UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

FORM 10-K

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

For the fiscal year ended December 31, ~~2008~~2009

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

Commission File Number 000-51219

PDC 2004-B Limited Partnership

(Exact name of registrant as specified in its charter)

West Virginia	20-0547318
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

1775 Sherman Street, Suite 3000, Denver, Colorado 80203

(Address of principal executive offices) (Zip code)

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

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

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

Title of Each Class

Limited Partnership Interests

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

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 x

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 ox No x ¨

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 (§ 229.405 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 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. x

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 x

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

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 ~~September~~ 30December 31, 2009, the Partnership had 899.94 units of limited partnership interest and no units of additional general partnership interest outstanding.

PDC 2004-B LIMITED PARTNERSHIP

INDEX TO REPORT ON FORM 10-K

		Page
	PART I
	Explanatory Note	1
	Special Note Regarding Forward Looking Statements	1
Item 1	Business	2
Item 1A	Risk Factors	1314
Item 1B	Unresolved Staff Comments	2114
Item 2	Properties	2114
Item 3	Legal Proceedings	2214
Item 4	~~Submission of Matters to a Vote of Security Holders~~[Reserved]	2314
	PART II
Item 5	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	2315
Item 6	Selected Financial Data	2416
Item 7	Management’s Discussion and Analysis of Financial Condition and Results of Operations	2416
Item 7A	Quantitative and Qualitative Disclosures About Market Risk	3826
Item 8	Financial Statements and Supplementary Data	4026
Item 9	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	4027
Item 9A(T)	Controls and Procedures	4027
Item 9B	Other Information	4328
	PART III
Item 10	Directors, Executive Officers and Corporate Governance	4428
Item 11	Executive Compensation	4733
Item 12	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	4833
Item 13	Certain Relationships and Related Transactions, and Director Independence	4833
Item 14	Principal Accountant Fees and Services	4935
	PART IV
Item 15	Exhibits, Financial Statement Schedules	4936
Signatures		5137
Financial Statements		F-1

Index

PART I

Explanatory Note to Comprehensive Annual Report

PDC 2004-B Limited Partnership (the “Partnership” or the “Registrant”), which was formed and funded on July 28, 2004 and, filed a Comprehensive Annual Report on Form 10-K for the years ended December 31, 2007, 2006 and 2005 on August 5, 2009. The report included condensed quarterly unaudited financial statements for each of the applicable quarters in 2007, 2006 and 2005.

This Comprehensive Annual Report on Form 10-K for the years ended December 31, 2008 and 2007 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, 2008 and 2007 as well as unaudited condensed financial information for each applicable interim period in 2008 and 2007.

Special Note Regarding Forward Looking Statements

This Annual Report contains “forward-looking” statements within the meaning of Section 27A of the Securities Act of 1933 (the “Securities Act”) and Section 21E of the Securities Exchange Act of 1934 (the “Exchange Act”) regarding PDC 2004-B Limited Partnership’s (the “Partnership’s” or the “Registrant’s”) business, financial condition, and results of operations. All ~~and~~statements ~~prospects~~other ~~that~~than ~~are~~statements ~~subject~~of ~~to risks~~historical facts included in and ~~uncertainties~~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 ~~oil and~~ natural gas and oil production and reserves, drilling plans, future cash flows, anticipated liquidity, anticipated capital expenditures and the Managing General Partner’s ~~Petroleum Development Corporation’s (“MGP’s” or “~~PDC’s”) strategies, plans and objectives. However, these are not the exclusive means of identifying forward-looking statements herein. Although forward-looking statements contained in this report reflect the Managing General Partner's good faith judgment, such statements can only be based on facts and factors currently known to ~~them~~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:

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

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

future production and development costs;

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 (“U.S.”) ~~and the impact of the global economy~~;

the effect of natural gas and oil derivatives activities;

· ~~availability and cost of capital and~~ conditions in the capital markets; and

· losses possible from pending ~~and/~~or future litigation ~~and the costs incident thereto~~.

Further, the Partnership urges the reader to carefully review and consider the cautionary statements made in this report, ~~including the risks~~ and ~~uncertainties that may affect~~ the Partnership'’s ~~business as described herein under Item 1A, Risk Factors and its~~ other filings with the SEC and public disclosures. Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date of this report. The Partnership ~~cautions you not to place undue reliance on forward-looking statements, which speak only as of the date of this report. The Partnership~~ undertakes no obligation to update any forward-looking statements in order to reflect any event or circumstance occurring after the date of this report or currently unknown facts or conditions or the occurrence of unanticipated events.

- 1 -

Index

Item 1. Business

General Information

The Partnership ~~was~~is ~~organized as~~ a ~~limited~~publically ~~partnership~~subscribed ~~on July 28, 2004 under the~~ West Virginia ~~Uniform~~ Limited Partnership ~~Act. Petroleum~~which ~~Development Corporation,~~owns aan ~~Nevada~~undivided ~~Corporation,~~working isinterest ~~the~~in ~~Managing~~natural ~~General~~gas ~~Partner~~and ofoil ~~the Partnership~~wells ~~(hereafter,~~located ~~the~~in ~~“Managing~~Colorado ~~General~~from ~~Partner”,~~which ~~“MGP”~~the ~~or “PDC”). Upon~~Partnership ~~completion~~produces ofand ~~its~~sells ~~public~~natural ~~sale~~gas ofand ~~its~~oil. ~~Partnership~~The ~~units on July 28, 2004, the~~ Partnership was ~~funded~~organized and ~~commenced~~began ~~its business~~ operations. ~~The~~in ~~Partnership~~2004 ~~was funded~~ with ~~initial~~cash ~~contributions~~contributed ofby ~~$18.0 million from 670~~ limited and additional general partners (collectively, the “Investor Partners”), ~~and~~who aown ~~cash~~80% ~~contribution~~ of ~~$4.0 million from~~ the ~~Managing General~~Partnership’s ~~Partner~~capital, ~~for~~or ~~its~~equity ~~interest. After~~interests, ~~payment~~and ofPDC, ~~syndication~~Managing ~~costs of~~General ~~$1.8~~Partner, ~~million and~~ a ~~one-time~~Nevada ~~management~~Corporation, ~~fee~~who toowns the ~~Managing~~remaining ~~General~~20% ~~Partner~~ of ~~$0.3~~ ~~million,~~ the Partnership’s ~~had~~capital, ~~available~~or ~~cash~~equity ~~of $19~~interest.9 ~~million to commence Partnership activities.~~ Upon funding, the Partnership entered into a Drilling and Operating Agreement (“D&O Agreement”) with the Managing General Partner ~~which~~that governs the drilling and operational aspects of the Partnership. The Partnership ~~owns~~utilized ansubstantially ~~undivided~~all ~~working~~of ~~interest~~the ~~in natural~~capital ~~gas~~raised ~~and oil wells located~~ in ~~Colorado~~the ~~from~~offering ~~which~~for the ~~Partnership produces~~initial drilling and ~~sells~~completion ~~natural~~of ~~gas~~the ~~and~~Partnership’s ~~oil~~wells.

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. A limited partner’s obligation to the Partnership under West Virginia law is limited to his or her capital contribution.

The following table presents Partnership formation and organizational information through the completion of the drilling phase on February 8, 2005:

				Number of Partner Units
PDC 2004-B Limited Partnership Information	Date	Number of Partners		Additional General Partner Units			Limited Partner Units		Equity Percentage			Amount (millions)

West Virginia Limited Partnership Formation	July 28, 2004
Limited Partnership Termination Date	December 31, 2055

Public Sale of Securities and Funding	July 28, 2004
Investor Partners (1) Unit Cost: $20,000			670		895.17			4.77		80.00	%	$	18.0
PDC, Managing General Partner										20.00	%		4.0
Total funding													22.0
Syndication costs paid to third-party brokers													(1.8	)
Management Fee Paid to PDC													(0.3	)
Net funding available for drilling activities										100.00	%	$	19.9

Conversion of additional General Partners to Limited Partners	February 8, 2005				(895.17	)		895.17
Limited Partnership Units after Conversion					-			899.94

(1)The Managing General Partner repurchases Investor Partner units under certain circumstances provided by the Agreement, upon request of an individual investor partner. For more information about the Managing General Partner’s limited partner unit repurchase program as well as the current number of Investor Partners as of the date of filing, see Item 5, Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities. For information concerning the Managing General Partner’s ownership interests in the Partnership as of the date of filing, see Item 12, Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.

The Partnership expects continuing operations of its oil and natural gas properties until such time that a well is depleted or becomes uneconomical to produce, at which time that well will be plugged and abandoned. The Partnership’s maximum term of existence extends through December 31, 2055, unless dissolved by certain conditions stipulated within the Agreement which are unlikely to occur at this time, or by written consent of the Investor Partners owning a majority of outstanding units at that time.

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

~~Drilling Activities~~Business Strategy

The ~~Partnership~~ ~~commenced~~primary ~~drilling~~objective ~~activities immediately following funding on July 28, 2004. Drilling operations were completed in March 2005 when the last~~ of the Partnership’s 23is ~~development~~the ~~wells~~profitable ~~were~~operation ~~connected~~of todeveloped ~~sales~~Colorado oil and ~~gathering~~ ~~pipeline. The~~natural ~~Partnership’s~~gas 23properties ~~gross~~and ~~wells represent 20.9 net wells, or~~ the ~~number~~appropriate allocation of ~~gross~~cash ~~wells~~proceeds, ~~multiplied~~costs byand ~~the~~tax ~~working~~benefits, ~~interest~~based ~~in the~~on ~~wells owned by~~ the ~~Partnership. All~~terms of the ~~drilled~~Agreement, ~~wells~~among ~~are located~~Partnership ~~in Colorado and all wells drilled are completed and producing as of December 31, 2008~~investors. The Partnership’s ~~wells~~operates ~~are~~in ~~considered developmental~~one ~~wells.~~business ~~Therefore~~segment, nooil ~~exploratory~~and ~~drilling~~natural ~~activity~~gas ~~was conducted on behalf of the Partnership~~sales.

The 23 wells discussed above are the only wells to be drilled by the Partnership since all of the funds raised in the Partnership offering have been utilized. Accordingly, the Partnership’s business plan going forward is to produce and sell the oil and gas from the Partnership’s wells, and to make distributions to the partners as outlined in the Partnership’s cash distribution policy, discussed in Item 5, Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.

In accordance with the D&O Agreement, the Partnership paid its proportionate share of the cost of drilling and completing each well as follows:

a) The cost of the prospect; and

b) The intangible well costs for each well completed and placed in production, an amount equal to the depth of the well in feet at its deepest penetration as recorded by the drilling contractor multiplied by the “intangible drilling and completion cost” in the D&O Agreement, plus the actual extra completion cost of zones completed in excess of the cost of the first zone and actual additional costs incurred in the event that an intermediate or third string of surface casing is run, rig mobilization and trucking costs, the additional cost for directional drilling and drill stem testing, sidetracking, fishing of drilling tools; and

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

Business Segments

The Partnership operates in one business segment, oil and natural gas sales.

- 2 -

Index

~~Plan of Operations~~Development

~~With regard~~The ~~to the~~ Partnership’s ~~developmental~~Denver-Julesburg (“DJ”) Basin wells ~~drilled~~are situated in ~~Colorado~~the Wattenberg Field, located north and east of Denver. The Codell formation, from which natural gas and oil is produced, is the primary producing zone for most of the Partnership’s 16 wells ~~were~~ ~~drilled~~developed in the Wattenberg Field. The ~~and~~Partnership’s ~~seven~~Piceance Basin wells ~~were~~are ~~drilled~~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 seven Grand Valley Field wells. The typical well production profile for wells in both the Wattenberg and Grand Valley fields displays an initial high production rate and relatively rapid decline, followed by years of relatively shallow decline.

~~The~~Well ~~16 Partnership~~recompletions ~~wells~~ in the Codell formation of Wattenberg Field ~~were~~wells, ~~targeted~~which may provide for additional reserve development and production, generally occur five to ~~the~~ten ~~Codell~~years ~~formation or~~after ~~deeper~~initial well drilling so that well resources are optimally utilized. ~~The~~These ~~Wattenberg~~well ~~Field,~~recompletions ~~located~~would ~~north~~be ~~and~~expected ~~east~~to ofoccur ~~Denver, Colorado,~~based ison ~~located~~a ~~within~~favorable ~~the~~general ~~Denver-Julesburg~~economic ~~(DJ)~~environment ~~Basin~~and commodity price structure. ~~Wells~~The in Managing General Partner has the DJauthority ~~area~~to ~~may~~determine ~~include~~whether asto ~~many~~recomplete asthe ~~four~~individual ~~productive~~wells ~~formations~~and to determine the timing of any recompletions. ~~From shallowest~~The timing of the recompletions can be affected by the desire to ~~deepest,~~optimize ~~these~~the ~~are~~economic return by recompleting the ~~Sussex,~~wells when commodity prices are at levels to obtain the ~~Niobrara,~~highest rate of return to the ~~Codell~~Partnership. The number and ~~the~~timing ~~J Sand~~of these recompletions will be subject to Partnership’s cash availability since borrowing is not permitted. The ~~primary~~Managing ~~producing~~General ~~zone~~Partner ~~for~~may ~~most~~retain ofPartnership distributable cash flow, if needed, to fully develop the Partnership’'s wells is; but if full development of the ~~Codell~~Partnership's ~~formation~~wells proves commercially unsuccessful, ~~which~~an ~~produces~~individual ainvestor ~~combination~~partner ofmight ~~natural~~anticipate ~~gas~~a ~~and oil~~reduction in cash distributions.

~~The~~A ~~seven Partnership~~recompletion ~~wells~~consists of a second fracture treatment in the ~~Grand~~same ~~Valley~~formation ~~Field~~originally ~~are~~fractured ~~targeted~~in to the ~~Mesa~~initial ~~Verde formation~~completion. PDC ~~The~~and ~~Grand~~other ~~Valley~~producers ~~Field~~have isfound inthat the ~~Piceance~~recompletions ~~Basin,~~generally ~~located~~increase ~~near~~ the ~~western~~ ~~border~~production rate and recoverable reserves of ~~Colorado~~the wells. ~~The~~On ~~producing~~average, ~~interval~~the ~~consists~~production ofresulting ~~a total~~from ofPDC's ~~150~~Codell torecompletions ~~300~~has ~~feet~~been ofabove ~~productive~~the ~~sandstone~~modeled ~~divided~~economics; ~~into~~however, 10all torecompletions 15have ~~different zones~~not been economically successful and future recompletions may not be economically successful. The ~~production~~cost ~~zones~~of ~~are~~recompleting ~~separated~~a bywell ~~layers~~producing from the Codell formation is generally one third of ~~nonproductive shale~~the ~~resulting~~cost inof a ~~total~~new ~~production~~well. If ~~interval~~the ofrecompletion 2work is performed,~~000~~ toPDC 4will charge the Partnership for the direct costs of recompletions,~~000~~ ~~feet~~and ~~with alternating~~the ~~producing~~Investor Partners and ~~non-producing~~the ~~zones. The~~Managing ~~natural~~General ~~gas reserves~~Partner ~~and~~will ~~production~~each ~~are~~pay ~~divided~~their ~~into~~proportionate ~~these~~share ~~numerous~~of ~~smaller zones~~costs based on the operating costs sharing ratios of the Partnership from funds retained by the Managing General Partner from distributable cash flows.

The ~~typical~~ ~~well~~Managing ~~production~~General ~~profile~~Partner ~~for~~has ~~wells~~developed ina ~~both~~plan ~~the~~to ~~Wattenberg~~initiate ~~and~~recompletion ~~Grand Valley~~activities ~~fields~~during ~~displays~~2010. This anplan ~~initial~~includes ~~high~~notifying ~~production~~investor ~~rate~~partners ~~and~~that ~~relatively~~funds ~~rapid decline,~~to ~~followed~~begin bythese ~~years~~recompletions will be withheld from future distributable cash flows of ~~relatively~~the ~~shallow~~Partnership ~~decline~~resulting from both current production and any increased production due to recompletion activities. ~~Natural~~Both ~~gas is~~ the ~~primary~~number ~~hydrocarbon~~of ~~produced;~~recompletions ~~however,~~and the ~~majority~~timing of ~~the~~recompletions ~~wells~~will inbe based on the ~~Wattenberg~~ ~~Field~~availability ~~also~~of ~~produce~~cash ~~oil~~withheld from distributions. ~~For~~The Managing General Partner believes that, based on projected recompletion costs and projected cash withholding, all partnership recompletions can be completed. As the ~~natural~~optimal ~~gas~~period approaches, the ~~purchase price~~Managing ~~may~~General ~~include~~Partner ~~revenue~~will ~~from~~re-evaluate the ~~recovery~~feasibility of ~~propane~~commencing ~~and~~those ~~butane~~recompletions inbased ~~the~~on ~~gas stream,~~engineering asdata ~~well~~and as a ~~premium~~favorable ~~for~~commodity ~~the~~price ~~typical~~environment ~~high-energy~~in ~~content~~order to maximize the financial benefit of the ~~natural gas~~recompletion.

~~Generally, PDC~~Drilling plans recompletion, as described below, of the wells producing from the Codell formation in the Wattenberg Field wells after they have been in production for five years or more, although the exact timing may be delayed or accelerated due to changing commodity prices and ~~the~~Other ~~availability~~Development of additional geological data and technology. The Managing General Partner has the authority whether to recomplete the individual wells and to determine the timing of any recompletions. The timing of the recompletions could be affected by the desire to optimize the return to the Partnership by recompleting the wells, when commodity prices are at levels to obtain the highest rate of return. The number and timing of these recompletions will be subject to Partnership’s cash availability since borrowing is not permitted. A recompletion consists of a second fracture treatment in the same formation originally fractured in the initial completion in well bore. PDC and other producers have found that the recompletions generally increase the production rate and recoverable reserves of the wells. However, all recompletions have not and may not result in economically recoverable reserves. The cost of recompleting a well producing from the Codell formation is about one third of the cost of a new well. If the recompletion work is performed, PDC will charge the Partnership for the direct costs of recompletions, and the Partnership will pay the Partnership’s proportionate share of costs based on the operating costs sharing ratios of the Partnership out of Partnership revenues earned from oil and gas sales. Based on the current economic environment, the Managing General Partner has no immediate plans to initiate recompletion activities in the Codell formation of the Wattenberg Field wells. The Partnership intends to re-evaluate the feasibility of commencing these recompletion activities as current economic conditions improve.Activities

~~Title~~The to Partnership’s properties (the “Properties”) consist of a working interest for the well bore in each well drilled by the Partnership. The Partnership drilled 23 productive development wells (20.9 net – the number of gross wells multiplied by the working interest in the wells owned by the Partnership) during drilling operations that began immediately after funding and concluded in March 2005 when all of the Partnership’s wells were connected to sales and gathering lines. No exploratory drilling activity was conducted on behalf of the Partnership. The 23 wells discussed above are the only wells to be drilled by the Partnership since all of the funds raised in the Partnership offering have been utilized. In accordance with the D&O Agreement, the Partnership paid its proportionate share of the cost of drilling and completing each well as follows:

· The ~~Partnership~~ ~~holds~~leasehold ~~record~~cost ~~title in its name to the working interest in each well. PDC provides an assignment~~ of ~~working interest for~~ the well bore, prior to the spudding of the well and effective the date of the spudding of the well, to the Partnership in accordance with the D&O Agreement. Upon completion of the drilling of all of the Partnership wells, these assignments are recorded in the applicable county. Investor Partners rely on PDC to use its best judgment to obtain appropriate title to these working interests. Provisions of the Limited Partnership Agreement (the “Agreement”), generally relieve PDC from errors in judgment with respect to the waiver of title defects. PDC takes those steps it deems necessary to assure that title to the working interests is acceptable for purposes of the Partnership. For additional information, see Item 2, Properties – Title to Properties.prospect;

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

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

- 3 -

Index

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

~~General.~~Title Asto operator, PDC represents the Partnership in all operating matters, including the drilling, testing, completion, recompletion and equipping of wells and the marketing and sale of the Partnership’s oil and natural gas production from the wells. PDC is the operator of all of the wells in which the Partnership owns an interest.Properties

~~PDC,~~The ~~may~~ Partnership's leases are direct interests in ~~certain~~producing ~~circumstances,~~acreage. In ~~provide~~accordance ~~equipment~~with ~~and~~the ~~supplies~~D&O Agreement, ~~and~~the ~~perform~~Managing ~~salt~~General ~~water disposal~~Partner ~~services~~exercised due care and ~~other~~judgment, ~~services~~which included curative work for ~~the~~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. ~~PDC~~The ~~sold equipment~~Partnership believes it holds good and defensible title to ~~the~~its ~~Partnership~~developed asproperties, ~~needed~~in accordance with standards generally accepted in the ~~drilling~~industry, orthrough ~~completion~~the record title held in the Partnership’s name, of each Partnership ~~wells~~well’s working interest. ~~All~~The ~~equipment~~Partnership’s properties are subject to royalty, overriding royalty and ~~services~~other ~~were~~outstanding ~~sold~~interests atcustomary to the ~~lesser of~~industry. ~~cost~~The Managing General Partner does not believe that any additional burdens, liens or ~~competitive~~encumbrances ~~prices~~customary to the industry, if any, will materially interfere with the commercial use of the properties. Provisions of the Agreement generally relieve PDC from any error in judgment with respect to the ~~area~~waiver of ~~operations~~title defects.

Natural Gas ~~Pipeline~~ and ~~Transmission. The~~ ~~transmission and~~Oil gathering lines, which are owned either by PDC or other third parties and which transport the Partnership's natural gas production, are subject to seasonal curtailment and occasional limitations due to repairs, improvements or as a result of priority transportation agreements with other natural gas transporters. Seasonal curtailment typically occurs during July and August as a result of high atmospheric temperatures which reduce compressor capacity. 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. When a significant amount of development work is being done in an area, production can temporarily exceed the available markets and pipeline capacity to move natural gas to more distant markets. This excess supply can lead to lower natural gas prices relative to other areas as the producers compete for the available markets by reducing prices. This excess supply can also lead to curtailments of production and periods when wells are shut-in due to lack of market.Reserves

~~Sale~~The ofPartnership’s ~~Production~~gas and oil reserves are located in the United States. InThe ~~accordance~~ Partnership’s reserve estimates are prepared with respect to reserve categorization, using the ~~D&O~~definitions ~~Agreement~~for proved reserves set forth in SEC Regulation S-X, ~~PDC~~Rule ~~markets~~4-10(a) ~~the~~and ~~oil~~subsequent SEC staff regulations interpretations and ~~natural~~guidance. The ~~gas~~Managing ~~produced~~General ~~from~~ Partner has a comprehensive process that governs the determination and reporting of the Partnership’s ~~wells~~proved onreserves. As apart ~~competitive~~of ~~basis,~~the atManaging ~~what~~General itPartner’s ~~believes~~internal tocontrol beprocess, the ~~best~~ ~~available~~Partnership’s ~~terms~~reserves ~~and~~are ~~prices~~reviewed ~~generally~~annually by an internal team composed of reservoir engineers, ~~under~~geologists ~~contracts~~and ~~with~~accounting ~~indexed~~personnel ~~monthly pricing~~for ~~provisions. PDC~~adherence ~~does~~to ~~not~~SEC ~~enter~~guidelines ~~into~~through ~~any~~a ~~commitment~~detailed ofreview ~~future production~~land ~~that~~records, ~~does~~available ~~not~~geological ~~directly~~and ~~benefit~~reservoir ~~the~~data ~~Partnership~~as well as production performance data. ~~Generally~~The review includes, ~~purchase~~ ~~contracts~~but ~~for~~is ~~the~~not ~~sale~~limited ofto, ~~oil~~confirmation ~~are~~that ~~cancelable~~reserve onestimates 30(1) ~~days~~include ~~notice,~~all ~~whereas purchase~~properties ~~contracts~~owned; ~~for~~(2) ~~the~~are ~~sale~~based ofon ~~natural~~proper ~~gas~~working ~~may~~and ~~range~~net ~~from~~revenue ~~spot~~interests; ~~market~~and ~~sales of~~(3) ~~short~~reflect ~~duration~~reasonable tocost ~~multi-year~~estimates ~~contracts~~and ~~requiring~~field ~~the~~performance. The ~~dedication~~internal ofteam compiles the ~~natural~~ ~~gas~~reviewed ~~produced~~data ~~from~~and aforwards ~~well~~the ~~for~~data ato ~~period~~an ~~ranging~~independent upconsulting tofirm ~~the~~engaged ~~life~~to ofestimate the ~~well~~ Partnership’s reserves.

The ~~gas is~~Partnership ~~sold~~utilized atthe ~~negotiated~~services ~~prices~~of ~~based~~an ~~upon~~independent apetroleum ~~number~~engineer, ofRyder ~~factors~~Scott Company, ~~including~~L.P. (Ryder Scott), to estimate the ~~quality~~ 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 ~~pressure~~test data, ~~estimated~~historical ~~remaining~~costs ~~reserves~~of operations and development, ~~prevailing supply~~product ~~conditions~~prices, ~~and~~or any ~~applicable~~agreements ~~price~~relating ~~regulations~~to ~~promulgated~~current byand ~~the Federal~~future ~~Energy~~operations ~~Regulatory~~of ~~Commission,~~properties orand ~~FERC~~sales of production. The independent petroleum engineer prepared an estimate of the Partnership’s ~~sells oil~~reserves ~~produced~~in byconjunction ~~its~~with ~~wells~~an toongoing ~~local~~review ~~oil~~by ~~purchasers~~the atManaging ~~spot~~General ~~prices~~Partner’s engineers. A ~~The~~final ~~produced oil~~comparison isof ~~stored~~data inwas ~~tanks~~performed atto orassure ~~near~~that the ~~location~~reserve ofestimates ~~the~~were ~~Partnership’~~complete and reasonable. The final independent petroleum engineer's ~~wells~~estimated ~~for routine~~reserve ~~pickup~~report was reviewed and approved by ~~oil~~the ~~transport~~Managing ~~trucks~~General Partner’s engineering staff and management.

~~In general,~~The professional qualifications of the Managing General Partner’s lead engineer primarily responsible for overseeing the preparation of the Partnership’s ~~has~~reserve ~~been~~estimate ~~and~~meets ~~expects~~the tostandards ~~continue~~of toReserves beEstimator ~~able~~as defined in the Standards Pertaining to ~~produce~~ the Estimating and ~~sell~~Auditing ~~oil~~of Oil and ~~natural~~Gas ~~gas~~Reserves ~~from~~Information as promulgated by the ~~Partnership’s~~Society ~~wells~~of ~~without~~Petroleum ~~significant curtailment~~Engineers. This ~~and~~Managing atGeneral ~~locally~~Partner ~~competitive~~employee ~~prices. The~~holds ~~Partnership~~a ~~does experience~~Bachelor ~~limited~~of ~~curtailments~~Science ~~from~~degree ~~time~~in toPetroleum ~~time~~and ~~due~~Natural toGas ~~pipeline~~Engineering ~~maintenance~~ and ~~operating~~has ~~issues~~over as25 ~~discussed~~years ~~above~~of experience in reservoir engineering. The ~~Partnership~~individual ~~experienced~~ is a ~~minor~~member ~~curtailment~~ of ~~production~~the inSociety ~~the~~of ~~Piceance~~Petroleum ~~Basin~~Engineers, ~~due~~allowing the individual to ~~limited compression~~remain ~~and~~current ~~pipeline~~with ~~capacity~~the ~~throughout~~developments ~~most~~and oftrends ~~fourth~~in ~~quarter 2008~~the industry. ~~This~~Further, ~~interruption~~during 2009, ~~due~~this individual attended ten hours of formalized training relating to ~~third~~the ~~party~~definitions ~~infrastructure,~~and ~~was corrected~~disclosure guidelines set forth in ~~early~~the SEC's final rule released in January 2009, Modernization of Oil and Gas Reporting.

Price +Risk Management. Price volatility is a very significant and a potential destabilizing factor in the oil and natural gas production industry. To help manage the risks associated with the oil and natural gas industry, the Partnership proactively employs strategies to reduce the effects of commodity price volatility on cash flows by utilizing commodity based derivative instruments to manage a portion of the exposure to price volatility. These instruments consist of Colorado Interstate Gas Index, or CIG, based contracts for Colorado natural gas production, basis protection swaps and New York Mercantile Exchange, or NYMEX, based contracts for Colorado oil production, and natural gas production. The contracts provide price protection for committed and anticipated oil and natural gas sales. The Partnership's policies prohibit the use of oil and natural gas futures, swaps, basis protection swaps or options for speculative purposes and permit utilization of derivatives only if there is an underlying physical position. While the Partnership’s derivative instruments are utilized to manage the impact of price volatility of its oil and natural gas production, the Partnership has elected not to prepare the documentation required to designate any of the Partnership’s derivative instruments as hedges under the terms of Statement of Financial Accounting Standards (“SFAS”) No. 133, Accounting for Derivative Instruments and Certain Hedging Activities. Thus, the Partnership is required to recognize changes in the fair value of its derivative positions in Partnership earnings each reporting period thereby resulting in the potential for significant earnings volatility. Along with realized gains or losses, these changes in fair value are classified as “Oil and gas price risk management, net” on the statements of operations. See Note 2, Summary of Significant Accounting Policies−Derivative Financial Instruments, to the Partnership’s accompanying financial statements included in this report.

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Index

~~The~~Proved ~~sale of~~reserves ~~the~~are ~~Partnership’s~~those ~~production~~quantities isof ~~subject~~oil toand ~~market price fluctuations for~~ natural gas, ~~sold~~which, inby ~~the~~analysis ~~spot~~of ~~market~~geoscience and ~~under~~engineering ~~market index contracts. PDC~~data, ascan ~~Managing~~be ~~General~~estimated ~~Partner,~~with ~~continues~~reasonable certainty to ~~evaluate the~~be ~~potential~~economically ~~for~~producible ~~reducing~~from ~~these~~a ~~risks~~given bydate ~~entering~~forward, ~~into~~from ~~derivative transactions. The~~known ~~Managing~~reservoirs, ~~General~~and ~~Partner~~under ~~may~~existing ~~close~~conditions, ~~out~~operating ~~any~~methods, ~~portion of~~and ~~derivatives~~government ~~that~~regulations. These ~~may~~reserve ~~exist~~quantities ~~from~~should ~~time~~be toproducible ~~time~~prior ~~which~~to ~~may~~the ~~result~~operating incontract aterm’s ~~realized gain~~expiration ordate, ~~loss~~unless onevidence indicates that ~~derivative~~renewal ~~transaction. The~~is ~~Partnership~~reasonably ~~manages price~~certain, ~~risk~~regardless onof ~~only~~whether adeterministic ~~portion~~or ofprobabilistic ~~its~~methods ~~anticipated~~are ~~production,~~used sofor the ~~remaining portion~~estimation. Estimates of ~~its~~proved ~~production~~reserves ismay ~~subject~~change, toeither ~~the~~positively ~~full~~or ~~fluctuation~~negatively, ofas ~~market pricing. As~~additional ofinformation ~~June~~becomes ~~30,~~available ~~2009~~and as contractual, ~~the~~economic and political conditions change. The Partnership’s ~~has~~net ~~oil~~proved ~~and~~reserve ~~natural~~estimates ~~gas derivatives~~have inbeen ~~place~~adjusted ~~covering~~as ~~71%~~necessary ofto ~~its~~reflect ~~expected~~all ~~oil~~contractual ~~production~~agreements, ~~and~~royalty ~~79%~~obligations ofand ~~its expected~~interests ~~natural~~owned ~~gas~~by ~~production~~others ~~for~~at the ~~remainder~~time of ~~2009~~the estimate. The Partnership’s two categories of proved reserves, are as follows:

~~The Partnership~~· ~~utilizes~~Proved ~~financial~~developed ~~derivatives~~reserves toare ~~establish~~those ~~“floors,” “collars,” “fixed-price swaps” or “basis protection swaps” on the possible range of the prices realized for the sale of~~ natural gas and oil~~. These~~ ~~are recorded~~quantities onexpected ~~the~~to ~~balance~~be ~~sheet~~recovered atfrom ~~fair value with changes in fair values recognized~~ currently inproducing ~~the~~zones ~~statement of operations~~ under the ~~caption~~continuation ~~"Oil and gas price risk management, net." PDC, as Managing General Partner~~ of ~~the~~ ~~Partnership,~~present ~~enters~~operating ~~into derivative transactions on behalf of the Partnership in the same manner in which it enters into transactions for itself~~methods. “Floors” contain a floor price (put) whereby PDC, as Managing General Partner, receives the market price from the purchaser and the difference between the market price and floor price from the counterparty if the commodity market price falls below the floor strike price, but receives no payment when the commodity market price exceeds the floor price. For “swap” instruments, if the market 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 market price and the fixed contract price from the counterparty. If the market 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 market price and the fixed contract price to the counterparty. “Collars” contain a fixed floor price (put) and ceiling price (call). If the market 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 market price from the counterparty. If the market 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 market price to the counterparty. If the market price is between the call and put strike price, no payments are due to or from the counterparty. Finally, “basis protection swaps” are arrangements that guarantee a price differential for natural gas valued at a specified pricing point, or hub. For Partnership CIG basis protection swaps that have a negative pricing differential 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. See Item 1A, Risk Factors - The Partnership's derivative activities could result in reduced future revenue and cash flows compared to the level the Partnership might experience if no derivative instruments were in place.

~~The Partnership~~· ~~participates~~Proved onundeveloped areserves, ~~pro-rata~~or ~~basis~~PUDs, inare ~~all~~those ~~derivative~~reserves ~~transactions entered~~expected ~~into by the Managing General Partner in a given area. The Partnership’s allocation of derivative positions is based on the Partnership’s percentage of estimated production~~ to ~~total~~be ~~estimated~~recovered ~~production~~ from aexisting ~~given area~~wells onwhere a ~~monthly~~relatively ~~basis. The~~major ~~transactions~~expenditure ~~are~~is onrequired ~~a production month basis. Therefore, the Partnership may participate in a derivative~~ for a ~~future period before it has production from that area~~recompletion. Prior to September 30, 2008, as estimated future production volumes increased due to continued drilling and wells placed into production, the allocation of derivative positions between PDC’s corporate interests and this Partnership, changed on a pro-rata basis. As of September 30, 2008, the allocation of derivative positions was fixed, based on the estimated future production at this date, between the Managing General Partner’s corporate interests and each sponsored drilling partnership. For positions entered into subsequent to September 30, 2008, specific designations of the quantities between the Managing General Partner’s corporate interests and each sponsored drilling partnership, including this Partnership, are allocated and fixed at the time the positions are entered into based on estimated future production. The Partnership believes that in a rapidly changing price environment, derivative positions are desirable to obtain more predictable cash flows and to reduce the impact of possible future price declines.

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

	As of December 31, 2009
	Oil (MBbl)		Natural Gas (MMcf)		Natural Gas Equivalent (MMcfe)		Percent
Proved developed
Piceance Basin: Grand Valley Field		6		3,291		3,327		88	%
Denver-Julesburg (DJ) Basin: Wattenberg Field		44		177		441		12	%
Total proved developed		50		3,468		3,768		100	%

Proved undeveloped
Piceance Basin: Grand Valley Field		-		-		-		0	%
Denver-Julesburg (DJ) Basin: Wattenberg Field		139		592		1,426		100	%
Total proved undeveloped		139		592		1,426		100	%

Proved reserves
Piceance Basin: Grand Valley Field		6		3,291		3,327		64	%
Denver-Julesburg (DJ) Basin: Wattenberg Field		183		769		1,867		36	%
Total proved reserves		189		4,060		5,194		100	%

In 2009, the SEC published its final rule regarding the modernization of oil and gas reporting, which changed the valuation price of in-ground natural gas and oil resources, used to determine economically producible natural gas and oil reserve quantities, from a year-end single-day pricing method to a method which applies the 12-month average of the first-day-of-the-month price during each month of 2009. An economically producible quantity is one where the revenue provided by its sale is reasonably likely to exceed the cost to deliver that quantity to market.

Operations

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

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

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Index

~~D&O Agreement.~~ The Partnership’s ~~has~~operations ~~entered~~are ~~into~~concentrated in the ~~D&O Agreement~~Rocky ~~with~~Mountain ~~PDC. The~~Region ~~D&O~~where ~~Agreement~~winter ~~provides~~weather ~~that~~conditions ~~the~~and ~~operator conducts~~time ~~and~~periods ~~directs~~reserved ~~drilling~~by ~~operations,~~leasehold ~~including~~restrictions ~~well~~designed ~~recompletions,~~to protect wildlife habitat can exist and ~~has full~~limit ~~control~~operational ofcapabilities ~~all~~for ~~operations~~as onlong ~~the~~as ~~Partnership's~~six ~~wells~~months. ~~Generally, an~~These ~~operator~~factors ~~has~~may ~~limited~~adversely ~~liability~~affect tosome ~~the~~ Partnership ~~for~~production ~~losses~~operations. ~~sustained~~In ~~or liabilities~~addition ~~incurred~~to cold weather, ~~except~~operational constraint challenges such as ~~may~~surface ~~result~~equipment ~~from~~freezing ~~the~~can ~~operator's~~limit ~~negligence~~production ~~or misconduct~~volumes. ~~Under~~Increased ~~the~~competition ~~terms~~and ofhigher ~~the~~costs ~~D&O~~during ~~Agreement~~milder weather and habitat protection periods for oil field equipment, ~~PDC~~services, ~~may subcontract~~supplies ~~certain~~and ~~functions~~qualified aspersonnel ~~operator~~can ~~for~~adversely ~~Partnership~~affect ~~wells. PDC retains~~profitability ~~responsibility~~and ~~for~~cash ~~work~~distributions ~~performed~~to bythe ~~subcontractors~~Investor Partners.

ToThe ~~the extent~~following ~~the~~table ~~Partnership~~presents ~~has less than a 100% working interest in a well,~~ the Partnership’s ~~paid~~productive ~~only~~wells ~~its~~by ~~proportionate share of total lease, development, and~~ operating ~~costs,~~field ~~and~~as ~~receives its proportionate share~~ of ~~production~~December ~~subject~~31, ~~only to royalties and overriding royalties~~2009. Productive ~~The~~wells ~~Partnership~~consist isof ~~responsible~~producing ~~only~~wells ~~for its obligations~~ and iswells ~~liable~~capable ~~only for its proportionate working interest share~~ of ~~the~~producing ~~costs~~oil ofand ~~developing~~natural ~~and~~gas ~~operating~~in ~~the~~commercial ~~wells~~quantities.

Under the D&O Agreement, the operator may provide 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 are based on competitive industry rates, which vary based upon the area 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.

	Producing Wells
	Gas
Location	Gross		Net
State of Colorado
Piceance Basin: Grand Valley Field		7.0		6.2
Denver-Julesburg (DJ) Basin: Wattenberg Field		16.0		14.7
Total Colorado		23.0		20.9

Total Productive Wells		23.0		20.9

~~Under~~The ~~the D&O Agreement the~~ Partnership’s ~~has~~operating ~~the~~areas ~~right~~are toprofiled ~~take in kind and separately dispose of its share of all oil and natural gas produced from its wells. In accordance with the D&O Agreement, the Partnership designated PDC~~ as its agent to market its production and authorized the operator to enter into and bind the Partnership in those agreements as it deems in the best interest of the Partnership for the sale of its oil and/or natural gas. Where pipelines owned by PDC are used in the delivery of natural gas to market, PDC charges a market rate gathering fee not to exceed that which would be charged by a non-affiliated third party for a similar service.follows:

~~The D&O~~DJ ~~Agreement~~Basin, ~~remains~~Wattenberg inField, ~~force~~Weld asCounty, ~~long~~Colorado. Located asnorth ~~any~~and ~~well~~east orof ~~wells~~Denver, ~~produce~~Colorado, orthe ~~are capable~~Partnership’s ofwells ~~economic~~in this field have exhibited production, ~~and~~histories typical for wells located in this field with an ~~additional~~initial ~~period~~high ofproduction ~~180~~rate ~~days~~and ~~from cessation~~relatively rapid decline, followed by years of ~~all~~relatively ~~production~~shallow decline. Although natural gas is the primary hydrocarbon produced, ormany ~~until~~wells ~~PDC~~also produce oil. Development wells in this area are generally 7,000 to 8,000 feet in depth and their primary producing zone is ~~replaced~~the asCodell ~~Managing~~formation ~~General Partner~~with assome ~~provided~~wells ~~for~~also completed in the ~~D&O~~shallower ~~Agreement~~Niobrara formation. Well spacing ranges from 20 to 40 acres per well.

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

~~When~~ Sale of Production. In accordance with the D&O Agreement, PDC markets the natural gas produced from the Partnership’s wells ~~are~~primarily ~~"complete"~~to ~~(i.e.,~~commercial ~~drilled~~end users, ~~fractured~~interstate or ~~stimulated~~intrastate pipelines or local utilities on a competitive basis, under the available terms and ~~all~~ ~~surface~~prices, ~~production~~generally ~~equipment~~under contracts with indexed monthly pricing provisions. The Managing General Partner believes these contract pricing provisions are customary for the industry. The sales price for natural gas may include revenue from the recovery of propane and ~~pipeline~~butane ~~facilities~~in ~~necessary~~the gas stream, as well as a premium for the typical high-energy content of the natural gas. The Partnership’s Wattenberg Field, and to ~~produce~~ a lesser extent the ~~well~~Grand ~~are~~Valley ~~installed)~~Field, ~~production~~wells ~~operations~~also ~~commence~~produce onoil ~~each well~~in addition to natural gas. ~~All~~The Managing General Partner is currently able to sell, at or near the Partnership’s wells, ~~are~~all ~~complete,~~of ~~and~~the Partnership’s oil production ~~operations are~~under ~~currently~~a ~~being~~purchase ~~conducted~~contract with ~~regard~~a toregional ~~each~~petroleum refiner containing monthly pricing provisions. The Partnership does not refine any of ~~the~~its 23oil ~~productive wells~~production.

PDC markets the Partnership’s natural gas to commercial end users, interstate or intrastate pipelines or local utilities, primarily under market sensitive contracts in which the price of natural gas sold varies as a result of market forces. Some leases, and thus the natural gas derived from wells drilled on those leases, may have been dedicated to particular markets at the time the Partnership drilled wells on such leases, or subsequent to, as part of the natural gas marketing arrangements. In general, the Partnership has been, and expects to continue to be able to, produce and sell natural gas from Partnership wells without significant curtailment and at competitive prices. The Partnership does experience limited curtailments from time to time due to pipeline maintenance and operating issues of the pipeline operators. For instance, 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 corrected in early 2009.

The majority of the Partnership’s wells in the Wattenberg Field in Colorado produce oil in addition to natural gas. The Managing General Partner is currently able to sell all the oil that the Partnership 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 to purchasers at or near the Partnership’s wells under both short and long-term purchase contracts with monthly pricing provisions.

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Index

~~PDC,~~Oil ~~on behalf~~and ofGas ~~the Partnership~~Production, ~~may~~Unit ~~enter~~Prices ~~into~~and fixed price contracts, or utilize derivatives, including collars, swaps or basis protection swaps, in order to offset some or all of the price variability for particular periods of time. The use of derivatives may entail fees, including the time value of money for margin requirements, which are charged to the Partnership.Costs

~~Seasonal factors,~~The ~~such~~following astable ~~effects~~presents ofinformation ~~weather~~regarding ~~on prices received and costs incurred, and availability of pipeline capacity, may impact~~ the Partnership'’s ~~results of~~ operations~~. In~~ ~~addition,~~by ~~both sales volumes and prices are subject to demand factors with a seasonal component.~~field:

Revenues, Expenses and Distributions

	Year Ended December 31,
	2009		2008
Production (1)

Natural gas (Mcf)
Piceance Basin: Grand Valley Field		313,124		413,124
Denver-Julesberg (DJ) Basin: Wattenberg Field		26,386		32,894
Total Natural Gas		339,510		446,018

Oil (Bbls)
Piceance Basin: Grand Valley Field		987		327
Denver-Julesberg (DJ) Basin: Wattenberg Field		8,286		9,345
Total Oil		9,273		9,672

Natural gas equivalent (Mcfe)
Piceance Basin: Grand Valley Field		319,046		415,086
Denver-Julesberg (DJ) Basin: Wattenberg Field		76,102		88,964
Total natural gas equivalent		395,148		504,050

Natural Gas and Oil Sales

Natural gas sales
Piceance Basin: Grand Valley Field	$	809,001	$	2,632,654
Denver-Julesberg (DJ) Basin: Wattenberg Field		110,089		269,014
Total natural gas sales		919,090		2,901,668

Oil sales
Piceance Basin: Grand Valley Field	$	43,411	$	26,496
Denver-Julesberg (DJ) Basin: Wattenberg Field		450,263		835,718
Total oil sales		493,674		862,214

Natural gas and oil sales
Piceance Basin: Grand Valley Field	$	852,412	$	2,659,150
Denver-Julesberg (DJ) Basin: Wattenberg Field		560,352		1,104,732
Total natural gas and oil sales	$	1,412,764	$	3,763,882

Average Sales Price (excluding realized gain (loss) on derivatives)

Natural gas (per Mcf)
Piceance Basin: Grand Valley Field	$	2.58	$	6.37
Denver-Julesberg (DJ) Basin: Wattenberg Field		4.17		8.18
Average sales price natural gas, all fields		2.71		6.51

Oil (per Bbl)
Piceance Basin: Grand Valley Field	$	43.98	$	81.03
Denver-Julesberg (DJ) Basin: Wattenberg Field		54.34		89.43
Average sales price oil, all fields		53.24		89.15

Natural gas equivalent (per Mcfe)
Piceance Basin: Grand Valley Field	$	2.67	$	6.41
Denver-Julesberg (DJ) Basin: Wattenberg Field		7.36		12.42
Average sales price natural gas equivalents, all fields		3.58		7.47

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

Piceance Basin: Grand Valley Field	$	1.27	$	0.93
Denver-Julesberg (DJ) Basin: Wattenberg Field		2.07		1.90
Average production cost, all fields		1.43		1.10

~~The Partnership's~~(1) ~~share~~Production ofas ~~production~~shown ~~revenue~~in ~~from~~the atable ~~given well~~ is ~~burdened~~determined by ~~and/or~~ ~~subject~~multiplying tothe ~~royalties~~gross ~~and~~production ~~overriding~~volume ~~royalties,~~of ~~monthly~~properties ~~operating~~in ~~charges, taxes~~which ~~and~~the Partnership has an interest by the percentage of the leasehold or other ~~operating~~property ~~costs~~interest the Partnership owns.

It(2) ~~is PDC's~~Average ~~practice to deduct operating expenses from the~~ production ~~revenue~~unit ~~for~~costs ~~the corresponding~~presented ~~period~~exclude ~~and to defer~~ the ~~collection~~effects of ~~operating~~ad ~~expenses~~valorem ~~to future periods when revenues are insufficient to render full payment~~ and aseverance ~~liability is recorded by the Partnership~~taxes.

- 7 -

Index

~~Production,~~Definitions ~~Sales,~~used ~~Prices and~~throughout ~~Lifting~~Item ~~Costs~~1. Business:

The following table sets forth information regarding the Partnership’s production volumes, oil and natural gas sales, average sales price received and average lifting cost incurred for the periods indicated.

	Year Ended			Year Ended
	December 31, 2008			December 31, 2007
Production
Oil (Bbls)		9,672			12,961
Natural gas (Mcf)		446,018			463,307
Natural gas equivalent (Mcfe)		504,050			541,073
Oil and Gas Sales
Oil sales	$	862,214		$	752,295
Gas sales		2,901,668			2,267,215
Total oil and gas sales	$	3,763,882		$	3,019,510
Average Sales Price (excluding realized gain (loss) on derivatives)
Oil (per Bbl)	$	89.15		$	58.04
Natural gas (per Mcf)		6.51			4.89
Natural gas equivalent (per Mcfe)		7.47			5.58
Realized Gain (Loss) on Derivatives, net
Oil derivatives - realized loss	$	(45,042	)	$	(3,604	)
Natural gas derivatives - realized gain		115,356			175,512
Total realized gain on derivatives, net	$	70,314		$	171,908
Average Sales Price (including realized gain (loss) on derivatives)
Oil (per Bbl)	$	84.49		$	57.76
Natural gas (per Mcf)		6.76			5.27
Natural gas equivalent (per Mcfe)		7.61			5.90
Average Production Cost (Lifting Cost) (per Mcfe)	$	1.79		$	1.44

Definitions used throughout Item 1, Business:

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

MBbl – One thousand barrels

Mcf – One thousand cubic feet

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

MMcf – One million cubic feet

MMcfe – One million cubic feet of natural gas equivalents

~~Production as~~For ~~shown~~more ininformation concerning the ~~table~~Partnership’s is2009 ~~determined~~and by2008 ~~multiplying~~production ~~the~~volumes ~~gross~~and ~~production~~costs, ~~volume of~~which ~~properties~~include inseverance ~~which~~and ad valorem taxes as reflected in the Partnership’s ~~has~~statements anof ~~interest~~operations byaccompanying ~~the~~this ~~percentage~~report, see Item 7, Management’s Discussion and Analysis of ~~the leasehold~~Financial orCondition ~~other~~and ~~property~~Results ~~interest~~of ~~the~~Operations ~~Partnership~~in ~~owns~~this report.

Commodity Price Risk Management. The Partnership’s ~~utilizes~~production ~~commodity~~sold ~~based~~in ~~derivative~~the ~~instruments~~spot market and under market index contracts is subject to ~~manage~~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 ~~its~~the Partnership’s committed and anticipated oil and natural gas sales to achieve a more predictable cash flow and to reduce exposure to fluctuations in oil and natural gas commodity prices. Since the Partnership manages price ~~volatility~~risk on only a portion of its ~~natural~~future ~~gas~~estimated ~~and~~production, ~~oil sales~~future production not covered by derivatives is subject to the full fluctuation of market pricing. ~~Production~~The ~~costs~~Partnership's ~~represent~~policies ~~oil~~prohibit ~~and~~the ~~gas~~use ~~operating~~of ~~expenses which~~derivative ~~include~~financial ~~severance~~instruments for speculative purposes and adpermit ~~valorem~~utilization ~~taxes~~of asderivatives ~~reflected~~only inif there is an underlying physical position. For more information on the Partnership’s derivative financial ~~statements. See~~instruments, see Item 7, Management'’s Discussion and Analysis of Financial Condition and Results of Operations−Commodity –Price ~~Production~~Risk Management, Net and ~~Operating Costs~~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.

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Index

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

All ~~of the~~derivative ~~Partnership’s~~assets ~~natural gas~~ and ~~oil~~liabilities ~~reserves~~ are ~~located~~recorded inon the ~~United States. Ryder~~balance ~~Scott~~sheets ~~Company,~~at Lfair value.P. PDC, anas ~~independent~~Managing ~~engineer~~General ~~prepared the~~Partner, ~~reserve~~has ~~reports~~elected ~~for~~not ~~2008~~to ~~and~~formally ~~2007.~~designate ~~The~~any ~~independent~~of ~~engineer~~the Partnership’s ~~estimates~~derivative ~~are made~~instruments ~~using~~as ~~available~~hedging ~~geological~~instruments and ~~reservoir~~therefore, ~~data~~the asPartnership ~~well~~does asnot ~~production performance~~use ~~data~~hedge ~~including~~accounting. Accordingly, ~~data~~the ~~provided~~Partnership byis ~~the~~required ~~Managing~~to ~~General Partner. The~~recognize ~~estimates~~changes ~~are~~in ~~prepared~~the ~~with~~fair ~~respect~~value toof ~~reserve categorization,~~the ~~using~~Partnership’s ~~the~~derivative ~~definitions~~instruments ~~for~~in ~~proved~~earnings ~~reserves~~each ~~set~~reporting ~~forth~~period ~~in Regulation~~and ~~S-X~~therefore, ~~Rule~~has ~~4-10(a)~~the ~~and~~potential ~~subsequent~~for ~~SEC~~significant ~~staff~~earnings ~~interpretations and guidance~~volatility. ~~When~~Changes ~~preparing~~in the ~~Partnership’s~~fair ~~reserve~~value ~~estimates,~~of ~~the independent~~derivative ~~engineers~~instruments ~~did~~related ~~not~~to ~~independently~~the ~~verify~~Partnership’s ~~the~~natural ~~accuracy~~gas and ~~completeness of~~oil ~~information~~sales ~~and~~are ~~data~~recorded ~~furnished~~in by the ~~Partnership~~line ~~with~~caption ~~respect~~“Commodity toprice ~~ownership interests,~~risk ~~oil and natural gas production~~management, ~~well~~net” ~~test~~in ~~data,~~the ~~historical~~Partnership’s ~~costs~~statements of operations. For ~~and~~more ~~developments,~~information ~~product~~regarding ~~prices,~~the orPartnership’s ~~any~~derivative ~~agreements~~financial ~~relating~~instruments ~~to current~~ and ~~future~~their ~~operations~~accounting, ofsee ~~properties~~Note ~~and~~4, ~~sales~~Fair ~~of production. The~~Value ~~Partnership’s~~Measurements ~~independent~~and ~~reserve~~Note ~~estimates~~5, ~~are reviewed~~Derivative ~~and~~Financial ~~approved~~Instruments byto the ~~Managing General Partner~~Partnership’s ~~internal~~accompanying ~~engineering staff~~financial ~~and~~statements ~~management~~included in this report.

~~The tables~~Delivery below set forth information as of December 31, 2008, regarding the Partnership’s proved reserves as estimated by Ryder Scott Company, L.P. Reserves cannot be measured exactly, because reserve estimates involve subjective 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. Neither the present value of estimated future net cash flows nor the standardized measure is intended to represent the current market value of the estimated oil and natural gas reserves which the Partnership owns. The Partnership’s estimated proved undeveloped reserves represent the reserves attributable to the planned future recompletion of the Codell formation in the 16 Wattenberg Field wells.Commitments

	As of December 31, 2008
	Oil (MBbl)		Gas (MMcf)		Total (MMcfe)
Proved developed		46		4,390		4,666
Proved undeveloped		211		1,166		2,432
Total Proved		257		5,556		7,098

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:

	Proved		Proved		Total
	Developed		Undeveloped		Proved
	(in thousands)		(in thousands)		(in thousands)
Estimated future net cash flows	$	12,094	$	7,138	$	19,232
Standardized measure of estimated future cash flows		6,880		3,007		9,887

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

~~Estimated future~~· ~~net~~Grand ~~cash~~Valley ~~flows~~Field ~~represent~~contractual ~~the~~natural ~~estimated~~gas ~~future~~processing ~~gross revenues expected to be generated from the production of proved reserves, net of estimated production costs~~ and ~~future~~firm ~~development~~sales ~~costs,~~dedications ~~using~~extend ~~prices~~through ~~and~~2022 ~~costs in effect at December 31, 2008. The prices used in the Partnership’s reserve reports yield weighted average wellhead prices of $38.33 per barrel of oil~~ and ~~$4.70~~contract ~~per~~provides ~~Mcf of natural gas. These prices should not be interpreted as a prediction of future prices, nor do they reflect~~ the ~~value of the Partnership~~seller’s ~~commodity~~ ~~hedges~~right into ~~place~~convert ~~at December 31, 2008. The amounts shown do not give effect~~ to ~~non-property~~a ~~related~~gathering ~~expenses, such as direct costs - general~~ and ~~administrative~~gas ~~expenses,~~processing ~~or to depreciation~~contract, ~~depletion and amortization~~solely.

~~The standardized~~· ~~measure of discounted future net cash flows is calculated in accordance with Statement of Financial Accounting Standards, or SFAS, No. 69, Disclosures About~~ Oil ~~and~~sales ~~Gas Producing~~dedication ~~Activities, which requires the future cash flows to be discounted. The discount rate used was 10%. Additional information on this measure~~ is ~~presented~~made inunder ~~Supplemental~~a ~~Oil and Gas Information~~ 2-year ~~Unaudited,~~master ~~Standardized Measure~~agreement ofwith ~~Discounted~~negotiated ~~Future Net Cash Flows and Changes Therein Relating to Proved Oil and Gas Reserves, included in this report~~extension.

Delivery to Market

The Partnership relies on PDC owned or third-party gathering and transmission pipelines to transport natural gas production volumes to customers. In general, the Partnership has been, and expects to continue to be able to, produce and sell natural gas 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 recent economic downturn which has weakened U.S. oil and natural gas demand and disrupted global credit markets, which third-party entities access for pipeline expansion financing.

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Index

~~Insurance~~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.

~~PDC,~~Competitive ~~in its~~Market capacity as operator, has purchased well pollution, public liability and worker’s compensation insurance policies for its own benefit as well as the benefit of the Partnership, however insurance may not be sufficient to cover all potential liabilities. Each partner who chose to participate as an additional general partner had potential unlimited liability for unforeseen events such as blowouts, lost circulation, and stuck drill pipe, occurring prior to converting to limited partners, which could result in unanticipated additional liability materially in excess of the per unit subscription amount. However, upon conversion to limited partners on February 8, 2005, all investor partners’ liability became limited. The remaining general partner is PDC, also the Managing General Partner.Position

~~PDC~~Competition ~~has obtained~~is ~~various~~high ~~insurance~~among ~~policies,~~persons ~~as described below,~~ and ~~intends~~companies toinvolved ~~maintain these policies subject to PDC's analysis of their premium costs, coverage and other factors. PDC may,~~ in ~~its sole discretion, increase or decrease~~ the ~~policy~~exploration ~~limits~~ and ~~types~~production of ~~insurance~~oil ~~from~~and ~~time~~natural ~~to time as deemed appropriate under the circumstances, which may vary materially~~gas. ~~PDC~~The isPartnership ~~the~~competes ~~named beneficiary~~with ~~under~~entities ~~each~~having ~~policy~~financial and ~~pays~~human ~~the~~resources ~~premiums~~substantially ~~for~~larger ~~each~~than ~~policy,~~those ~~except~~available ~~with respect~~ to the ~~insurance~~Partnership. Because ~~coverage~~there ~~referred~~are tothousands inof ~~Items~~oil 2 and 5natural ~~below~~gas companies in ~~which case~~ the ~~Managing~~United ~~General~~States, ~~Partner and~~ the ~~Partnership~~national ~~are~~supply ~~co-insured~~of ~~and co-beneficiaries. Additionally~~natural gas, ~~PDC~~including ~~as operator of~~ the ~~Partnership's wells~~Rockies ~~requires~~Region ~~all~~which ofcurrently ~~PDC's~~supplies ~~subcontractors~~approximately to22% ~~carry~~of ~~liability~~the ~~insurance~~U.S. ~~coverage with~~natural ~~respect~~gas toproduction ~~the~~annually, ~~subcontractors’~~is ~~activities~~diversified. InAs ~~the~~a ~~event~~result of ~~a loss~~Federal ~~due~~Energy toRegulatory ~~the~~Commission, ~~subcontractors’~~or ~~performance~~FERC, ~~the~~and ~~insurance~~Congressional ~~policies~~deregulation of ~~the particular~~natural ~~subcontractor~~gas atand ~~risk~~oil ~~may~~prices bein ~~drawn upon before~~ the ~~insurance~~past, ofprices ~~the Managing~~are ~~General~~generally ~~Partner~~determined orby ~~that~~competitive ~~of the Partnership. PDC has obtained~~ supply-and-demand ~~expects~~market ~~to maintain the following insurance~~forces.

1.The ~~Worker~~marketing of oil and natural gas produced by the Partnership is affected by a number of factors, some of which are beyond the Partnership's ~~compensation~~control ~~insurance~~and inthe ~~full~~exact ~~compliance~~effect ~~with~~of which cannot be accurately predicted. These factors include the ~~laws~~volume ~~for~~and prices of crude oil imports, the ~~states~~availability and cost of adequate oil and natural gas 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 oil and natural gas in ~~which~~world markets combined with supply and demand balance within and across U.S. geographical regions may have caused significant variations in the ~~operator~~prices ~~has~~of ~~employees;~~these traditional hydrocarbon products over recent years.

2.The ~~Operator'~~Partnership’s ~~bodily~~fields ~~injury~~are ~~liability~~crossed ~~and~~by ~~property~~natural ~~damage~~gas ~~liability~~pipelines ~~insurance~~belonging to DCP Midstream LP (“DCP”), ~~each~~Williams ~~with~~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 ~~limit~~number of $1factors, ~~million;~~including the quality of the gas, well pressure, estimated remaining reserves, prevailing supply conditions and any applicable price regulations promulgated by the FERC. FERC natural gas pipeline open-access initiatives implemented during the mid-1980’s to mid-1990’s, mandated that interstate gas pipeline companies separate their merchant activities from their transportation activities and thus release, on both a short and a long-term basis, available transmission system capacity. Thus, local distribution companies have taken an increasingly active role in acquiring their own natural gas supplies. Consequently, the Managing General Partner believes interstate transmission pipelines and local distribution companies (utilities) are buying natural gas directly from natural gas producers and marketers, and retail unbundling efforts are causing many end-users to buy their own reserves. In general, the Partnership has been and expects to continue to be able to produce and sell oil and natural gas from the Partnership’s wells at locally competitive prices.

3.The ~~Employer'~~Partnership’s ~~liability~~secondary ~~insurance~~hydrocarbon product is oil. In contrast to U.S. natural gas pricing, which is determined more directly by North American supply-demand factors with asome ~~limit~~increasing role played by liquefied natural gas, or LNG, importation, crude oil pricing is subject to global supply-demand influences including the presence of ~~not~~the ~~less~~Organization ~~than~~of $1Petroleum ~~million;~~Exporting Countries, or OPEC, whose members establish prices and production quotas for petroleum products from time to time, with the intent of reducing the current global oversupply caused by the global economic downturn while maintaining or increasing price levels. The Managing General Partner is unable to predict what effect, if any, future OPEC actions will have on the quantity of, or prices received for, oil and natural gas produced and sold from the Partnership's wells.

4Colorado accounts for approximately 1% of the U.S.’s ~~Automobile~~total ~~public~~annual ~~liability~~domestic ~~insurance~~oil ~~with~~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 ~~limit~~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 ~~not~~rising ~~less~~Canadian ~~than~~tar $1sand ~~million~~imports ~~per~~and ~~occurrence~~lack of inter-regional export oil pipeline capacity to higher-oil demand regions. However, ~~covering~~increased ~~all~~refining ~~PDC~~capacity ~~owned~~near orDenver ~~leased~~has ~~automobile~~enabled ~~equipment;~~local ~~and~~Colorado oil suppliers, including the Partnership, to receive pricing advantage over supplies located in less densely-populated northern Rocky Region areas.

5. Operator's umbrella liability insurance with a limit of $50 million for each well location and in the aggregate.

PDC’s management, as Managing General Partner, believes that 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 drilling, recompletions and reworks. PDC has maintained liability insurance, including umbrella liability insurance, of at least two times the Partnership’s capitalization, up to a maximum of $50 million, but in no event less than $10 million during drilling or recompletion operations.

Competition and Markets

Competition is high among persons and companies involved in the exploration for and production of oil and natural gas. The Partnership competes with entities having financial resources and staffs substantially larger than those available to the Partnership. There are thousands of oil and natural gas companies in the United States. The national supply of natural gas is widely diversified. As a result of this competition and FERC and Congressional deregulation of natural gas and oil prices, prices are generally determined by competitive forces.

The marketing of any oil and natural gas produced by the Partnership is affected by a number of factors 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 pipeline and other transportation facilities, the marketing of competitive fuels, such as coal and nuclear energy, and other matters affecting the availability of a ready market, such as fluctuating supply and demand. Among other factors, the supply and demand balance of crude oil and natural gas in world markets may have caused significant variations in the prices of these products over recent years.

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Index

~~FERC Order~~Reliance No. 636, issued in 1992, restructured the natural gas industry by requiring natural gas pipelines to separate their storage, sales and transportation functions and establishing an industry-wide structure for "open-access" transportation service. FERC Order No. 637, issued in February 2000, further enhanced competitive initiatives, by removing price caps on ~~short-term~~Managing ~~capacity~~General ~~release transactions.~~Partner

~~FERC Order No~~General. ~~637~~As ~~also~~provided ~~enacted~~by ~~other~~the ~~regulatory~~Agreement, ~~policies~~PDC ~~that~~as ~~increase~~Managing ~~the flexibility~~General ofPartner, ~~interstate~~has ~~natural~~authority ~~gas~~to ~~transportation,~~manage ~~maximize~~the ~~shippers'~~Partnership’s ~~supply alternatives,~~activities ~~and~~through ~~encourage~~the ~~domestic~~D&O ~~gas~~Agreement, ~~production~~utilizing inits ~~order~~best efforts to ~~meet~~carry ~~projected increases~~out inthe ~~gas~~business ~~demand. These~~of ~~increases~~the Partnership in ~~demand~~a ~~come~~prudent ~~from~~and abusiness-like ~~number of~~fashion. PDC ~~sources,~~has ~~including~~a asfiduciary ~~boiler~~duty ~~fuel~~ to ~~meet~~exercise ~~increased~~good ~~electric~~faith ~~power~~and ~~generation needs~~deal ~~and~~fairly aswith anInvestor ~~industrial~~Partners. PDC’s ~~fuel~~executive ~~that~~staff ismanages ~~environmentally~~the ~~preferable~~affairs ~~to alternatives~~of ~~such~~the asPartnership, ~~nuclear~~while ~~power~~technical geosciences and ~~coal. This~~petroleum ~~trend~~engineering ~~has~~staff ~~been evident~~oversee ~~over~~ the ~~past~~well ~~year~~drilling, ~~particularly~~completions, inrecompletions, and operations. PDC’s administrative staff controls the ~~western~~Partnership’s ~~U.S.~~finances and makes distributions, ~~where~~apportions ~~natural~~costs ~~gas is~~and ~~the~~revenues ~~preferred~~among ~~fuel~~wells ~~for~~and ~~environmental~~prepares ~~reasons~~Partnership reports, financial statements and ~~electric~~filings ~~power~~presented ~~demand~~to ~~has directly~~Investor ~~increased~~Partners, ~~the~~tax ~~demand~~agencies ~~for~~and ~~natural~~the ~~gas~~SEC, as required.

~~The combined~~Provisions ~~impact~~ of ~~FERC~~the ~~Order~~D&O NoAgreement. Under ~~636~~the terms of the D&O Agreement, the Partnership has authorized and Noextended to PDC the authority to manage the production operations of the oil and natural gas wells in which the Partnership owns an interest, including the initial drilling, testing, completion, and equipping of wells; subsequent well recompletion, where economical, and ultimate evaluation for abandonment. Further, ~~637~~while the Partnership has ~~been~~the right to ~~increase~~take ~~the competition~~in-kind ~~among~~and separately dispose of its share of all oil and natural gas ~~suppliers~~produced from the ~~different~~Partnership’s wells, the Partnership designated PDC as its oil and natural gas ~~producing regions~~production marketing agent and authorized PDC to enter into and bind the Partnership, under those agreements PDC deems in the Ubest interest of the Partnership, in the sale of the Partnership’s oil and natural gas.S 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.

InTo ~~1995,~~ the ~~North~~extent ~~American~~the ~~Free~~Partnership ~~Trade~~has ~~Agreement,~~less orthan ~~NAFTA,~~a ~~eliminated~~100% ~~trade~~working ~~and investment~~interest ~~barriers~~ in ~~the~~a ~~United States~~well, ~~Canada,~~Partnership obligations and ~~Mexico,~~liabilities ~~increasing~~are ~~foreign competition~~limited ~~for~~to ~~gas~~its ~~production. Legislation~~proportionate ~~that~~working ~~Congress~~interest ~~may consider~~share ~~with~~and ~~respect~~thus, tothe ~~oil~~Partnership ~~and~~paid ~~natural~~only ~~gas~~its ~~may~~proportionate ~~increase~~share orof ~~decrease~~total ~~the~~lease ~~demand for~~and development costs, pays only the Partnership'’s ~~production~~proportionate inshare ~~the~~of ~~future~~operating costs, ~~depending~~and onreceives ~~whether~~its ~~the legislation~~proportionate isshare ~~directed~~of ~~toward~~production ~~decreasing~~subject ~~demand~~only orto ~~increasing supply~~royalties and overriding royalties.

~~Members of~~Under the ~~Organization~~D&O ofAgreement, ~~Petroleum~~PDC ~~Exporting~~provides ~~Countries~~all necessary labor, orvehicles, ~~OPEC~~supervision, ~~establish~~management, ~~prices~~ accounting, and ~~production~~overhead ~~quotas~~services for ~~petroleum~~normal ~~products~~production operations and may deduct from ~~time~~Partnership revenues a fixed monthly charge for these services. The charge for these operations and field supervision fees (referred to ~~time,~~as ~~with~~“well ~~the~~tending ~~intent~~ fees”) for each producing well is based on competitive industry field rates which vary based on areas of ~~reducing~~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 ~~global~~average ~~oversupply~~of the Oil and ~~maintaining~~Gas orExtraction ~~increasing~~Index ~~price levels~~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. ~~PDC~~This average is ~~unable~~commonly referred to ~~predict~~as ~~what~~the ~~effect,~~Accounting ifProcedure ~~any,~~Wage ~~future~~Index ~~OPEC actions~~Adjustment ~~will~~which ~~have~~is onpublished annually by the ~~quantity~~Council of Petroleum Accountants Societies, or ~~prices~~COPAS. These ~~received~~rates ~~for~~are reflective of similar costs incurred by comparable operators in the production field. PDC, ~~oil~~in ~~and~~certain ~~natural gas~~circumstances, ~~produced~~has and ~~sold~~may ~~from~~in the future, provide equipment or supplies, perform salt water disposal services or other services for the Partnership's ~~wells~~at the lesser of cost or competitive prices in the area of operations.

Insurance. The Partnership’'s ~~well~~production ~~fields~~operations ~~are~~involve ~~crossed~~a byvariety ~~pipelines~~of ~~belonging~~operating risks, including but not limited to ~~Encana~~fire, ~~DCP Midstream~~explosions, LPblowouts, ~~(“DCP”)~~pipe failure, ~~Williams~~casing ~~Production~~collapse and abnormally pressured formations which could result in injury, ~~RMT~~loss ~~(“Williams”)~~of life or suspension of operations, and ~~others~~ environmental hazards such as natural gas leaks, ruptures and discharges of toxic gas which could result in environmental damage and clean-up obligations. ~~These~~PDC, ~~companies~~in ~~have~~its ~~all~~capacity ~~traditionally~~as operator, has purchased ~~substantial portions~~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 ~~supply~~premium ~~from~~costs, ~~Colorado~~coverage ~~producers~~and other factors. ~~Transportation~~During ~~on these~~drilling ~~systems~~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 ~~delivered~~in ~~natural~~accordance ~~gas~~with ~~meet~~customary ~~quality~~industry ~~standards~~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, recompletions and reworks and ongoing productions operations. However, there can be no assurance that athis ~~tariff~~insurance will be ~~paid~~adequate to cover all losses or exposure for ~~quantities~~liability ~~transported~~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.

Sales of natural gas 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. As a result of FERC regulations that require interstate gas pipeline companies to separate their merchant activities from their transportation activities and require these companies to release available capacity on both a short and a long-term basis, local distribution companies have taken an increasingly active role in acquiring their own natural gas supplies. Consequently, 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. Activity by state regulatory commissions to review local distribution company procurement practices more carefully and to unbundle retail sales from transportation has caused natural gas purchasers to minimize their risks in acquiring and attaching natural gas supply and has increased competition in the natural gas marketplace.

Natural Gas and Oil Pricing

PDC markets the natural gas and 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 gas in the Piceance Basin to Williams, which has an extensive gathering and transportation system in the field. In the Wattenberg Field, the gas is sold primarily to DCP, which gathers and processes the gas and liquefiable hydrocarbons produced. Natural gas 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 may be affected by capacity interruptions on pipelines transporting natural gas out of the region.

Through December 31, 2008, PDC sold 100% of the crude oil from the Partnership’s wells to Teppco Crude Oil, LP (“Teppco”). The oil is picked up at the well site and trucked to either refineries or oil pipeline interconnects for redelivery to refineries. Oil prices fluctuate not only with the general market for oil as may be indicated by changes in the NYMEX, but also due to changes in the supply and demand at the various refineries. The cost of trucking or transporting the oil to market affects the price the Partnership ultimately receives for the oil. Beginning January 1, 2009, the Partnership began selling the majority of its crude oil to Suncor Energy Marketing, Inc. (“Suncor”).

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~~Governmental Regulation~~Customers

~~While~~PDC markets the ~~prices~~ ~~of oil and~~ natural gas ~~are set by the market, other aspects of the Partnership's business~~ and ~~the~~ oil ~~and~~from ~~natural~~Partnership ~~gas~~wells ~~industry~~ in ~~general~~Colorado ~~are heavily~~subject ~~regulated. The~~to ~~availability~~market ofsensitive acontracts, ~~ready~~the ~~market~~price ~~for~~of ~~oil~~which ~~and natural~~increases ~~gas~~or ~~production~~decreases ~~depends~~with onmarket ~~several~~forces ~~factors~~ beyond control of the Partnership~~'s control~~. ~~These factors include regulation of production~~Currently, ~~federal~~PDC ~~and state~~sells ~~regulations~~Partnership ~~governing~~natural ~~environmental~~gas ~~quality~~in ~~and pollution control,~~ the ~~amount~~ ofPiceance ~~oil~~Basin ~~and~~to ~~natural~~Williams ~~gas~~Production ~~available~~RMT ~~for sale~~(“Williams”), ~~the~~which ~~availability~~has ofan ~~adequate pipeline~~extensive gathering and ~~other~~ transportation ~~and~~system ~~processing~~in ~~facilities~~this ~~and~~Basin. In the ~~marketing~~Wattenberg ~~of competitive~~Field, ~~fuels. State~~the ~~and~~gas ~~federal~~is ~~regulations~~sold ~~generally~~primarily ~~are intended~~ to ~~protect~~DCP ~~consumers~~Midstream ~~from~~LP ~~unfair treatment and oppressive control~~(“DCP”), ~~to reduce~~which ~~the~~gathers ~~risk to the public~~ and ~~workers~~processes ~~from~~ the ~~drilling,~~gas ~~completion, production~~ and ~~transportation~~liquefiable ofhydrocarbons ~~oil~~produced. Natural ~~and natural~~ gas, toproduced ~~prevent~~in ~~waste~~Colorado ofmay ~~oil and~~be ~~natural~~impacted ~~gas,~~by tochanges ~~protect~~in ~~rights~~market ofprices ~~owners~~on in a ~~common~~national ~~reservoir~~level, ~~and~~as ~~to control~~well ~~contamination~~as ofchanges ~~the~~in ~~environment. Pipelines are subject to~~ the ~~jurisdiction~~market offor ~~various~~natural ~~federal,~~gas ~~state~~within ~~and~~the ~~local~~Rocky ~~agencies~~Mountain Region. ~~PDC management,~~Sales asof ~~Managing~~natural ~~General~~gas ~~Partner,~~from ~~believes that~~ the Partnership's iswells ~~in compliance~~to ~~with~~DCP ~~such~~and ~~statutes,~~Williams ~~rules,~~are ~~regulations~~made ~~and~~on ~~governmental~~the ~~orders, although~~spot ~~there~~market ~~can~~via beopen-access notransportation ~~assurance~~arrangements ~~that~~through ~~this~~Williams is or ~~will~~other ~~remain~~pipelines ~~the case. The~~and ~~following~~may ~~summary~~be ~~discussion~~impacted ofby ~~the~~capacity ~~regulation~~interruptions ofon ~~the United~~pipelines ~~States~~transporting ~~oil and~~ natural gas ~~industry~~out ~~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~~region.

~~Environmental Regulation~~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 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.

~~The Partnership’s~~Industry 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 could 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 December 2008, the State of Colorado’s Oil and Gas Conservation Commission finalized new broad-based wildlife protection and environmental regulations for the oil and natural gas industry which are expected to increase the Partnership’s well recompletion costs and ongoing level of production and operating costs. Partnership expenses relating to preserving the environment have risen over the past two years and are expected to continue in 2009 and beyond. While environmental regulations have had no materially adverse effect on its operations to date, no assurance can be given that environmental regulations or interpretations of such regulations will not in the future, result in a curtailment of production or otherwise have a materially adverse effect on Partnership operations.Regulation

~~The Partnership~~While ~~generates wastes that may be subject to~~ the ~~Federal~~prices ~~Resource Conservation~~of ~~and~~oil ~~Recovery Act, or RCRA,~~ and ~~comparable~~natural ~~state statutes. The~~gas ~~U.S.~~are ~~Environmental~~set ~~Protection~~by ~~Agency,~~the ~~or EPA~~market, ~~and various~~other ~~state~~aspects ~~agencies~~of ~~have limited~~ the ~~approved~~Partnership's ~~methods~~business ofand ~~disposal~~the ~~for~~industry ~~certain hazardous~~in ~~and~~general ~~non-hazardous~~are ~~wastes~~heavily regulated. ~~Furthermore,~~The ~~certain~~following ~~wastes generated~~summary bydiscussion ~~our~~of ~~operations~~the ~~that~~regulation ~~are~~of ~~currently~~the ~~exempt~~United ~~from~~States ~~treatment~~industry ~~as "hazardous~~is ~~wastes"~~not ~~may~~intended into ~~the~~constitute ~~future~~a becomplete ~~designated~~discussion asof ~~"hazardous~~the ~~wastes~~various statutes," rules, regulations and ~~therefore~~ beenvironmental ~~subject~~orders to ~~more~~which ~~rigorous~~the ~~and~~Partnership's ~~costly~~operations ~~operating~~may ~~and~~be ~~disposal requirements~~subject.

~~Proposed Regulation~~The availability of a ready market for oil and natural gas production depends on several factors beyond the Partnership's control. These factors include regulation of production, federal and state regulations governing environmental quality and pollution control, the amount of oil and natural gas available for sale, the availability of adequate pipeline and other transportation and processing facilities and the marketing of competitive fuels. State and federal regulations generally are intended to protect consumers from unfair treatment and oppressive control, to reduce the risk to the public and workers from the drilling, completion, production and transportation of oil and natural gas, to prevent waste of oil and natural gas, to protect rights of owners in a common reservoir and to control contamination of the environment. Pipelines are subject to the jurisdiction of various federal, state and local agencies.

~~Various legislative~~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~~/or~~ tax incentives and other measures. The petroleum and natural gas industries historically ~~has~~ have been very heavily regulated; therefore, there is no assurance that the less stringent regulatory approach recently pursued by FERC and Congress will continue. The Partnership cannot determine to what extent its future operations and earnings will be affected by new legislation, new regulations, or changes in existing regulation, at federal, state or local levels. Current federal and state proposed regulations expected to impact the industry, if enacted, include the following:

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~~Operating Hazards~~· Congressional legislation which could establish a “cap and trade” system regarding greenhouse gas emissions. Companies would be assigned emission “allowances” under these bills which would decline each year. In addition, new EPA greenhouse gas monitoring and reporting regulations could affect the Partnership and the third parties that process the Partnership’s natural gas and oil.

~~The Partnership's~~· ~~production~~Federal ~~operations~~regulatory ~~include a variety of operating risks~~proposals, ~~including~~ ~~but~~which ~~not~~could ~~limited~~limit to the ~~risk~~use of ~~fire,~~over-the-counter ~~explosions,~~(OTC) ~~blowouts~~derivatives, ~~cratering, pipe~~including ~~failure,~~the ~~casing~~oil ~~collapse, abnormally pressured formations,~~ and ~~environmental~~ ~~hazards~~gas ~~such~~price ashedging ~~natural~~the ~~gas~~Managing ~~leaks,~~General ~~ruptures~~Partner ~~and~~currently ~~discharges of toxic gas~~uses. ~~The~~ ~~occurrence~~Limits ofon ~~any~~the use of ~~these~~OTC instruments could ~~result~~impair ~~in substantial losses to~~ the ~~Partnership~~Managing ~~due~~General toPartner’s ~~injury~~use ~~and loss~~ of ~~life,~~these ~~severe~~derivatives ~~damage to~~ and ~~destruction~~ ofcould ~~property,~~limit natural resources and equipment, pollution and other environmental damage, clean-up responsibilities, regulatory investigation, criminal proceedings and penalties and suspension of operations. Pipeline, gathering and transportation operations are subject to the ~~many~~Partnership’s ~~hazards~~ability ~~inherent in the natural gas industry. These hazards include damage~~ to ~~wells,~~protect ~~pipelines~~its ~~and~~cash ~~other~~flows ~~related equipment, damage to property caused by hurricanes, floods, fires~~ and ~~other~~reduce ~~acts~~commodity ofprice 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 operationsrisk.

~~Any significant~~· ~~problems~~New ~~related~~or toincreased ~~Partnership~~severance ~~wells~~taxes ~~could~~have ~~adversely~~been ~~affect~~proposed ~~our ability~~in toseveral ~~conduct operations. In accordance with customary industry practice~~states, ~~the~~ ~~Partnership~~which 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 Partnership operations and financial condition. We cannot predict whether insurance will continue to be available at premium levels that justify its purchase or whether insurance will be available at all. Furthermore, the ~~Partnership~~existing isoperations ~~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~~these ~~regional~~states ~~prices~~and or the ~~Partnership’s~~economic ~~inability~~viability toof ~~deliver natural~~future ~~gas~~well recompletions.

Environmental Regulation

The Partnership’s operations are subject to numerous laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. Public interest in the protection of the environment has increased dramatically in recent years. The trend of more expansive and tougher environmental legislation and regulations is expected to continue. To the extent laws are enacted or other governmental action is taken that restricts drilling or imposes environmental protection requirements that result in increased costs and reduced access to the natural gas industry in general, our business and prospects could be adversely affected. In 2009, the State of Colorado’s Oil and Gas Conservation Commission implemented new broad-based environmental and wildlife protection regulations for the industry which are expected to increase the Partnership’s well recompletion costs and ongoing level of natural gas and oil production costs. See Note 9, Commitments and Contingencies−Other to the Partnership’s accompanying financial statements to this report.

Partnership expenses relating to preserving the environment have risen over the past two years and are expected to continue. Environmental and other governmental laws and regulations have increased the costs to plan, design, drill, install, operate and abandon oil and natural gas wells. While environmental regulations have had no materially adverse effect on its operations to date, no assurance can be given that environmental regulations or interpretations of such regulations will not in the future, result in a curtailment of production or otherwise have a materially adverse effect on Partnership operations.

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

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

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 0001306758. 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.

Item 1A. Risk Factors

In the course of its normal business, the Partnership is subject to a number of risks that could adversely impact its business, operating results, financial condition, and cash distributions. The following is a discussion of the material risks involved in an investment in the Partnership.

Risks Related to the Global Economic Crisis

The current global economic crisis may increase the magnitude and the likelihood of the occurrence of the negative consequences discussed in many of the risk factors that follow and result in reduced cash distributions to the Investor Partners. In particular, consider the risks related to the rapid deterioration of demand for oil and natural gas resulting from the economic crisis and the related negative effects on oil and gas pricing. Similarly, further reductions in oil and gas prices could result in existing Partnership wells being uneconomical to recomplete which would reduce remaining Partnership proved reserves. These factors could limit the Managing General Partner’s ability to execute the Partnership business plan and result in lower Partnership production, adversely impacting Partnership income and Investor Partner distributions. Additionally, the global economic crisis also increases the Partnership’s credit risk associated with derivative financial institutional counterparty default or oil and natural gas purchaser non-payment, thus potentially impacting Partnership liquidity and production operating levels. All of these risks could have a significant effect on the Partnership’s business, financial results and Partnership distributions. Any additional deterioration in the domestic or global economic conditions will further amplify these results.

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~~Recent~~Number ~~disruptions in the global financial markets and the likely related economic downturn may further decrease the demand for oil and natural gas and the prices~~ of ~~oil~~total and natural gas thereby limiting the Partnership’s production and thereby adversely affecting Partnership profitability and Investor Partner distributions. During the second half of 2008 and to date, prices for oil and natural gas decreased over 70% from midfull-~~2008 levels. The~~time well-publicized global financial market disruptions and the related economic crisis may further decrease demand for oil and gas and therefore lower oil and gas prices. If there is such an additional reduction in demand, the production of natural gas in particular may be in oversupply. There is no certainty as to how long this low price environment will continue. The Partnership operates in a highly competitive industry, and certain competitors have lower operating costs in such an environment. Additionally, the inability of third parties to finance and build additional pipelines out of the Rockies and elsewhere could cause significant negative pricing effects. Any of the above factors could adversely affect the Partnership’s operating results and reduce cash distributions to the Investor Partners. For more information regarding the Wattenberg Field recompletion plan, see Item 1 Business, Plan of Operation.employees

~~Risks~~The ~~Pertaining~~Partnership has no employees and relies on the Managing General Partner to ~~Natural Gas~~manage the Partnership’s business. PDC’s officers, directors and ~~Oil~~employees ~~Investments~~receive direct remuneration, compensation or reimbursement solely from PDC, and not the Partnership, with respect 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.

~~The~~Item ~~oil and natural gas business is speculative and may be unprofitable and result in the total loss of investment~~1A. ~~The~~ Risk oil and natural gas business is inherently speculative and involves a high degree of risk and the possibility of a total loss of investment. The Partnership's business activities may result in unprofitable well operations, not only from non-productive wells and recompletions, but also from wells that do not produce oil or natural gas in sufficient quantities or quality to return a profit on the amounts expended. The prices of oil and natural gas play a major role in the profitability of the Partnership. Partnership wells may not produce sufficient natural gas and oil for investors to receive a profit or even to recover their initial investment. Only three out of 77 partnerships sponsored by PDC have, to date, generated cash distributions in excess of investor subscriptions without giving effect to tax savings.Factors

~~The~~Not Partnership may retain Partnership revenues if needed for Partnership operations to fully develop the Partnership's wells; if full development of the Partnership's wells proves commercially unsuccessful, an individual investor partner might anticipate a reduction in cash distributions. The Partnership utilized substantially all of the capital raised in the offering for the drilling and completion of wells. If the Partnership requires additional capital in the future, it will have to retain Partnership revenues necessary for these purposes. Retaining Partnership revenues will result in a reduction of cash distributions to the investors. Additionally, in the future, PDC plans to rework or recomplete Partnership wells; however, PDC has not withheld money from the initial investment for that future work. Future development of the Partnership's wells may prove commercially unsuccessful and the further-developed Partnership wells may not generate sufficient funds from production to increase distributions to Investor Partners to cover revenues retained. If future development of the Partnership's wells is not commercially successful using funds retained from current production revenues, lower future operational revenues could result in a reduced level of cash distributions to the Investor Partners of the Partnership.Applicable

The inability of one or more of the Partnership’s customers or derivative counterparties to meet their obligations may adversely affect Partnership profitability and timing of distributions to Investor Partners. Substantially all of the Partnership’s accounts receivable results from natural gas and oil sales to a limited number of third parties in the energy industry. This concentration of customers may affect the Partnership’s overall credit risk in that these entities may be similarly affected by recent changes in economic and other conditions. In addition, Partnership oil and natural gas derivatives positions expose the Partnership to credit risk in the event of nonperformance by counterparties.

Increases in prices of oil and natural gas have increased the cost of drilling and development and may adversely affect the performance and profitability of the Partnership in both the short and long term and may result in reduced cash distributions to the Investor Partners. In the recent high price environment, most oil and natural gas companies had increased their expenditures for drilling new wells. This has resulted in increased demand and higher cost for oilfield services and well equipment. Because of these higher costs, the Partnership is subject to a higher risk for decreased profitability during both future rising or falling, oil and natural gas price changes.

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Natural gas and oil prices fluctuate unpredictably and a decline in prices of oil and natural gas will reduce the profitability of the Partnership's production operations and could result in reduced cash distributions to Investor Partners. Global economic conditions, political conditions, and energy conservation have created unstable prices. Revenues of the Partnership are directly related to natural gas and oil prices. The prices for domestic natural gas and oil production have varied substantially over time and by location and are likely to remain extremely unstable. Revenue from the sale of oil and natural gas increases when prices for these commodities increase and declines when prices decrease. These price changes can occur rapidly and are not predictable nor within the control of the Partnership. A decline in natural gas and/or oil prices would result in lower revenues for the Partnership and a reduction of cash distributions to the Investor Partners of the Partnership. Further, reductions in prices of oil and natural gas may result in shut-ins thereby resulting in lower production, revenues and cash distributions. The prices from the fourth quarter of 2008 to date have been too low to economically justify many drilling operations, including well recompletions, and it is uncertain how long such low pricing shall persist.

The high level of drilling activity, particularly in the Rocky Mountain Region during the past two years, could result in an oversupply of gas on a regional or national level, resulting in much lower commodity prices, reduced profitability of the Partnership and reduced cash distributions to Investor Partners. The high level of drilling, combined with a reduction in demand resulting from recently volatile oil and natural gas prices and economic uncertainty, could result in an oversupply of natural gas. In the Rocky Mountain region, rapid growth of production and increasing supplies may result in lower prices and production curtailment due to limitations on available pipeline facilities or markets not developed to utilize or transport the new supplies. In both cases, the result would likely result in lower Partnership natural gas sales prices, reduced profitability for the Partnership and reduced cash distributions to the Investor Partners. Although additional pipeline capacity became available in early 2008 with the expansion of Rockies Express Pipeline, pipeline constraints continue for regional Rocky Mountain natural gas production transportation to high-demand market areas.

Sufficient insurance coverage may not be available for the Partnership, thereby increasing the risk of loss for the General Partners. It is possible that some or all of the insurance coverage which the Partnership has available may become unavailable or prohibitively expensive. In that case, PDC might elect to change the insurance coverage. The general partners could be exposed to additional financial risk due to the reduced insurance coverage and due to the fact that they would continue to be individually liable for obligations and liabilities of the Partnership that arose prior to conversion to limited partners which occurred on February 8, 2005. Investor Partners could be subject to greater risk of loss of their investment because less insurance would be available to protect the Partnership from casualty losses. Moreover, should the Partnership's cost of insurance become more expensive, or should the Partnership suffer a significant uninsured casualty loss, the amount of cash distributions to the investors will be reduced.

Through their involvement in the Partnership and other non-partnership activities, the Managing General Partner and its affiliates have interests which conflict with those of the Investor Partners; actions taken by the Managing General Partner in furtherance of its own interests could result in the Partnership being less profitable and a reduction in cash distributions to the Investor Partners. PDC's continued active participation in oil and natural gas activities for its own account and on behalf of other partnerships organized or to be organized by PDC and the manner in which Partnership revenues are allocated create conflicts of interest with the Partnership. PDC has interests which inherently conflict with the interests of the Investor Partners. The following is an itemization of the material conflicts of interest of PDC as Managing General Partner of the Partnership and of PDC’s affiliates:

· PDC might sponsor additional drilling programs or joint ventures in the future, that could conflict with the interests of the Partnership. PDC and affiliates have the right to organize and manage oil and natural gas drilling programs in the future similar to the Partnership and to conduct production operations now and in the future on its own behalf or for other individual investor partners. This situation could lead to a conflict between the position of PDC as Managing General Partner of the Partnership and the position of PDC or its affiliates as managing general partner or sponsor of additional programs.

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· PDC has a fiduciary duty as Managing General Partner to the Partnership. PDC acts as managing general partner currently for 33 limited partnerships, including this Partnership, and is accountable to all of the partnerships as a fiduciary. PDC therefore has a duty to exercise good faith and deal fairly with the investor partners of each partnership. PDC’s actions taken on behalf of one or more of these partnerships could be disadvantageous to the Partnership and could fall short of the full exercise of its fiduciary duty to the Partnership.

· There are and will continue to be transactions between PDC, its affiliates and the Partnership. PDC, as operator of the Partnership, has and will continue to provide drilling, completion and operation services to the Partnership’s wells. Although the prices that PDC has charged, and will charge, to the Partnership for the supplies and services provided by PDC and affiliates to the Partnership will be competitive with the prices charged by unaffiliated persons for the same supplies and services, PDC will benefit financially from this relationship.

In operating the Partnership, the Managing General Partner and its affiliates could take actions which benefit themselves and which do not benefit the Partnership. These actions could result in the Partnership being less profitable. In that event, Investor Partners could anticipate a reduction of cash distributions.

The Partnership and other partnerships sponsored by PDC, as Managing General Partner, may compete with each other for prospects, equipment, contractors, and personnel; as a result, the Partnership may find it more difficult to operate effectively and profitably. During 2008, PDC operated and managed other partnerships formed for substantially the same purposes as those of the Partnership. PDC will operate and manage these partnerships in 2009 and for the foreseeable future. Therefore, a number of partnerships with unexpended capital funds, including those partnerships formed before and after the Partnership, may exist at the same time. The Partnership may compete for equipment, contractors, and PDC personnel (when the Partnership is also in need of equipment, contractors and PDC personnel), which may make it more difficult and more costly to obtain equipment and services for the Partnership. In that event, it is possible that the Partnership would be less profitable. Additionally, because PDC must divide its attention in the management of its own corporate interests as well as the affairs of the 33 limited partnerships PDC has organized in previous programs, the Partnership will not receive PDC's full attention and efforts at all times.

The Partnership's derivative activities could result in reduced revenue and cash flows compared to the level the Partnership might experience if no derivative instruments were in place. The Managing General Partner uses derivative instruments for a portion of the Partnership’s natural gas and oil production to achieve a more predictable cash flow and to reduce exposure to adverse fluctuations in the prices of natural gas and oil. These arrangements expose the Partnership to the risk of financial loss in some circumstances, including when purchases or sales are different than expected, the counter-party to the derivative contract defaults on its contract obligations, or when there is a change in the expected differential between the underlying price in the derivative agreement and actual prices that we receive. In addition, derivative arrangements may limit the benefit from changes in the prices for natural gas and oil. Since the Partnership’s derivatives do not currently qualify for use of hedge accounting, changes in the fair value of derivatives are recorded in the Partnership’s income statements. Accordingly, the Partnership’s net income is subject to greater volatility than would be reported if its derivative instruments qualified for hedge accounting. For instance, if oil and natural gas prices rise significantly, it could result in significant non-cash losses each quarter which could have a material negative effect on Partnership net income.

Fluctuating market conditions and government regulations may cause a decline in the profitability of the Partnership and a reduction of cash distributions to the Investor Partners. The sale of any natural gas and oil produced by the Partnership will be affected by fluctuating market conditions and governmental regulations, including environmental standards, set by state and federal agencies. From time-to-time, a surplus of natural gas or oil may occur in areas of the United States. The effect of a surplus may be to reduce the price the Partnership receives for its natural gas or oil production, or to reduce the amount of natural gas or oil that the Partnership may produce and sell. As a result, the Partnership may not be profitable. Lower prices and/or lower production and sales will result in lower revenues for the Partnership and a reduction in cash distributions to the Investor Partners of the Partnership.

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Index

The Partnership is subject to complex federal, state, local and other laws and regulations that could adversely affect the cost, manner or feasibility of doing business. The Partnership’s operations are regulated extensively at the federal, state and local levels. Environmental and other governmental laws and regulations have increased the costs to plan, design, drill, install, operate and abandon oil and natural gas wells. Under these laws and regulations, the Partnership could also be liable for personal injuries, property damage and other damages. Failure to comply with these laws and regulations may result in the suspension or termination of the Partnership’s operations and subject the Partnership to administrative, civil and criminal penalties. Moreover, public interest in environmental protection has increased in recent years, and environmental organizations have opposed, with some success, certain drilling projects. Compliance with these regulations and possible liability resulting from these laws and regulations could result in a decline in profitability of the Partnership and a reduction in cash distributions to the Investor Partners of the Partnership.

The Partnership’s activities are subject to the regulations regarding conservation practices and protection of correlative rights. These regulations affect our operations and limit the quantity of natural gas and/or oil we may produce and sell. A major risk inherent in our drilling plans is the need to obtain drilling permits from state and local authorities. Because the Partnership may consider recompleting various of its Wattenberg wells if the economic environment improves, for which permits will be required, delays in obtaining regulatory approvals or drilling permits or the failure to obtain a drilling permit for a well or the receipt of a permit with unreasonable conditions or costs could have a material adverse effect on our ability to develop our properties. Additionally, the natural gas and oil regulatory environment could change in ways that might substantially increase the financial and managerial costs of compliance with these laws and regulations and, consequently, adversely affect the Partnership’s ability to pay distributions to Investor Partners. Illustrative of these risks are regulations recently enacted by the State of Colorado which focuses on the oil and gas industry. These multi-faceted regulations significantly enhance requirements regarding oil and natural gas permitting, environmental requirements, and wildlife protection. Permitting delays and increased costs could result from these final regulations. The Partnership further references sections Government Regulation and Proposed Regulation in Item 1, Business, for a detailed discussion of the laws and regulations that effect Partnership activities.

Environmental hazards involved in drilling gas and oil wells may result in substantial liabilities for the Partnership, a decline in profitability of the Partnership and a reduction in cash distributions to the Investor Partners. There are numerous natural hazards involved in the drilling and operation of wells, including unexpected or unusual formations, pressures, blowouts involving possible damages to property and third parties, surface damages, personal injury or loss of life, damage to and loss of equipment, reservoir damage and loss of reserves. Uninsured liabilities would reduce the funds available to the Partnership, may result in the loss of Partnership properties and may create liability for additional general partners. The Partnership may become subject to liability for pollution, abuses of the environment and other similar damages, and it is possible that insurance coverage may be insufficient to protect the Partnership against all potential losses. In that event, Partnership assets would be used to pay personal injury and property damage claims and the costs of controlling blowouts or replacing destroyed equipment rather than for drilling activities. These payments would cause an otherwise profitable partnership to be less profitable or unprofitable and would result in a reduction of cash distributions to the Investor Partners of the Partnership.

Delay in Partnership natural gas or oil production could reduce the Partnership’s profitability and cash distributions to the Investor Partners. The Partnership’s inability to recomplete wells in a timely fashion may result in production delays. In addition, marketing demands that tend to be seasonal may reduce or delay production from wells. Wells drilled for the Partnership may have access to only one potential market. Local conditions including but not limited to closing businesses, conservation, shifting population, pipeline maximum operating pressure constraints, and development of local oversupply or deliverability problems could halt or reduce sales from Partnership wells. Any of these delays in the production and sale of the Partnership's natural gas and oil could reduce the Partnership's profitability, and in that event, the cash distributions to the Investor Partners of the Partnership would decline.

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Index

A significant variance from the Partnership’s estimated reserves and future net revenues could adversely affect the Partnership’s cash flows and results of operations. The accuracy of proved reserves and future net revenues estimates from such reserves, is a function of the quality of available geological, geophysical, engineering and economic data and is subject to various assumptions, including assumptions required by the SEC relating to oil and gas prices, drilling and operating expenses, and other matters. Although the estimated proved reserves represent reserves the Partnership reasonably believes it is certain to recover, actual future production, oil and gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and gas reserves will most likely vary from the assumptions and estimates used to determine proved reserves. Any significant variance could materially affect the estimated quantities and value of the Partnership’s oil and gas reserves, which in turn could adversely affect cash flows and results of operations. In addition, estimates of proved reserves may be adjusted to reflect many factors, many of which are beyond the Partnership’s control, including production history, results of development, and prevailing oil and natural gas prices which are volatile and often fluctuate greatly. Lower natural gas and oil prices may not only reduce Partnership revenues, but also may reduce the amount of natural gas and oil that can be produced economically. As a result, the Partnership may have to make substantial additional downward adjustments to its estimated proved reserves. If this occurs or if Partnership estimates of production data factors change, accounting rules may require the Partnership to write-down operating assets to fair value, as a non-cash charge to earnings. The Partnership assesses impairment of capitalized costs of proved natural gas and oil properties by comparing net capitalized costs to estimated undiscounted future net cash flows on a field-by-field basis using estimated future production based upon prices at which the Managing General Partner reasonably estimates such products may be sold. The Partnership has recorded no impairments since its operations commenced in July 2004. The Partnership may incur additional impairment charges in the future, which could have a material adverse effect on the results of Partnership operations and Partner’s equity.

The standardized measure of estimated proved reserves, in accordance with SFAS 69, Disclosures About Oil and Gas Producing Activities, which assumes a 10% discount factor, will not necessarily equal the current fair market value of the estimated oil and gas reserves. In accordance with the reserve reporting requirements of the SEC, the estimated discounted future net cash flows from proved reserves are generally based on prices and costs as of the date of the estimate. Actual future prices and costs may be materially higher or lower than those as of the date of the estimate. The timing of both the production and the expenses with respect to the development and production of oil and gas properties will affect the timing of future net cash flows from estimated proved reserves and their related present value estimate.

Seasonal weather conditions may adversely affect the Partnership’s ability to conduct production activities in some of the areas of operation. Oil and natural gas operations in the Rocky Mountains are adversely affected by seasonal weather conditions. In certain areas, drilling and other oil and natural gas activities are restricted or prevented by weather conditions for up to six months out of the year. This limits operations in those areas and can intensify competition during those months for oil field equipment, services, supplies and qualified personnel, which may lead to periodic shortages. These constraints and the resulting shortages or high costs could delay operations and materially increase operating and capital costs and therefore adversely affect profitability, and could result in a reduction of cash distributions to the Investor Partners.

A Colorado lawsuit against PDC, the Managing General Partner of the Partnership, for underpayment of royalties, could financially harm PDC and the Partnership. A judgment by the Federal Court against PDC could result in lower oil and gas sales revenues for the Partnership, reduced profitability and reduced cash distributions to the Investor Partners. On May 29, 2007, Glen Droegemueller, individually and as representative plaintiff on behalf of all others similarly situated, filed a class action complaint against the Managing General Partner in the District Court, Weld County, Colorado alleging that the Managing General Partner underpaid royalties on natural gas produced from wells operated by the Managing General Partner in parts of the State of Colorado (the “Droegemueller Action”). The plaintiff sought declaratory relief and to recover an unspecified amount of compensation for underpayment of royalties paid by us pursuant to leases. The Managing General Partner removed the case to Federal Court on June 28, 2007. On October 10, 2008, the court preliminarily approved a settlement agreement between the plaintiffs and the Managing General Partner, on behalf of itself and the Partnership. Although the Partnership was not named as a party in the suit, the lawsuit states that it relates to all wells operated by the Managing General Partner, which includes a majority of the Partnership’s 16 wells in the Wattenberg field. The portion of the settlement relating to the Partnership’s wells for all periods through December 31, 2008 that has been expensed by the Partnership is approximately $18,000 which includes legal fees of approximately $1,000. This entire settlement of $17,713 was deposited by the Managing General Partner into an escrow account on November 3, 2008. Notice of the settlement was mailed to members of the class action suit in the fourth quarter of 2008. The final settlement was approved by the court on April 7, 2009. Settlement distribution checks were mailed in July 2009. During September 2009, all settlement costs were passed through to the Partners and any required judicial action from the settlement of the suit was implemented in this distribution.

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Index

Special Risks of an Investment in the Partnership

A “material weakness” identified in the Partnership’s internal control over financial reporting and resulting ineffective disclosure controls and procedures could have a material adverse effect on the reliability of Partnership financial statements, its ability to file Partnership public reports on time and provide for accurate and timely Investor Partner distributions.

Management of the Managing General Partner assessed the effectiveness of the Partnership’s internal control over financial reporting as of December 31, 2008 and pursuant to this assessment, identified a material weakness in the Partnership’s internal control over financial reporting. The existence of any material weakness means there is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the Partnership’s annual or interim financial statements will not be prevented or detected on a timely basis. The material weakness relates to the Partnership’s failure to maintain sufficient documentation to adequately assess the operating effectiveness of internal control over reporting for the transactions that are directly related to and processed by the Partnership. For a more detailed discussion of the Partnership’s material weakness, see Item 9A(T), Controls and Procedures, of this report. As a result of this material weakness, management of the Managing General Partner concluded that the Partnership’s disclosure controls and procedures were not effective as of December 31, 2008.

Failure by the Partnership to maintain effective internal control over financial reporting and/or effective disclosure controls and procedures could prevent the Partnership from being able to prevent fraud and/or provide reliable financial statements and other public reports or make timely and accurate Investor Partner distributions. Such circumstances could harm the Partnership’s business and operating results, cause Investor Partners to lose confidence in the accuracy and completeness of the Partnership’s financial statements and reports, and have a material adverse effect on the Partnership’s ability to fully develop and utilize Partnership assets. These failures may also adversely affect the Partnership’s ability to file our periodic reports with the SEC on time.

The partnership units are not registered and there is no public market for the units. As a result, an individual investor partner may not be able to sell his or her units. There is and will be no public market for the units nor will a public market develop for the units. Investor Partners may not be able to sell their Partnership interests or may be able to sell them only for less than fair market value. A sale or transfer of units by an individual investor partner requires PDC’s, as Managing General Partner, prior written consent. For these and other reasons, an individual investor partner must anticipate that he or she will have to hold his or her Partnership interests indefinitely and will 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.

The general partners, including the Managing General Partner, are individually liable for Partnership obligations and liabilities that arose prior to conversion to limited partners that may exceed the amount of their subscriptions, Partnership assets, and the assets of the Managing General Partner. Under West Virginia law, the state in which the Partnership was organized, general partners of a limited partnership have unlimited liability with respect to the Partnership. Therefore, the additional general partners of the Partnership were liable individually and as a group for all obligations and liabilities of creditors and claimants, whether arising out of contract or tort, in the conduct of the Partnership's operations until such time as the additional general partners converted to limited partners on February 8, 2005. Upon completion of the drilling phase of the Partnership's wells, all additional general partnership units were converted into units of limited partnership interests and thereafter became limited partners of the Partnership. Irrespective of conversion, the additional general partners will remain fully liable for obligations and liabilities that arose prior to conversion. Investors as additional general partners may be liable for amounts in excess of their subscriptions, the assets of the Partnership, including insurance coverage, and the assets of the Managing General Partner.

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Index

The Managing General Partner may not have sufficient funds to repurchase limited partnership units. As a result of PDC, the Managing General Partner, being a general partner in several partnerships as well as an actively operating corporation, the Partnership’s net worth is at risk of reduction if PDC suffers a significant financial loss. Because the Investor Partners may request the Managing General Partner to repurchase the units in the Partnership, subject to certain conditions and restrictions, a significant adverse financial reversal for PDC could result in the Managing General Partner’s inability to pay for Partnership obligations or the repurchase of investor units. As a result, an individual investor partner may not be able to liquidate his or her investment in the Partnership.

A significant financial loss by the Managing General Partner could result in PDC's inability to indemnify additional general partners for personal losses suffered because of Partnership liabilities. As a result of PDC's commitments as managing general partner of several partnerships and because of the unlimited liability of a general partner to third parties, PDC's net worth is at risk of reduction if PDC suffers a significant financial loss. The partnership agreement provides that PDC as the Managing General Partner will indemnify all additional general partners for the amounts of their obligations and losses which exceed insurance proceeds and the Partnership's assets. Because PDC is primarily responsible for the conduct of the Partnership's affairs, as well as the affairs of other partnerships for which PDC serves as managing general partner, a significant adverse financial reversal for PDC could result in PDC's inability to pay for Partnership liabilities and obligations. The additional general partners of the Partnership might be personally liable for payments of the Partnership's liabilities and obligations. Therefore, the Managing General Partner's financial incapacity could increase the risk of personal liability as an additional general partner because PDC would be unable to indemnify the additional general partners for any personal losses they suffered arising from Partnership operations.

A substantial part of the Partnership’s natural gas and oil production is located in the Rocky Mountain Region, making it vulnerable to risks associated with operating in a single major geographic area. The Partnership’s operations are focused in the Rocky Mountain Region and its producing properties are geographically concentrated in that area. Because Partnership operations are not geographically diversified, the success of its operations and profitability may be disproportionately exposed to the effect of any regional events, including fluctuations in prices of natural gas and oil produced from the wells in the region, natural disasters, restrictive governmental regulations, transportation capacity constraints, curtailment of production or interruption of transportation, and any resulting delays or interruptions of production from existing or planned new wells. During the last four months of 2008, natural gas prices in the Rocky Mountain Region fell disproportionately when compared to other markets, due in part to continuing constraints in transporting gas from producing properties in the region. Because of the concentration of Partnership operations in the Rocky Mountain Region, and although in late 2008 the Partnership entered into a significant multi-year basis hedge minimizing the price risk of the Partnership’s operational concentration in the Rocky Mountain region, such price decreases could have a material adverse effect on Partnership revenue, profitability, cash flow and cash distributions to Investor Partners.

The Managing General Partner, with respect to its own corporate interests, the Partnership and various other limited partnerships sponsored by the Managing General Partner, have been delinquent in filing periodic reports with the SEC. Consequently, Investor Partners are unable to review the delinquent partnerships’ respective financial statements as a source of information for evaluating their investment in the Partnership. PDC, as an actively operating corporation, and various limited partnerships which PDC has sponsored and for which PDC serves as the Managing General Partner are subject to reporting requirements of the Exchange Act and are obligated to file annual and quarterly reports with the SEC in accordance with the rules of the SEC. In the course of preparing corporate financial statements for the quarter ended June 30, 2005, PDC identified accounting errors in its prior period financial statements. As a result, on October 17, 2005, PDC’s Board of Directors, Audit Committee and management concluded that PDC’s previously issued financial statements could not be relied upon and would be restated. PDC, as Managing General Partner, made similar determinations regarding the financial statements of certain of the limited partnerships which are subject to the Exchange Act reporting obligations.

Since June 2007, PDC has become compliant with its corporate Exchange Act filing and reporting obligations. Additionally, Rockies Region 2007 Limited Partnership, Rockies Region 2006 Limited Partnership, PDC 2005-A Limited Partnership, PDC 2005-B Limited Partnership, Rockies Region Private Limited Partnership, PDC 2004-A Limited Partnership and PDC 2004-D Limited Partnership have completed all required SEC filings through June 30, 2009. PDC 2004-B Limited Partnership (with this filing) has completed all required SEC filings through December 31, 2008, but is delinquent on all subsequent quarterly filing requirements. PDC 2004-C Limited Partnership has completed all required SEC filings through December 31, 2007, but is delinquent on all subsequent quarterly and annual filing requirements. All remaining limited partnerships sponsored by PDC which are subject to the Exchange Act have been, and continue to be, delinquent in filing their respective periodic reports in accordance with the requirements of the Exchange Act. Until these partnerships file their delinquent periodic reports, investors will be unable to review the financial statements of the various limited partnerships as an additional source of information they can use in their evaluation of their investment in the Partnership. Currently the Managing General Partner has in place a compliance effort addressing the delinquent reports of the various limited partnerships. However, due to the amount of effort, time and financial resources required to bring the limited partnerships into compliance with Exchange Act periodic reporting requirements, the Partnership and the various limited partnerships may be unable to bring their delinquent reports current and may be unable in the future to file their required periodic reports with the Securities and Exchange Commission in a timely manner.

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Index

Item 1B. Unresolved Staff Comments

None

Item 2. Properties

~~The Partnership’s~~Information ~~properties~~regarding (the ~~“Properties”)~~Partnership’s ~~consist~~wells, ofproduction, ~~working~~proved ~~interests~~reserves ~~in gas wells~~ and ~~the ownership in leasehold~~ acreage inare ~~the~~included ~~spacing units for the 23 wells drilled by the Partnership. The acreage associated with the spacing units is designated by state rules and regulations~~ in ~~conjunction with local practice. See the section titled~~ Item 1, ~~Business~~and ~~Drilling~~Note ~~Activities~~2, ~~and~~Summary ~~Plan~~ of ~~Operations~~Significant ~~for additional~~Accounting ~~information~~Policies, onto the Partnership’s ~~properties~~financial statements included in this report.

The Partnership commenced drilling activities immediately following funding on July 28, 2004. All wells were drilled by December 31, 2004 and drilling operations were completed in March 2005 when the last of the Partnership’s 23 productive development wells were connected to pipelines. The Partnership’s 23 gross wells represent 20.9 net wells, or the number of gross wells multiplied by the working interest in the wells owned by the Partnership. At December 31, 2008, all 23 Partnership wells were producing. Productive wells consist of producing wells and wells capable of producing oil and natural gas in commercial quantities. The 23 wells are the only wells to be drilled by the Partnership since all of the funds raised in the Partnership offering have been utilized. The details of these drilling areas are further outlined below.

The Wattenberg Field, located north and east of Denver, Colorado, is in the Denver-Julesburg (DJ) Basin. The typical well production profile has an initial high production rate and relatively rapid decline, followed by years of relatively shallow decline. Natural gas is the primary hydrocarbon produced; however, many wells will also produce oil. The purchase price for the natural gas may include revenue from the recovery of propane and butane in the gas stream, as well as a premium for the typical high-energy content of the natural gas. Wells in the area may include as many as four productive formations. From shallowest to deepest, these are the Sussex, the Niobrara, the Codell and the J Sand. The primary producing zone in most wells is the Codell sand which produces a combination of natural gas and oil. The Partnership has 16 wells located in this field.

The Grand Valley Field is in the Piceance Basin, located near the western border of Colorado. Wells in the Piceance Basin generally produce natural gas along with small quantities of oil. The producing interval consists of a total of 150 to 300 feet of productive sandstone divided in 10 to 15 different zones. The production zones are separated by layers of nonproductive shale resulting in a total interval of 2,000 to 4,000 feet with alternating producing and non-producing zones. The natural gas reserves and production are divided into these numerous smaller zones. The Partnership has seven wells located in this field.

Production

Production commenced during the fourth quarter of 2004, peaked at 352,000 Mcfe during the quarter ended June 30, 2005 and has continued to decrease as anticipated based on the projected production decline curves. A complete disclosure of quarterly production volumes, prices and sales is presented in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations in this report.

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Index

Oil and Natural Gas Reserves

All of the Partnership’s gas and oil reserves are located in the United States. The Partnership utilized the services of an independent petroleum engineer, Ryder Scott Company, L.P., for its 2008 and 2007 reserve reports. The independent engineer’s estimates are made using available geological and reservoir data as well as production performance data. The 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 interpretations and guidance. 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, oil and gas production, well test data, historical costs of operations and developments, product prices, or any agreements relating to current and future operations of properties and sales of production. The Partnership's independent reserve estimates are reviewed and approved by the Managing General Partner's internal engineering staff and management. See Supplemental Oil and Gas Information – Unaudited, Net Proved Oil and Gas Reserves for additional information regarding the Partnership’s reserves.

Title to Properties

The Partnership holds record title in its name to the working interest in each well. PDC provides an assignment of working interest for the well bore prior to the spudding of the well and effective the date of the spudding of the well, to the Partnership in accordance with the Drilling and Operation Agreement. Upon completion of the drilling of all of the Partnership wells, these assignments are recorded in the applicable county. Investor Partners rely on PDC to use its best judgment to obtain appropriate title to these working interests. Provisions of the Agreement relieve PDC from any error in judgment with respect to the waiver of title defects. PDC takes those steps it deems necessary to assure that title to the working interests is acceptable for purposes of the Partnership.

The Partnership's leases are direct interests in producing acreage. The Partnership believes it holds good and defensible title to its developed properties, in accordance with standards generally accepted in the oil and natural gas industry. As is customary in the industry, a perfunctory title examination was conducted by PDC at the time the undeveloped properties were acquired by PDC. Prior to the commencement of drilling operations, a title examination is conducted and curative work is performed with respect to discovered defects which are deemed to be significant. Title examinations have been performed with respect to substantially all of the Partnership's producing properties.

The Partnership’s properties are subject to royalty, overriding royalty and other outstanding interests customary to the industry. The properties may also be subject to additional burdens, liens or encumbrances customary to the industry. We do not believe that these burdens, liens or encumbrances, if any, will materially interfere with the use of the properties.

Item 3. Legal Proceedings

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

See Note 9, Commitments and Contingencies to the accompanying financial statements for additional information related to litigation.

-Item ~~22 -~~4. [Reserved]

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Index

Item 4. Submission of Matters to a Vote of Security Holders

None

PART II

Item 5.

Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

At ~~September~~ 30December 31, 2009, the Partnership had ~~664~~661 Investor Partners holding 899.94 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, 2009, the Managing General Partner has repurchased 1718.02 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 be able to sell them only for less than fair market value. No transfer of a unit may be made unless the transferee satisfies ~~any~~ relevant suitability requirements, as imposed by law or the Partnership. The Partnership may require that the transferor provide an opinion of legal counsel stating that the transfer complies with ~~all~~ applicable securities laws. A sale or transfer of units by an individual investor partner requires PDC’s, as Managing General Partner, prior written consent. For these and other reasons, an individual investor partner must anticipate that he or she will have to hold his or her partnership interests indefinitely and will not be able to liquidate his or her investment in the Partnership. Consequently, an individual investor partner must be able to bear the economic risk of investing in the Partnership for an indefinite period of time.

Cash Distribution Policy. PDC plans to make distributions of Partnership cash on a monthly basis, but no less often than quarterly, subject to funds being available for distribution. PDC will make cash distributions of 80% of available cash to the Investor Partners, ~~adjusted~~including ~~for~~ any Investor Partner units purchased by the Managing General Partner, and 20% of available 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 interest in the net income of the Partnership.

PDC cannot presently predict amounts of future cash distributions, if any, from the Partnership. However, PDC expressly conditions any distribution upon the Partnership having sufficient cash available for distribution. Sufficient cash available for distribution is defined to generally mean cash generated by the Partnership in excess of the amount the Managing General Partner determines is necessary or appropriate to provide for the conduct of the Partnership's business, to comply with applicable law, to comply with any other agreements or to provide for future distributions to unit holders. In this regard, PDC reviews the accounts of the Partnership at least quarterly for the purpose of determining the sufficiency of distributable cash available for distribution. Amounts will be paid to Investor Partners only after payment of fees and expenses to the Managing General Partner and its affiliates and only if there is sufficient cash available. The ability of the Partnership to make or sustain cash distributions depends upon numerous factors. PDC can give no assurance that any level of cash distributions to the Investor Partners of the Partnership will be attained, that cash distributions will equal or approximate cash distributions made to investor partners of prior drilling programs sponsored by PDC, or that any level of cash distributions can be maintained. ~~The Partnership made cash distributions of $2,972,261 and $2,395,447 for the years ended December 31, 2008 and 2007, respectively, and a total of $17,087,643 since inception.~~

The ~~volume~~ offollowing ~~production~~table ~~from~~presents ~~producing properties naturally declines with the passage of time and is not subject to the control of management. The~~ cash ~~flow~~distributions ~~generated~~made ~~by the Partnership's activities and the amounts available for distribution~~ to the Partnership'’s ~~Investor~~investors ~~Partners will, therefore, decline in the absence of significant increases in the prices that the Partnership receives~~ for ~~its oil and natural gas production, or significant increases in~~ the ~~production~~ ofperiods oil and natural gas from the successful additional development of these properties, if any. If the Partnership decides to develop its wells further, the funds necessary for that development would come from the Partnership's revenues. As a result, there may be a decrease in the funds available for distribution, and the distributions to the Investor Partners may decrease.described:

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Period	Cash Distributions

For the year ended December 31, 2009	$	2,381,883
For the year ended December 31, 2008		2,972,261

For the period from the Partnership's inception to December 31, 2009	$	19,469,526

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Index

~~Unit~~The ~~Repurchase Program. Beginning~~volume of production from producing properties naturally declines with the ~~third~~passage ~~anniversary~~ of time and is not subject to the ~~date~~control of ~~the~~ ~~first~~management. The cash flow generated by the Partnership's activities and the amounts available for distribution ofto the Partnership,'s Investor Partners ofwill, ~~the Partnership~~therefore, ~~may~~decline ~~request~~in the ~~Managing~~absence ~~General~~of ~~Partner~~significant toincreases ~~repurchase~~in ~~their~~the ~~units. The~~prices that the Partnership ~~initiated~~receives ~~monthly~~for ~~cash~~its ~~distributions~~oil toand ~~Investor~~natural ~~Partners~~gas production, or significant increases in ~~February~~ ~~2005. If~~the ~~requested~~production byof ~~individual~~oil ~~investor~~and ~~partners,~~natural gas from the ~~Managing~~ ~~General~~successful ~~Partner~~additional isdevelopment ~~conditionally~~of ~~obligated~~these properties, if any. If the Partnership decides to ~~purchase~~develop inits ~~any~~wells ~~calendar year~~further, ~~units~~the ~~which~~funds ~~aggregate~~necessary upfor tothat ~~10%~~development ofwould come from the ~~initial subscriptions~~Partnership's revenues. ~~Repurchase~~As ofa ~~units~~result, isthere ~~subject~~may tobe ~~PDC’s~~a ~~financial ability~~decrease toin ~~purchase~~the funds available for distribution, and the ~~units~~distributions to the Investor Partners may decrease. ~~The~~For ~~purchase~~more ~~price~~information ~~will~~concerning ~~not~~the bePartnership’s ~~less than~~cash ~~four~~flows ~~times~~from ~~the~~operations ~~most~~see ~~recent~~Item ~~twelve~~7, ~~months~~Management’s ~~cash~~Discussion ~~distributions~~and ~~from production~~Analysis of ~~the~~Financial ~~Partnership~~Condition and Results of Operations−Liquidity and Capital Resources.

InUnit ~~the first~~Repurchase ~~quarter~~Program. Investor ofPartners ~~2008,~~may request that the Managing General Partner ~~repurchased~~repurchase aunits ~~total~~at ofany ~~0.5 units~~time ~~during~~beginning ~~February~~with ~~2008,~~ the ~~first~~third ~~month~~anniversary ~~unit~~of ~~repurchases~~the ~~were~~first ~~eligible~~cash ~~under the~~distribution ~~program,~~of atthe anPartnership. The ~~average~~repurchase price ofis ~~$9,230~~set ~~per~~at ~~unit~~a ~~and~~minimum ~~0.25~~of ~~units~~four ~~during~~times ~~March 2008~~the atmost anrecent ~~average~~twelve ~~price~~months of ~~$7,340~~cash ~~per~~distributions ~~unit~~from production. ~~Second~~In ~~quarter~~any ~~unit repurchases~~calendar ~~included~~year, the ~~April~~Managing ~~2008~~General ~~repurchase~~Partner ofis ~~0.5~~conditionally ~~units~~obligated atto anpurchase ~~average~~Investor ~~price per~~Partner ~~unit~~units ofaggregating ~~$7,330~~to ~~and~~10% ~~May~~of ~~2008~~the ~~repurchases~~initial ofsubscriptions ~~0.25~~if ~~units~~requested atby an ~~average~~individual ~~price per~~investor ~~unit of $7~~partner,~~520. Remaining~~ ~~2008~~subject ~~repurchases~~to ~~were~~its ~~comprised~~financial ~~of fourth~~ability ~~quarter~~to ~~repurchases~~do ofso ~~1.0~~and ~~unit~~upon atreceipt anof ~~average~~opinions ~~price~~ of ~~$9,295~~counsel ~~per~~that ~~unit~~the ~~in October~~repurchase ~~and~~will ~~2.5~~not ~~units~~cause atthe anPartnership ~~average~~to ~~price~~be oftreated ~~$9,748~~as ~~per~~a ~~unit~~“publically ~~in December. First~~traded ~~quarter~~partnership” ~~2009~~or ~~unit~~result ~~repurchases~~in ~~include~~the ~~1.0~~termination ~~unit repurchased~~of atthe anPartnership ~~average~~for ~~price~~federal ofincome ~~$10,345~~tax ~~per~~purposes. Repurchase ~~unit~~requests ~~during~~are ~~February~~fulfilled ~~and~~by ~~0.5 units~~the ~~repurchased~~Managing atGeneral anPartner ~~average~~on ~~price~~a ~~of $10~~first-come,~~670~~ ~~per~~first-serve ~~unit during March~~basis. ~~Second~~There ~~quarter repurchases in April 2009,~~ were ~~4.25~~no ~~units repurchased~~limited atpartner anunit ~~average~~repurchases ~~price~~by ofthe ~~$10,794~~Managing ~~per~~General ~~unit. There~~Partner ~~have~~during ~~been no~~the ~~third~~three ~~quarter~~months ~~unit~~ended ~~repurchases~~December ~~through~~31, ~~July~~ 2009.

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

Item 6. Selected Financial Data

Not applicable

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis, as well as other sections in this Form 10-K, should be read in conjunction with the Partnership’s accompanying financial statements and related notes to the financial statements included in this report. Further, the Partnership encourages ~~you~~the reader to revisit the Special Note Regarding Forward-Looking Statements on page 1 of the report.

Partnership Overview

~~The Partnership~~PDC ~~was~~2004-B ~~funded~~Limited onPartnership ~~July~~engages 2,in ~~2004~~the ~~with~~development, ~~initial~~production ~~contributions~~and sale of ~~$18~~oil and natural gas.~~0 million~~ The ~~from~~Partnership ~~the~~began ~~Investor~~oil ~~Partners~~and gas operations in July 2004 and acurrently ~~cash~~operates ~~contribution~~23 ofgross $4(20.09 ~~million~~net) ~~from~~ wells located in the state of Colorado. The Managing General Partner~~. After~~ ~~payment~~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 ~~syndication~~natural ~~costs~~gas sold varies as a result of $1 market forces.8 PDC, ~~million~~on ~~and~~behalf aof ~~one~~the Partnership through the D&O Agreement, may enter into multi-~~time~~year ~~management~~contracts ~~fee~~which generally have monthly index-based pricing provisions, or utilize derivatives, including collars, swaps or basis protection swaps, in order to ~~PDC~~offset some or all of $0the commodity price variability for particular periods of time.3 Seasonal ~~million~~factors, ~~the Partnership~~such ~~had~~as ~~available~~effects ~~cash~~of weather on prices received and costs incurred, and availability of ~~$19.9~~pipeline ~~million~~capacity, toowned ~~commence~~by PDC or other third parties, may impact the Partnership's ~~oil~~results. In addition, both sales volumes and ~~natural~~ ~~gas~~prices ~~well~~could ~~drilling~~be ~~activities~~affected by demand factors .

The Partnership’s ~~began~~wells ~~exploration~~will ~~and~~produce ~~development~~until ~~activities~~they ~~immediately~~are ~~after funding. In~~depleted ~~July~~or ~~2004,~~until ~~PDC~~they ~~commenced~~are ~~drilling~~uneconomical onto ~~behalf~~produce; ofhowever, ~~the~~ Partnership~~. As~~ ofwell ~~December~~recompletions ~~31,~~in ~~2008,~~the aCodell ~~total~~formation of 23Wattenberg Field wells ~~have~~may ~~been drilled~~provide infor ~~Colorado,~~additional ~~all~~reserve ofdevelopment ~~which~~and ~~are producing~~production. These 23well ~~wells~~recompletions ~~are the~~generally ~~only~~occur ~~wells~~five ~~the~~to ~~Partnership~~ten ~~will~~years ~~drill~~after ~~because~~initial ~~all~~well ofdrilling ~~the~~so ~~capital contributions~~that ~~have~~well ~~been~~resources ~~utilized. The~~are ~~completed~~optimally ~~wells~~utilized ~~produce primarily~~and ~~natural~~would ~~gas,~~be ~~with~~expected ~~some~~to ~~associated~~occur ~~crude~~within ~~oil. Sales~~a ~~of produced~~favorable ~~natural~~general ~~gas~~economic environment and ~~oil~~commodity ~~commenced~~price ~~during~~structure. The ~~the~~Managing ~~fourth~~General ~~quarter~~Partner ofhas ~~2004~~developed ~~as wells~~a ~~were~~plan ~~connected~~ to ~~pipelines. Production~~initiate ~~and~~recompletion ~~sales~~activities ~~increased through~~during ~~the~~2010. This ~~first~~plan ~~two~~includes ~~quarters~~notifying ofinvestor ~~2005~~partners asthat ~~additional~~funds ~~wells~~to ~~were~~begin ~~completed~~these ~~and connected~~recompletions towill ~~pipelines. As~~be ~~expected~~withheld ~~for~~from ~~wells~~future indistributable ~~this~~cash ~~area,~~flows of the Partnership ~~has~~resulting ~~recognized~~from aboth ~~steady~~current ~~decline in quarterly~~ production and ~~net sales. The~~any ~~Partnership’s~~increased ~~wells~~production ~~will~~due ~~produce~~to ~~until~~recompletion ~~they~~activities. Both ~~are~~the ~~depleted or~~number ~~until~~of ~~they~~recompletions ~~are~~and ~~uneconomical~~the totiming ~~produce;~~of ~~however,~~recompletions itwill isbe ~~generally,~~based on the ~~plan~~availability of ~~the~~ ~~Partnership~~cash ~~and~~withheld ~~the~~from distributions. The Managing General Partner tobelieves ~~recomplete~~that, ~~the~~based ~~Codell formation~~on inprojected ~~certain~~recompletion ~~wells~~costs inand ~~the~~projected ~~Wattenberg~~cash ~~Field~~withholding, ~~after~~all ~~five~~partnership orrecompletions ~~more~~can ~~years~~be ~~of production~~completed. Current ~~because~~estimated ~~these~~costs ~~wells~~for ~~will~~these ~~have~~well ~~experienced~~recompletions ais ~~significant~~between ~~decline~~$150,000 ~~in production~~and in$200,000 ~~that~~per ~~time period~~recompletion. ~~However,~~ As the ~~exact~~optimal ~~timing~~period ~~of recompletion~~approaches, ~~may~~the beManaging ~~delayed~~General orPartner ~~accelerated~~will ~~due~~re-evaluate ~~to changing commodity prices and~~ the ~~availability~~feasibility of ~~additional~~commencing ~~geological~~those ~~data and technology. Codell~~ recompletions ~~typically~~based ~~increase~~on ~~production~~engineering ~~rates~~data and ~~recoverable reserves. Although~~a ~~PDC~~favorable ~~has~~commodity ~~experienced~~price ~~significant~~environment ~~production increases~~in ~~following~~order ~~prior~~to ~~Codell~~maximize ~~recompletions,~~the ~~not~~financial ~~all~~benefit ~~such~~of ~~recompletions~~the ~~have been successful~~recompletion.

- 24 16 -

Index

~~2008~~ 2009 Overview

~~The~~Even ~~year 2008~~with ~~was~~natural agas ~~year~~prices rebounding somewhat in the last two months of ~~significant~~2009 ~~events:~~from ~~oil~~earlier ~~and~~in ~~natural~~the ~~gas~~year, ~~prices~~the ~~reached~~Partnership continued to ~~record~~ ~~and~~experience ~~near~~a ~~record~~depressed ~~highs,~~natural ~~respectively,~~gas ~~through~~commodity ~~July;~~pricing ~~then,~~market inthroughout ~~the~~2009 ~~midst~~compared ~~of U~~to 2008.S. The ~~credit~~Partnership’s ~~turmoil~~production ~~and~~decreased ato ~~worldwide~~395 ~~economic~~MMcfe ~~slump,~~for inthe ~~December,~~2009 ~~oil~~annual ~~prices~~period ~~fell~~ compared to ~~their~~504 ~~lowest~~MMcfe infor ~~four~~the ~~years~~same ~~and~~2008 ~~natural~~period, ~~gas~~a ~~prices~~decrease ~~decreased~~of ~~approximately 50~~22%. ~~While~~The ~~the~~ Partnership’s ~~felt~~average ~~the~~sales ~~impact~~price offor ~~these~~2009 ~~events~~declined to $3.58 per Mcfe, ~~the Managing~~a ~~General~~decrease ~~Partner~~of ~~believes~~52% from the ~~Partnership~~annual ~~was~~sales ~~successful~~price ina ~~managing~~year ~~its operations~~ago, While the significant changes in ~~such~~commodity aprices ~~manner~~have ~~that~~impacted the Partnership’s ~~was~~results ~~able~~of tooperations, ~~minimize~~the Managing General Partner believes that managing the ~~negative~~ ~~price~~Partnership’s ~~impacts~~operations ~~while~~by ~~capitalizing~~partially onreducing the ~~positive~~negative impacts of ~~price~~lower ~~risk management~~prices ~~using~~through ~~derivatives. The~~the Partnership’s derivative ~~position eased~~positions ~~the~~was ~~impact~~successful. Although of the ~~fall~~Partnership’s in2009 ~~oil~~natural gas and ~~natural~~sales ~~gas~~revenues ~~prices~~declined by $2. ~~During~~ 3 million compared to 2008, the Partnership’s ~~recorded~~annual cash flows provided by operating activities declined by only $0.17 million, or 23%, primarily benefited by the increase in ~~net~~the Partnership’s realized derivative gains~~. Further,~~ for the ~~Partnership~~2009 ~~estimates~~annual period to $1.2 million and the ~~net~~reduction ~~fair~~in ~~value~~“Due offrom ~~its derivative~~Managing ~~positions~~General asPartner –Other, Net” of ~~December~~$0.8 ~~31,~~million. These ~~2008~~realized toderivative begains added $13.208 ~~million~~per Mcfe to the Partnership’s average sales price noted above.

~~The decline~~- in17 market prices during the fourth quarter of 2008 resulted in $1.3 million in unrealized gains on derivatives for the year ended December 31, 2008. The $1.3 million in unrealized gains for the year is the fair value of the derivative positions as of December 31, 2008 of $1.2 million, less the fair value of derivative positions as of December 31, 2007 of $(0.1) million. There may be further gains or losses as prices decrease or increase until the positions mature or are closed.-

The required accounting treatment for derivatives that do not qualify for hedge accounting treatment under SFAS No. 133 may result in significant swings in operating results over the life of the derivatives. The combination of the settled derivative contracts and the revenue received from the oil and gas sales at delivery are expected to result in a more predictable cash flow stream and Partnership distributions than would the sales contracts without the associated derivatives.

The average NYMEX and CIG prices for the next 24 months (forward curve) from the respective dates below are as follows:

		December 31,		June 30,		December 31,		June 30,
Commodity	Index	2007		2008		2008		2009
Natural gas: (per MMbtu)
	NYMEX	$	8.12	$	12.52	$	6.62	$	5.83
	CIG		6.78		8.86		4.49		4.87
Oil: (per Bbl)	NYMEX		90.79		140.15		57.49		74.51

The commodity price declines from June 30, 2008, through December 31, 2008, relative to the Partnership’s current derivative positions, resulted in the significant unrealized derivative gains in 2008. If there are further price declines in 2009, unrealized derivatives gains on our current positions may be expected to continue. Conversely, if there are price increases in 2009, unrealized derivatives losses on our current positions may be expected to occur.

- 25 -

Index

Results of Operations

~~The following~~Summary ~~table~~Operating sets forth selected information regarding the Partnership’s results of operations, including production volumes, oil and gas sales, average sales prices received, average sales price including realized derivative gains and losses, production and operating costs, depreciation, depletion and amortization costs, other operating income and expenses for the years ended December 31, 2008 and 2007.Results

	Year Ended			Year Ended
	December 31, 2008			December 31, 2007			Change
Number of producing wells (end of period)		23			23			-
Production: (1)
Oil (Bbl)		9,672			12,961			-25	%
Natural gas (Mcf)		446,018			463,307			-4	%
Natural gas equivalents (Mcfe) (2)		504,050			541,073			-7	%
Average Selling Price (excluding realized gain (loss) on derivatives)
Oil (per Bbl)	$	89.15		$	58.04			54	%
Natural gas (per Mcf)		6.51			4.89			33	%
Natural gas equivalents (per Mcfe)		7.47			5.58			34	%
Realized Gain (Loss) on Derivatives, net
Oil derivatives - realized loss	$	(45,042	)	$	(3,604	)		*
Natural gas derivatives - realized gain		115,356			175,512			-34	%
Total realized gain on derivatives, net	$	70,314		$	171,908			-59	%
Average Selling Price (including realized gain (loss) on derivatives)
Oil (per Bbl)	$	84.49		$	57.76			46	%
Natural gas (per Mcf)		6.76			5.27			28	%
Natural gas equivalents (per Mcfe)		7.61			5.90			29	%
Average cost per Mcfe
Production and operating costs (3)	$	1.79		$	1.44			24	%
Depreciation, depletion and amortization		2.77			2.57			8	%
Revenues:
Oil and gas sales	$	3,763,882		$	3,019,510			25	%
Oil and gas price risk management, net		1,324,026			(171,459	)		*
Total revenues	$	5,087,908		$	2,848,051			79	%
Operating costs and expenses:
Production and operating costs	$	901,832		$	776,600			16	%
Direct costs - general and administrative		102,909			49,037			110	%
Depreciation, depletion and amortization		1,397,701			1,388,803			1	%
Accretion of asset retirement obligations		8,780			8,304			6	%
Total operating costs and expenses	$	2,411,222		$	2,222,744			8	%
Income from operations	$	2,676,686		$	625,307			328	%
Interest income		38,335			49,440			-22	%
Net income	$	2,715,021		$	674,747			302	%
Cash distributions	$	2,972,261		$	2,395,447			24	%

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

* Percentage change not meaningful, equal to or greater than 250% or not calculable.

	Year Ended December 31,
	2009		2008			Change
Number of producing wells (end of period)		23		23			*

Production (1)
Natural gas (Mcf)		339,510		446,018			-24	%
Oil (Bbl)		9,273		9,672			-4	%
Natural gas equivalents (Mcfe) (2)		395,148		504,050			-22	%
Mcfe per day		1,083		1,381			-22	%

Natural Gas and Oil Sales
Natural gas	$	919,090	$	2,901,668			-68	%
Oil		493,674		862,214			-43	%
Total natural gas and oil sales	$	1,412,764	$	3,763,882			-62	%

Realized Gain (Loss) on Derivatives, net
Natural gas	$	1,060,717	$	115,356			*
Oil		160,141		(45,042	)		*
Total realized gain on derivatives, net	$	1,220,858	$	70,314			*

Average Selling Price (excluding realized gain (loss) on derivatives)
Natural gas (per Mcf)	$	2.71	$	6.51			-58	%
Oil (per Bbl)	$	53.24	$	89.15			-40	%
Natural gas equivalents (per Mcfe)	$	3.58	$	7.47			-52	%

Average Selling Price (including realized gain (loss) on derivatives)
Natural gas (per Mcf)	$	5.83	$	6.76			-14	%
Oil (per Bbl)	$	70.51	$	84.49			-17	%
Natural gas equivalents (per Mcfe)	$	6.66	$	7.61			-12	%

Average cost per Mcfe
Natural gas and oil production cost (3)	$	1.53	$	1.79			-14	%
Depreciation, depletion and amortization	$	3.34	$	2.77			20	%

Operating costs and expenses:
Direct costs - general and administrative	$	547,088	$	102,909			*
Depreciation, depletion and amortization	$	1,318,602	$	1,397,701			-6	%

Cash distributions	$	2,381,883	$	2,972,261			-20	%

-* ~~26 -~~Percentage change not meaningful, equal to or greater than 250% or not calculable. Amounts may not calculate due to rounding.

~~Index~~ _______________

(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)

Production costs represent oil and gas operating expenses which include production taxes.

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

~~Oil~~- ~~and~~18 ~~Natural Gas Sales~~-

The table below shows sales and production information for each quarter for the years ended December 31, 2008 and 2007. Oil and natural gas sales exclude the impact of commodity-based derivatives, which are reflected in the line “Oil and gas price risk management, net” in the statements of operations. (In thousands except for per Mcf, per Bbl and per Mcfe amounts and percentage changes).

	2008									2007
	Sales									Sales
Total	(in thousands)			MMcfe			per Mcfe			(in thousands)		MMcfe		per Mcfe
Jan-Mar	$	954			127		$	7.53		$	902		156	$	5.79
Apr-Jun		1,480			158			9.35			812		146		5.55
Jul-Sept		924			112			8.28			655		133		4.93
Oct-Dec		406			107			3.78			651		106		6.13
Total	$	3,764			504		$	7.47		$	3,020		541	$	5.58
Change (year over year)		25	%		-7	%		34	%

	2008									2007
	Sales									Sales
Oil	(in thousands)			MBbl			per Bbl			(in thousands)		MBbl		per Bbl
Jan-Mar	$	194			2		$	81.91		$	165		4	$	44.60
Apr-Jun		290			3			113.51			184		3		54.20
Jul-Sept		285			3			105.95			202		3		64.08
Oct-Dec		93			2			45.21			201		3		74.35
Total	$	862			10		$	89.15		$	752		13	$	58.04
Change (year over year)		15	%		-25	%		54	%

	2008									2007
	Sales									Sales
Natural Gas	(in thousands)			MMcf			per Mcf			(in thousands)		MMcf		per Mcf
Jan-Mar	$	760			113		$	6.75		$	737		133	$	5.52
Apr-Jun		1,190			143			8.32			628		126		4.99
Jul-Sept		639			95			6.70			453		114		3.98
Oct-Dec		313			95			3.29			450		90		5.00
Total	$	2,902			446		$	6.51		$	2,268		463	$	4.89
Change (year over year)		28	%		-4	%		33	%

The 25% increase in total sales in 2008 as compared to 2007 was due to an increase in average sales price per Mcfe of 34% partially offset by decreased total production volumes, in Mcfe or energy equivalency basis, of 7%.

Commodity price increases during the first half of 2008, which contributed to an increase in sales of $0.9 million, were partially offset by sales declines of $0.2 million due to decreased production volumes, resulting in the overall $0.7 million increase in oil and natural gas sales in 2008 as compared to 2007. This decline in production volumes is consistent with the historically declining production curves for wells drilled in the Wattenberg and Piceance fields. The year-to-year decrease in both oil and natural gas production volumes of 25% and 4%, respectively, reflects the historically steeper decline in oil production volumes during the earlier portions of the production life cycle as compared to natural gas which was offset, however, by a more substantial increase in oil prices (54%) than natural gas prices (33%) during the period.

- 27 -

Index

OnNatural ~~a quarterly~~Gas ~~basis, production volumes, on an energy equivalency basis, declined during the quarters ended March 31~~ and ~~September~~Oil 30, 2008, compared to the same periods in 2007. However, commodity price increases of $0.2 million and $0.4 million, respectively, offset production volume declines of $0.2 million and $0.1 million, respectively, so that overall sales remained unchanged and increased by $0.3 million, respectively, during these periods. During the quarter ended June 30, production increased due to a decrease in line pressure as new pipeline was added and more efficient routing of the gas was effected by Williams. This resulted in a production increase of $0.1 million and combined with commodity price increases of $0.6 million over the previous year’s comparable period, resulted in that quarter’s overall oil and natural gas sales increase of $0.7 million.Sales

~~Overall quarterly~~The 62% decrease in total sales ~~declined,~~in ~~however,~~2009 byas ~~$0.3~~compared ~~million,~~to ~~during~~2008 was due to the ~~quarter~~combined ~~ended December~~effects 31of decreased total production volumes, ~~2008~~on ~~over~~a ~~the~~Mcfe ~~previous~~or ~~year’s~~energy ~~fourth~~equivalency ~~quarter~~basis, ~~due~~of to22% ~~commodity price~~and ~~reductions~~a ofsignificantly ~~$0.3~~lower ~~million~~average ~~while~~sales ~~production~~price ~~volumes~~per ~~remained~~Mcfe, ~~substantially unchanged~~of ~~period-to-period~~52%.

~~The Partnership~~Commodity ~~expects~~price declines contributed $1.5 million while volume reductions added $0.8 million to ~~experience~~the ~~continued~~$2.3 ~~declines~~million decrease in ~~both~~ oil and natural gas sales in 2009 compared to the prior year. This change in production volumes ~~over~~is consistent with the ~~wells’~~historically ~~life~~declining ~~cycles~~production ~~until~~curves ~~such~~for ~~time~~wells ~~that~~drilled in the Wattenberg ~~wells~~and ~~may~~Grand beValley ~~successfully recompleted~~fields. ~~Subsequent~~The ~~to successful~~decrease ~~recompletion,~~in ifnatural ~~any,~~gas ~~production~~and ~~will~~oil ~~once~~sales ~~again~~revenue ~~begin~~was ~~to decline~~partially offset by realized derivative gains during 2009 of $1.2 million. See Commodity Price Risk Management, Net discussion below.

~~Oil~~The decrease in natural gas revenues of 68% contrasts to the more moderate reduction in oil revenues of 43%. The Partnership’s oil revenue decline was moderated by a reduction in average oil sales prices (40%) as compared to a reduction in natural gas sales prices (58%) during the period. The Partnership expects to experience continued declines in both oil and ~~Natural~~natural ~~Gas Pricing~~gas production volumes over the wells’ life cycles until the Wattenberg wells are recompleted.

~~Financial results depend upon many factors, particularly the prices of oil and natural gas and our ability to market our production effectively.~~ Natural ~~gas~~Gas and ~~oil~~ ~~prices~~Oil have been among the most volatile of all commodity prices. These price variations have a material impact on Partnership financial results. Natural gas and oil prices also vary by region and locality, especially in the Rocky Mountain Region, depending upon the distance to markets, and the supply and demand relationships in that region or locality. This can be especially true in the Rocky Mountain Region in which all of the Partnership’s wells are located. The combination of increased drilling activity and the lack of substantial local market demand can result in a local market oversupply situation from time to time. The Managing General Partner believes such a situation existed in the Rocky Mountain Region during 2007, with production exceeding the local market demand and pipeline transportation capacity to non-local markets. The result, beginning in the second quarter of 2007 and continuing into the fourth quarter of 2007, was a decrease in the price of Rocky Mountain natural gas as measured by the Colorado Interstate Gas, or CIG, Index (per MMbtu) compared to the New York Mercantile Exchange, or NYMEX, price (per MMbtu).Pricing

~~The expansion~~Financial inresults ~~January~~depend ~~2008~~upon ofmany ~~the Rockies Express pipeline (“REX”)~~factors, aparticularly ~~major interstate~~the ~~pipeline~~price ~~constructed and operated by a non-affiliated entity, resulted in a narrowing~~ of ~~the~~oil ~~NYMEX~~ and ~~CIG~~natural ~~price~~gas ~~differential~~and ~~to under $1.00 between~~ the ~~indices~~Partnership’s ~~average~~ability ~~prices~~to inmarket ~~January~~its ~~and~~production ~~February 2008~~effectively. ~~However,~~Oil aand ~~substantial~~natural ~~portion~~gas ofprices ~~the~~are ~~new~~among ~~capacity created by~~ the ~~REX~~most ~~Pipeline~~volatile isof ~~now~~all ~~under~~commodity ~~contract~~prices. These ~~resulting~~price invariations ahave ~~resumption of regional transportation capacity restraints and~~ a ~~widening~~material ofimpact on the ~~NYMEX-CIG~~Partnership’s ~~differential that~~financial ~~peaked~~results. Oil ~~in June~~ and ~~September~~natural atgas ~~average~~prices ~~index~~also ~~price~~vary ~~differentials~~by ofregion ~~$4.58~~ and ~~$4.00~~locality, ~~respectively. Index~~depending ~~differentials~~upon ~~closed~~the ~~2008~~distance ~~having again narrowed~~ to ~~$1.30~~markets, and ~~are expected to average $0.96 for~~ the ~~next~~supply 24and ~~months (forward~~demand ~~curve)~~relationships ~~based on index futures. Like most producers~~ in ~~the~~ that region, ~~the~~or Partnership relies on major interstate pipeline companies to construct these facilities to increase pipeline capacity, rendering the timing and availability of these facilities beyond the Partnership’s controllocality. InThis ~~view~~can ofbe ~~the~~especially ~~regional~~true transportation capacity issues cited herein regarding Rocky Mountain region production, the Partnership believes that the cited capacity constraints will continue into the future and that the sale of production in the Rocky Mountain Region ~~will continue to be governed by price~~. ToThe ~~that~~combination ~~end,~~of ~~the~~increased ~~Partnership~~drilling ~~has~~activity ~~been~~and ~~able~~the tolack ~~sell all~~ of ~~its production~~local tomarkets ~~date,~~ has ~~not~~resulted ~~had~~in toa ~~significantly~~local ~~curtail~~market ~~its~~oversupply ~~production~~situation ~~for~~from ~~long periods of~~ time ~~because of an inability~~ to ~~sell its production because of pipeline unavailability and believes that it will be able to sell all of its future production at market prices~~time.

~~Oil pricing~~The isprice ~~also~~the ~~driven~~Partnership ~~strongly~~receives byfor ~~supply~~the ~~and~~natural ~~demand relationships. In~~gas produced in the Rocky Mountain Region ~~for~~is ~~2008~~based on a variety of prices, ~~Partnership~~which ~~oil sales~~primarily ~~averaged~~includes ~~$89.15~~natural ~~per~~gas ~~barrel~~sold ~~which~~at isCIG ~~below~~prices ~~the~~with ~~NYMEX~~a ~~oil~~portion ~~market~~sold 12at Mid-~~month average~~Continent, ~~monthly~~San ~~closing~~Juan ~~prices~~Basin, ~~(per~~Southern ~~Barrel)~~California ~~for~~or ~~2008~~other ofnearby ~~$104~~region prices.42 The CIG Index, ~~due~~and toother ~~supply competition~~indices ~~from~~for production delivered to other Rocky Mountain ~~oil~~pipelines, has historically been less than the price received for natural gas produced in the eastern regions, which is NYMEX based primarily, because of the lack of interstate transmission capacity which moved Rocky Mountain natural gas production to Northeastern U.S. industrial and ~~Canadian~~heating ~~oil~~markets. This ~~that~~negative differential has ~~driven~~narrowed ~~down market~~in ~~prices~~recent months and for two out of the last four months become a slight positive differential, which contradicts historical variances.

-Like ~~28 -~~most producers in the region, the Partnership relies on major interstate pipeline companies to construct transmission facilities to increase pipeline capacity to Northeastern U.S and California markets, rendering the timing and availability of these facilities beyond the Partnership’s control. In view of the regional transportation capacity issues cited herein regarding Rocky Mountain regional production, the Partnership believes that pipeline capacity constraints, although significantly moderated, will continue into the immediate future and that the sale of production in the Rocky Mountain Region will continue to be influenced by price. To that end, the Partnership has been able to sell all of its production to date, has not had to significantly curtail its production for long periods of time because of an inability to sell its production because of pipeline deliverability constraints and believes that it will be able to sell all of its future production at market prices.

- 19 -

Index

~~The~~Commodity ~~price the~~Price ~~Partnership~~Risk ~~receives for the natural gas produced in the Rocky Mountain Region is based on a market basket of prices~~Management, which primarily includes natural gas sold at the CIG prices with a portion sold at Mid-Continent, San Juan Basin, Southern California or other nearby region prices. The CIG Index, and other indices for production delivered to other Rocky Mountain pipelines, has historically been less than the price received for natural gas produced in the eastern regions, which is NYMEX based.Net

~~Through September~~Natural ~~2009~~Gas and Oil Sales Derivative Instruments. The Managing General Partner on behalf of the Partnership through the D&O Agreement, uses various derivative instruments to manage fluctuations in oil and natural gas prices. The ~~have~~Partnership ~~continued~~has toin ~~fluctuate~~place, ~~with~~a ~~oil prices~~series of collars, fixed-price swaps and basis swaps on ~~NYMEX~~a asportion ~~high~~of asthe ~~$74~~Partnership’s natural gas and oil production.37 Under ~~(per~~the ~~Barrel)~~Partnership’s oncollar ~~August~~arrangements, 24if the applicable index rises above the ceiling price, ~~2009~~the ~~and~~Managing asGeneral ~~low~~Partner ~~as $33~~pays the counterparty; however, if the index drops below the floor price, the counterparty pays the Managing General Partner.98 Under ~~(per~~the ~~Barrel)~~Partnership’s oncommodity ~~February~~swap 12arrangements, ~~2009~~if ~~and~~the applicable index rises above the swap price, the Managing General Partner pays the counterparty; however, if the index drops below the swap price, the counterparty pays the Managing General Partner. Under the Partnership’s basis protection swaps, if the differential widens, then the counterparty pays the Managing General Partner; however, if the differential narrows, then the Managing General Partner pays the counterparty. Because the Partnership sells all of its physical natural gas ~~prices~~and onoil ~~CIG~~at assimilar ~~high as~~prices ~~$4.59~~to ~~(per~~the ~~MMbtu)~~indexes oninherent ~~January~~in 7the Partnership’s derivative instruments, ~~2009~~the Partnership ultimately realizes a price related to its collars of no less than the floor and asno ~~low~~more asthan $1the ceiling and, for the Partnership’s commodity swaps, the Partnership ultimately realizes the fixed price related to its swaps.33 The ~~(per~~following ~~MMbtu)~~table onpresents ~~April 14~~the Partnership’s commodity price risk management (loss) gain, ~~2009~~net.

Oil and Natural Gas Price Risk Management, Net

	Year Ended December 31,
	2009			2008
Realized gains (losses)
Oil	$	160,141		$	(45,042	)
Natural Gas		1,060,717			115,356
Total realized gain, net		1,220,858			70,314

Unrealized gains (losses)
Reclassification of realized (gains) losses included in prior periods unrealized		(995,594	)		38,450
Unrealized (loss) gain for the period		(765,148	)		1,215,262
Total unrealized (loss) gain, net		(1,760,742	)		1,253,712
Commodity price risk management (loss) gain, net	$	(539,884	)	$	1,324,026

~~The Managing~~Realized ~~General~~gains ~~Partner~~recognized ~~uses~~in ~~oil~~2009 ~~and~~of ~~natural~~$1.2 ~~gas~~million ~~commodity~~are ~~derivative instruments~~a toresult ~~manage~~of ~~price~~lower ~~risk~~natural ~~for~~gas ~~PDC~~and asoil ~~well~~commodity asprices ~~its~~at ~~sponsored~~settlement ~~drilling partnerships. The~~compared ~~Managing~~to ~~General Partner sets these instruments for PDC and~~ the ~~various~~respective ~~partnerships~~strike ~~managed by PDC jointly by area of operations~~price. ~~Prior~~During ~~to September 30~~2009, ~~2008,~~the asPartnership ~~production~~recorded ~~volumes changed,~~unrealized ~~the~~derivative ~~allocation~~losses of ~~derivative~~$1.0 ~~positions~~million ~~between~~on ~~PDC~~the Partnership’s ~~corporate interests~~CIG ~~and each of the sponsored drilling partnerships changed on a pro-rata~~ basis~~. As~~ ~~of September 30~~swaps, ~~2008,~~as ~~PDC has fixed~~ the ~~allocation~~forward ~~of derivative~~basis ~~positions,~~differential between ~~PDC~~NYMEX and ~~each~~CIG ~~partnership.~~continued ~~Existing~~to ~~positions~~narrow ~~are allocated based on fixed quantities for each position~~ and ~~new~~became ~~positions~~a ~~will have~~positive ~~specific~~differential ~~designations~~as ~~relative~~of toDecember ~~the~~31, ~~applicable partnership. Realized~~2009, and unrealized ~~gains~~derivative ~~and~~ losses ~~resulting~~of ~~from derivative~~$0.1 ~~positions~~million ~~are reported~~ on the ~~statement~~Partnership’s ofoil ~~operations~~positions, asboth ~~“Oil~~of ~~and~~which ~~gas price~~were ~~risk~~offset ~~management,~~by ~~net.” The~~unrealized ~~net~~derivative gains~~/losses~~ ~~are comprised~~ of ~~the~~ ~~change~~$0.3 inmillion ~~fair~~on ~~value of derivative positions related to~~ the Partnership’s ~~production~~ ~~and~~natural ~~underlying~~gas ~~derivative contracts entered into by the Managing General Partner on behalf of the Partnership~~positions.

In periods of rising prices, the Partnership will generally record losses on its derivative positions as fair values exceed contract prices determining the Partnership’s oil and natural gas sales. Conversely, in periods of decreasing prices, the Partnership will generally recognize gains on its ~~derivative~~ ~~positions. During 2008, the Partnership experienced volatility in oil and gas prices that resulted in fluctuation in both realized and unrealized~~ derivative positions.

~~The following~~Commodity ~~table~~price ~~presents~~risk ~~the~~management, ~~realized~~net ~~and~~includes ~~unrealized~~realized gains and losses ~~recorded for~~and ~~each~~unrealized changes in the fair value of derivative instruments related to the ~~quarterly~~Partnership’s natural gas and ~~annual~~oil ~~periods~~production. See ~~identified:~~Note 4, Fair Value of Financial Instruments, and Note 5, Derivative Financial Instruments, to the accompanying financial statements for additional details of the Partnership’s derivative financial instruments.

	Three months ended
	March 31, 2008			June 30, 2008			September 30, 2008			December 31, 2008			Total
Realized gains (losses)
Oil	$	(10,885	)	$	(45,232	)	$	(37,585	)	$	48,660		$	(45,042	)
Natural gas		(24,010	)		(237,628	)		75,399			301,595			115,356
Realized (loss) gain		(34,895	)		(282,860	)		37,814			350,255			70,314
Unrealized (loss) gain		(363,931	)		(566,693	)		1,627,955			556,381			1,253,712
Oil and gas price risk management, net	$	(398,826	)	$	(849,553	)	$	1,665,769		$	906,636		$	1,324,026
	Three months ended
	March 31, 2007			June 30, 2007			September 30, 2007			December 31, 2007			Total
Realized gains (losses)
Oil	$	(1,422	)	$	(1,552	)	$	(449	)	$	(181	)	$	(3,604	)
Natural gas		(6,228	)		53,992			99,166			28,582			175,512
Realized (loss) gain		(7,650	)		52,440			98,717			28,401			171,908
Unrealized (loss) gain		(141,498	)		54,023			(21,128	)		(234,764	)		(343,367	)
Oil and gas price risk management, net	$	(149,148	)	$	106,463		$	77,589		$	(206,363	)	$	(171,459	)

- 20 -

“Oil and gas price risk management, net” includes realized gains and losses and unrealized changes in the fair value of oil and natural gas derivatives related to Partnership oil and natural gas production. See and Note 4, Fair Value of Financial Instruments and Note 5, Derivative Financial Instruments, to the accompanying financial statements for additional details of the Partnership’s derivative financial instruments.

- 29 -

Index

For the year ended December 31, 2008, the Partnership recorded realized gains of $0.1 million and unrealized gains of $1.2 million, resulting in a net $1.3 million gain for the year. During the quarter ended March 31, 2008, prices increased and remained above December 31, 2007 prices resulting in unrealized losses of $0.4 million. The ~~CIG-index~~following ~~monthly~~table ~~average~~presents ~~of daily natural gas prices (per MMbtu) and oil prices on NYMEX (per barrel) in~~ the ~~second~~ quarter 2008 remained above December 31, 2007 levels, resulting in the $0.3 million realized and $0.6 million unrealized losses for that period. Although Rocky Mountain Region oil and natural gas prices increased during the first seven months of 2008, the Partnership ~~experienced significant commodity price declines during the last five months of 2008, relative to the Partnership~~’s ~~current~~ derivative positions, ~~which resulted~~ in ~~significant unrealized~~effect ~~derivative~~as ~~gains for the year and for the quarters ended September 30 and December 31. Monthly averages~~ of ~~daily natural gas prices for the months August through~~ December ~~declined in August to $5.45 and retrenched further to a low during October of $2.90. Oil prices experienced a steep decline from a July 2008 high of $145.29 to $44.60 at December~~ 31, ~~2008. This~~ ~~pricing pattern in the Rocky Mountain Region for oil and natural gas resulted in the Partnership’s third quarter unrealized gains of $1~~2009.7 million and fourth quarter realized and unrealized gains of $0.4 million and $0.5 million, respectively. When forward prices for oil and natural gas decrease as they did throughout the last five months of 2008, the Partnership’s derivative positions, which include floors, ceilings and swaps, tend to increase in value, resulting in unrealized gain positions.

In 2007, the Partnership incurred a realized gain of $0.2 million and an unrealized loss of $0.4 million, resulting in a $0.2 million net loss for the year. The majority of the unrealized losses recognized for 2007 and for the quarters ended March 31 and December 31, respectively, were due to increasing natural gas prices. The decline in the CIG market during the second and third quarters of 2007, which fell to a low of $1.05 for the September average of natural gas daily prices (per MMbtu), resulted in the realized gain during 2007. When forward prices for oil and natural gas prices increase as they did in 2007, the Partnership’s derivative portfolio tends to decrease in value, resulting in unrealized loss positions. Due to the continued volatility of commodity prices, large quarter to quarter fluctuations in “Oil and gas price risk management, net” occur.

	Collars						Fixed-Price Swaps				CIG Basis Protection Swaps
	Quantity (Gas-Mmbtu)		Weighted Average Contract Price				Quantity (Gas-Mmbtu Oil-Bbls)		Weighted Average Contract Price		Quantity (Gas-Mmbtu)		Weighted Average Contract Price			Fair Value at December 31, 2009(1)
Commodity/ Index	Quantity (Gas-Mmbtu)		Floors		Ceilings		Quantity (Gas-Mmbtu Oil-Bbls)		Weighted Average Contract Price		Quantity (Gas-Mmbtu)		Weighted Average Contract Price			Fair Value at December 31, 2009(1)

Natural Gas
CIG
1Q 2010		42,039	$	7.50	$	7.50		29,532	$	9.20		-	$	-		$	204,968
4Q 2010		19,326		4.75		9.45		-		-		-		-			3,471
2011		28,989		4.75		9.45		-		-		-		-			1,658

NYMEX
2Q 2010		-		-		-		66,328		5.55		67,729		(1.88	)		(97,416	)
3Q 2010		-		-		-		65,381		5.55		66,914		(1.88	)		(112,000	)
4Q 2010		7,747		5.75		8.30		38,101		6.10		46,404		(1.88	)		(63,187	)
2011		10,536		5.75		8.30		205,149		6.77		215,685		(1.88	)		(174,844	)
2012		16,124		6.00		8.27		211,826		6.98		227,947		(1.88	)		(169,105	)
2013		-		-		-		211,753		7.12		211,753		(1.88	)		(148,753	)
Total Natural Gas		124,761						828,070				836,432					(555,208	)

Oil
NYMEX
1Q 2010		-		-		-		1,208		92.96		-		-			15,440
2Q 2010		-		-		-		1,224		92.96		-		-			13,696
3Q 2010		-		-		-		1,236		92.96		-		-			12,201
4Q 2010		-		-		-		1,236		92.96		-		-			10,728
2011		-		-		-		2,822		70.75		-		-			(42,530	)
Total Oil		-						7,726				-					9,535

Total Natural Gas and Oil																$	(545,673	)

~~Oil~~(1) ~~and~~Approximately ~~Natural~~48% ~~Gas~~of ~~Sales~~the ~~Derivative Instruments. The~~total ~~Managing~~fair ~~General~~value ~~Partner~~of ~~uses~~the ~~various~~ derivative ~~instruments~~assets toand ~~manage~~98% ~~fluctuations~~of inliabilities ~~oil~~were ~~and~~measured ~~natural~~using ~~gas prices. The~~significant ~~Managing~~unobservable ~~General~~inputs. ~~Partner~~See ~~has~~Note in4, ~~place~~Fair aValue ~~series of collars~~Measurements, ~~fixed~~to ~~price swaps and basis protection swaps on a portion of~~ the ~~Partnership’s~~ ~~oil~~accompanying ~~and~~financial ~~natural~~statements ~~gas~~included ~~production, as set forth~~ in ~~the~~this ~~following table~~report.

~~This table~~Natural ~~identifies~~Gas ~~the Partnership’s derivative positions related to oil~~ and ~~gas sales~~Oil ~~activities~~Production ~~in effect as of June 30, 2009, on the Partnership’s production.~~Costs

	Collars								Fixed-Price Swaps				Basis Protection Swaps
	Floors				Ceilings
			Weighted				Weighted				Weighted				Weighted		Fair Value
Commodity/	Quantity		Average		Quantity		Average		Quantity		Average		Quantity		Average		at
Operating Area/	(Gas-MMbtu		Contract		(Gas-MMbtu		Contract		(Gas-MMbtu		Contract		(Gas-MMbtu		Contract		June 30,
Index	Oil-Bbls)		Price		Oil-Bbls)		Price		Oil-Bbls)		Price		Oil-Bbls)		Price		2009
Natural Gas
Rocky Mountain Region
CIG
3Q 2009		75,689	$	5.75		75,689	$	8.90		-	$	-		-	$	-	$	225,647
4Q 2009		53,256		6.67		53,256		10.21		19,688		9.20		-		-		262,375
2010		61,366		6.63		61,366		10.79		29,531		9.20		181,049		1.88		70,475
2011		28,989		4.75		28,989		9.45		-		-		215,684		1.88		(189,872	)
2012		-		-		-		-		-		-		227,950		1.88		(189,981	)
2013		-		-		-		-		-		-		211,754		1.88		(159,416	)
NYMEX
2010		7,747		5.75		7,747		8.30		160,968		5.62		-		-		(57,737	)
2011		10,537		5.75		10,537		8.30		58,166		6.96		-		-		592
2012		-		-		-		-		61,041		6.96		-		-		(11,549	)
Total Natural Gas																		(49,466	)
Oil
Rocky Mountain Region
NYMEX
3Q 2009		-		-		-		-		1,414		90.52		-		-		27,549
4Q 2009		-		-		-		-		1,414		90.52		-		-		24,913
2010		-		-		-		-		4,906		92.96		-		-		84,957
Total Oil																		137,419
Total Natural Gas and Oil																	$	87,953

Natural gas and 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. As production is expected to continue to decline, production costs per unit can be expected to increase.

~~In July 2009~~Generally, natural gas and oil production costs vary with changes in total oil and natural gas sales and production volumes. Property and severance taxes are estimates by the Managing General Partner ~~entered~~based ~~into~~on arates ~~NYMEX-~~determined using historical information. These amounts are subject to revision based ~~oil~~on ~~swap~~actual ~~covering approximately~~amounts ~~50%~~determined ofduring future filings by the ~~Partnership’s~~Managing ~~estimated~~General ~~production~~Partner ofwith the taxing authorities. Property and severance taxes vary directly with total oil ~~for~~and ~~the calendar~~natural ~~year~~gas ~~2011~~sales. Transportation atcosts ~~$70~~vary directly with production volumes.75 Fixed monthly well operating costs increase on a per ~~barrel~~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. These costs include water hauling and disposal, equipment repairs and maintenance, snow removal and service rig workovers.

Natural gas and oil production costs were lower by $0.3 million, or 33%, due to volume-associated 30 reductions of $0.2 million in production taxes, natural gas transport and lease operating expenses. In addition to volume-associated production tax decreases, lower commodity valuations further lowered production taxes by approximately $0.2 million. The Partnership had one well workover that increased lease operating costs by $0.1 million during fourth quarter 2009. Natural gas and oil production costs per Mcfe were $1.53 during the year 2009 compared to $1.79 for the year 2008.

- 21 -

Index

Production and Operating Costs

Production and Operating 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.

	2008						2007
	Prod Costs		Mcfe		per Mcfe		Prod Costs		Mcfe		per Mcfe
Jan-Mar	$	191,687		126,681	$	1.51	$	195,397		155,517	$	1.26
Apr-Jun		295,585		158,382		1.87		193,665		146,279		1.32
Jul-Sep		224,979		111,504		2.02		208,557		132,937		1.57
Oct-Dec		189,581		107,483		1.76		178,981		106,340		1.68
Total	$	901,832		504,050	$	1.79	$	776,600		541,073	$	1.44

As production declines as per the historical decline curve, fixed costs may increase as a percentage of total costs. This results in production costs per unit increases. As production is expected to continue to decline, production costs per unit can be expected to increase.

Generally, production and operating costs vary either with total oil and natural gas sales or production volumes. Property and severance taxes are estimates by the Managing General Partner based on rates determined using historical information. These amounts are subject to revision based on actual amounts determined during future filings by the Managing General Partner with the taxing authorities. Property and severance taxes vary directly with total oil and natural gas 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. These costs include water hauling and disposal, equipment repairs and maintenance, snow removal and service rig workovers. In addition, general oil field service costs have experienced significant inflationary increases.

During 2008, production and operating costs increased $0.1 million or 16% compared to the previous year, due primarily to variable costs, including production-related taxes and transportation, related to oil and natural gas volume reductions, on an Mcfe or energy equivalency basis, of 7%. Increases in the cost of general oil field services, including increased road maintenance and equipment repairs, are reflected in the per Mcfe basis unit cost increases for the second and third quarters of 2008. A decrease in general oil field service costs caused the reduction in the per Mcfe basis unit cost during the fourth quarter of 2008.

An increase in general oil field service costs caused the increase in the per Mcfe basis unit cost during the first quarter of 2007. The increases in the per Mcfe basis unit costs through the remaining three quarters of 2007 were principally due to production volume decreases.

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 ~~2008~~2009 by ~~approximately~~ $~~54,000 due~~0.4 ~~primarily~~million principally due to ~~increases~~billings infrom ~~audit~~the ~~fees~~Partnership’s ofindependent ~~approximately~~registered ~~$23~~public accounting firm,~~000~~ ~~and~~PricewaterhouseCoopers ~~outside professional~~LLP ~~fees~~("PwC"), offor ~~approximately~~professional ~~$46,000~~services ~~offset~~rendered by aPwC ~~reduction~~for inthe ~~legal~~audits ~~fees~~ of ~~approximately~~the ~~$13,000~~Partnership’s prior years’ financial statements due to Partnership compliance efforts during 2009.

- 31 -

Index

Depreciation, Depletion and Amortization

~~The Partnership~~Depreciation, ~~recorded~~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 inis primarily based upon year-end proved developed producing natural gas and oil reserves and is determined by these reserves and their associated production volumes. For 2008, the Partnership’s natural gas and ~~2007~~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 ~~follows:~~of December 31. In 2009, the SEC published its final rule regarding the modernization of oil and gas reporting, which changed the valuation price from a December 31 single-day pricing to a price determined by the 12-month average of the first-day-of-the-month price during each month of 2009. If valuation prices increase, the estimated volumes of natural gas and oil reserves will increase, resulting in decreases in the rate of DD&A for each Mcfe produced. If valuation prices decrease, as they did from December 31, 2008 to December 31, 2009, the estimated volumes of natural gas and oil reserves will decrease, resulting in increases in the rate of DD&A for each Mcfe produced.

	2008						2007
	DD&A		Mcfe		per Mcfe		DD&A		Mcfe		per Mcfe
Jan-Mar	$	338,689		126,681	$	2.67	$	389,979		155,517	$	2.51
Apr-Jun		394,122		158,382		2.49		360,868		146,279		2.47
Jul-Sep		318,593		111,504		2.86		319,661		132,937		2.40
Oct-Dec		346,297		107,483		3.22		318,295		106,340		2.99
Total	$	1,397,701		504,050	$	2.77	$	1,388,803		541,073	$	2.57

The DD&A expense rate per Mcfe increased to $3.34 for the year ended December 31, 2009, compared to $2.77 during the same period in 2008. The variance in the per Mcfe rates for 2009 compared to 2008 is partially the result of the changing production mix between the Partnership’s Wattenberg and Grand Valley fields, which have significantly different DD&A rates, and the overall production volume decline of 22% which reduced DD&A expense by $0.3 million in 2009 compared to the previous year. Production-related DD&A expense declines were partially offset however, as a consequence of increases in per Mcfe DD&A rates due to lower proved developed reserves at December 31, 2009 compared to December 31, 2008. This proved developed natural gas and oil reserve revision increased DD&A expense by $0.2 million, resulting in the overall $0.1 million decline in DD&A expense during 2009 as compared to 2008.

DD&A expense is primarily based upon year-end proved developed producing oil and gas reserves. These reserves are valued at the price of oil and natural gas as of December 31 each year. If prices increase, the corresponding volume of oil and natural gas reserves will increase, resulting in decreases in the rate of DD&A per unit of production. If year-end prices decrease as they did from 2007 to 2008, volumes of oil and natural gas reserves will decline, resulting in increases in the rate of DD&A per unit of production.

DD&A expense for the year 2008 compared to 2007 remained substantially unchanged primarily due to the production level decrease of $0.1 million which was offset by an increase per Mcfe due to somewhat lower reserves at December 31, 2008. In both the fourth quarter of 2008 and 2007, the DD&A unit cost per Mcfe increased due to revised estimates of reserves from the annual reserve reports which indicated decreases in proved developed reserves from the respective prior periods. While both production and overall year-end reserves are expected to decline gradually year-to-year over the wells’ remaining life cycles, downward revisions to oil and natural gas reserves in the annual 2008 reserve report resulted in the larger DD&A unit cost increase during the fourth quarter of 2008 as compared to the fourth quarter 2007.

The variances in the per Mcfe rates for the 2008 quarters ended March 31, June 30 and September 30 and the comparable quarter for 2007 are primarily the result of the changing production mix between the Partnership’s Wattenberg and Grand Valley fields which have significantly different DD&A rates.

Interest Income

Interest income decreased in 2008 as compared to 2007 due to the somewhat lower level of undistributed revenues held by the Managing General Partner, as well as a reduction in the interest rates applied to those undistributed revenue amounts. Additionally, interest rates decreased on amounts held in escrow by the Managing General Partner on behalf of the Partnership related to production tax obligation over-withholding during the years prior to 2007. For more information on the production tax obligation over-withholding by the Managing General Partner, see Note 2, Summary of Significant Accounting Policies−Due from (to) Managing General Partner−Other.

Liquidity and Capital Resources

AsThe ~~the~~ Partnership’s ~~completed~~primary ~~its~~sources ~~drilling~~of ~~activities~~cash asin of2009 ~~March~~were ~~31,~~from ~~2005,~~funds ~~the Partnership’s~~generated ~~operations~~from ~~are~~the ~~expected~~sale toof benatural ~~conducted~~gas ~~with~~and ~~available~~oil ~~funds~~production and ~~revenues~~ ~~generated~~the ~~from~~net ~~oil~~realized ~~and~~gains ~~natural~~from ~~gas~~the ~~production~~Partnership’s ~~activities~~derivative positions. These ~~Because~~sources ~~oil and~~of ~~gas~~cash ~~production~~were ~~from~~primarily used to fund the Partnership’s ~~existing~~operating ~~properties~~cost, ~~declined~~general ~~rapidly in~~and administrative activities and provide monthly distributions to the ~~first~~Investor ~~two~~Partners ~~years~~and PDC, the Managing General Partner. Fluctuations in the Partnership’s ~~may~~operating becash ~~unable~~flow toare ~~maintain~~substantially ~~its~~driven ~~current level~~by ofcommodity ~~oil~~prices, ~~and~~change ~~gas~~in production volumes and ~~cash~~realized ~~flows~~gains ~~from~~and ~~operations~~losses iffrom commodity positions. Commodity prices ~~remain~~have inhistorically ~~their~~been ~~current~~volatile ~~depressed~~and ~~state~~the ~~for~~Partnership amanages ~~prolonged~~this ~~period~~volatility ~~beyond 2009~~through derivatives. ~~This~~Therefore, ~~decreased~~the ~~production~~primary ~~would~~source ~~have~~of athe ~~material~~Partnership’s ~~negative~~cash ~~impact on~~flow from operations becomes the net activity between the Partnership’s ~~operations~~natural gas and ~~may~~oil ~~result~~sales inand ~~reduced~~realized ~~cash~~derivative ~~distributions~~gains ~~to the~~and ~~Investor~~losses. However, ~~Partners~~the inPartnership ~~2010~~does ~~and~~not ~~beyond.~~hold ~~Based~~economic onhedges ~~the~~for ~~current~~100% ~~economic environment,~~of the ~~Managing~~Partnership’s ~~General~~expected ~~Partner~~future ~~has~~production noand ~~immediate~~therefore ~~plans~~may tostill ~~initiate recompletion~~experience ~~activities~~significant fluctuations in ~~the~~our ~~Codell~~cash ~~formation~~flows offrom ~~the Wattenberg Field wells~~operations. ~~The~~See ~~Managing~~Results ~~General~~of ~~Partner~~Operations ~~will~~for ~~re-evaluate~~further ~~the~~discussion ~~feasibility~~ of ~~commencing~~the ~~these~~impact ~~recompletion~~of ~~activities~~prices asand ~~economic~~volumes ~~conditions improve. However,~~on nosales ~~assurance~~from ~~can~~operations beand ~~given~~the ~~that~~impact ~~recompletion~~ of derivative activities ~~will~~on bethe ~~feasible~~Partnership’s revenues.

-The ~~32 -~~Partnership’s future operations are expected to be conducted with available funds and revenues generated from oil and natural gas production activities and commodity gains (losses). Oil and gas production from the Partnership’s existing properties are expected to continue a gradual decline over the remaining life of the wells. Therefore, the Partnership expects a lower annual level of oil and gas production and, in the absence of significant price increases, 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 Investor Partners in 2010 and beyond. Future cash distributions may also be reduced to fund well recompletions in the Codell formation of the Wattenberg field.

- 22 -

Index

The Partnership’s liquidity may be impacted by fluctuating oil and natural gas prices, as noted in Item 1A, Risk Factors. Changes in market prices for oil and natural gas directly affect the level of cash flow from operations. While a decline in oil and natural gas prices would affect the amount of cash flow that would be generated from operations, the Partnership had oil and natural gas derivatives in place as of June 30, 2009, covering 71% of the Partnership’s expected oil production and 79% of its expected natural gas production for the remainder of 2009. These contracts reduce the impact of price changes for a substantial portion of the Partnership’s 2009 cash from operations. In July 2009, the Managing General Partner entered into a NYMEX-based oil swap covering approximately 50% of the Partnership’s estimated production of oil for the calendar year 2011 at $70.75 per barrel. The fair value of the current derivatives positions will change based on changes in oil and natural gas futures markets. Oil and natural gas derivatives as of December 31, 2008 are detailed in Note 5, Derivative Financial Instruments to the accompanying financial statements.

Working Capital

~~The following~~Working ~~table~~capital ~~sets~~at ~~forth~~December ~~the~~31, 2009 was $0.3 million compared to working capital ~~position~~of $2.2 million at December 31, 2008. This decrease of $1.9 million was primarily due to the ~~Partnership~~ following changes in accounts receivable balances:

	As of
	March 31, 2008		June 30, 2008		September 30, 2008		December 31, 2008
Working capital	$	1,127,939	$	1,012,126	$	1,929,827	$	2,190,481
	As of
	March 31, 2007		June 30, 2007		September 30, 2007		December 31, 2007
Working capital	$	1,450,306	$	1,503,645	$	1,421,595	$	1,155,245

Natural gas and oil receivables decreased to $0.3 million as of December 31, 2009, from $0.4 million as of December 31, 2008.

~~Cash Flows~~· ~~From~~Realized ~~Financing~~derivative ~~and~~gains ~~Investing~~receivables ~~Activities~~decreased to $0.2 million as of December 31, 2009, from $0.3 million as of December 31, 2008

In· ~~2008, the~~Short-term ~~Partnership~~unrealized ~~received~~derivative agains ~~refund~~receivable ofdecreased ~~approximately~~to $~~37,000~~0.0 ~~from~~million ~~the~~as ~~State~~ of ~~Colorado~~ ~~for~~December ~~state~~31, ~~sales taxes charged during prior years on well tubing and casing purchases during the Partnership’s drilling operations~~2009, ~~which~~from ~~were subsequently~~$1.0 ~~determined~~million toas ~~be tax-exempt utilization~~ of ~~this material. The~~December ~~Partnership has from time-to-time~~31, ~~invested in additional equipment which supports enhanced hydrocarbon recovery, treatment, delivery and measurement or environmental protection, which totaled approximately $8,000 in~~ 2008.

~~The Partnership~~Additionally, ~~initiated~~during ~~monthly~~the ~~cash~~third ~~distributions~~quarter to2009, ~~investors~~there inwas ~~February~~a ~~2005 and~~net ~~has~~reduction ~~distributed~~of $170.18 million ofin ~~its~~amounts ~~operating~~due ~~cash~~from ~~flows~~the ~~from~~Managing ~~its~~General ~~July~~Partner ~~2, 2004~~as ~~date~~a of$0.8 ~~inception~~million ~~through~~receivable ~~December~~for ~~31,~~over-withheld ~~2008~~production taxes related to Partnership production prior to 2007 was collected. ~~The~~In ~~following~~addition, ~~table sets~~the ~~forth~~Partnership settled the ~~quarterly~~obligation ~~cash~~for ~~distributions~~the toColorado Royalty Settlement of approximately $20,000 with the Managing General Partner. The ~~and the~~net ~~Investor~~cash ~~Partners~~impact of these transactions increased distributions by $0.8 million during 2009. For more information on the ~~years~~Colorado ~~ended~~Royalty ~~December~~Settlement 31see Note 9, ~~2008~~Commitments and ~~2007, respectively~~Contingencies to the accompanying audited financial statements.

	Managing		Investor
	General Partner		Partners		Total
	Distributions		Distributions		Distributions
2008
Jan-Mar	$	98,574	$	394,299	$	492,873
Apr-Jun		148,380		593,522		741,902
Jul-Sep		196,122		784,490		980,612
Oct-Dec		151,375		605,499		756,874
	$	594,451	$	2,377,810	$	2,972,261
2007
Jan-Mar	$	129,948	$	519,794	$	649,742
Apr-Jun		118,300		492,530		610,830
Jul-Sep		123,010		492,043		615,053
Oct-Dec		103,964		415,858		519,822
	$	475,222	$	1,920,225	$	2,395,447

Cash Flows

-Cash ~~33 -~~Flows From Investing Activities

The Partnership, from time-to-time, invests in additional equipment which supports treatment, delivery and measurement of oil and gas or environmental protection. These amounts totaled approximately $13,000 for 2009. The Partnership also received an approximately $11,000 refund from the Managing General Partner during the year 2009, for estimated capital expenditures previously charged for oil and gas properties which the Managing General Partner subsequently determined were not applicable to the Partnership.

Cash Flows From Financing Activities

The Partnership initiated monthly cash distributions to investors in February 2005 and has distributed $19.5 million through December 31, 2009. The table below presents the cash distributions to the Managing General Partner and Investor Partners including Managing General Partner distributions relating to limited partnership units repurchased for the periods described as follows:

Year Ended	Managing General Partner Distributions		Investor Partners Distributions		Total Distributions

2009	$	476,376	$	1,905,507	$	2,381,883

2008	$	594,451	$	2,377,810	$	2,972,261

Investor Partner cash distributions include $34,541 and $21,450 during the years 2009 and 2008, respectively, related to equity cash distributions on Investor Partner units repurchased by the Managing General Partner.

- 23 -

Index

Cash Flows From Operating Activities

Net cash provided by operating activities was $32.03 million infor ~~2008~~2009 compared to $23.4 0 million infor ~~2007~~2008, ana ~~increase~~decrease of $0.67 million. The ~~increase~~decrease in cash provided by operating activities was due primarily to the following:

· AnA ~~increase~~decrease in ~~oil~~natural gas and ~~gas~~oil sales ~~revenues~~receipts of ~~25% offset by a~~ $02.15 million, ~~decrease~~or ~~in realized oil and gas price risk management gains~~63%, ~~net;~~accompanied by an increase in ~~production~~direct ~~and operating~~ costs of– ~~16%~~general and anadministrative ~~increase in direct costs~~ of ~~approximately~~ $~~54,000~~0.4 million; and

· ~~Increase~~An increase in ~~the~~realized ~~“Due~~commodity ~~from~~price ~~(to)~~risk ~~Managing~~management, ~~General~~net ~~Partner~~of $1.2 million and a decrease in natural gas and oil production costs of $0.3 million, ~~net~~or 33%.”

~~The following~~· ~~table~~A ~~presents~~reduction in “Due from Managing General Partner – Other, Net,” of $0.8 million in third quarter 2009, due to the ~~operating~~Managing ~~cash~~General ~~flows~~Partner’s $0.8 million payment to the Partnership for over-withheld production taxes and accrued interest thereon related to Partnership production prior to 2007 which was offset by the ~~following periods:~~Partnership’s approximately $20,000 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.

	2008
	Quarter ended		Quarter ended		Quarter ended		Quarter ended
	March 31,		June 30,		September 30,		December 31,
Cash flows from operating activities	$	501,665	$	744,152	$	984,395	$	760,352

Information related to the oil and gas reserves of the Partnership’s wells is discussed in detail in the Supplemental Oil and Gas Information−Unaudited, Net Proved Natural Gas and Oil Reserves.

	2007
	Quarter ended		Quarter ended		Quarter ended		Quarter ended
	March 31,		June 30,		September 30,		December 31,
Cash flows from operating activities	$	654,524	$	614,471	$	618,547	$	519,731

Information related to the oil and gas reserves of the Partnership’s wells is discussed in detail in Supplemental Oil & Gas Information – Unaudited, Net Proved Oil and Gas Reserves.

Contractual Obligations and Contingent Commitments

The table below sets forth the Partnership’s contractual obligations and contingent commitments as of December 31, 2008 and 2007.

	Payments due by period
Contractual Obligations and			Less than						More than
Contingent Commitments	Total		1 year		1-3 years		3-5 years		5 years
December 31, 2008
Unrealized loss on derivative contracts	$	100,327	$	-	$	-	$	100,327	$	-
Asset Retirement Obligations		161,487		-		-		-		161,487
	$	261,814	$	-	$	-	$	100,327	$	161,487
December 31, 2007
Unrealized loss on derivative contracts	$	68,645	$	68,645	$	-	$	-	$	-
Asset Retirement Obligations		152,707		-		-		-		152,707
	$	221,352	$	68,645	$	-	$	-	$	152,707

Critical Accounting Policies and Estimates

The Managing General Partner has identified the following ~~accounting~~ policies as critical to business operations and the understanding of the results of the operations of the Partnership. This 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 ~~condition~~position and results of operations and ~~require~~the ~~management's~~Managing ~~most~~General ~~subjective~~Partner ormay ~~complex~~use ~~judgments,~~significant ~~and~~ judgment in their application; as a result, these policies are subject to an inherent degree of uncertainty. In applying ~~those~~these policies, ~~management~~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, ~~observance~~ 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:

- 34 -

Index

Oil and Natural Gas Properties

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

The Partnership’s estimates of proved reserves are based on quantities of oil and gas that engineering and geological analysis demonstrates, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic conditions. Annually, we engage independent petroleum engineers to prepare a reserve and economic evaluation of all our properties on a well-by-well basis as of December 31.

Proved reserves are the estimated quantities of oil and natural gas that geologic and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. 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.

Proved developed reserves are the quantities of oil and natural gas expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped reserves are those reserves expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for completion. In some cases, proved undeveloped reserves may require substantial new investments in additional wells and related facilities.

The process of estimating and evaluating oil and gas 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 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 DD&A expense, a change in estimated reserves could have a material effect on the Partnership’s financial statements.

In accordance with Statement of Financial Accounting Standards, SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, the Partnership assesses its proved oil and gas properties for possible impairment, upon a triggering event, by comparing net capitalized costs to estimated undiscounted future net cash flows on a field-by-field basis using estimated future production based upon prices at which the Partnership reasonably estimates the commodity to be sold. The estimates of future prices may differ from current market prices of oil and natural gas. Downward revisions in estimates to the Partnership’s reserve quantities, expectations of falling commodity prices or rising operating costs could result in a triggering event and therefore a possible impairment of the Partnership’s oil and natural gas properties. If net capitalized costs exceed undiscounted future net cash flows, impairment is based on estimated fair value utilizing a future discounted cash flow analysis and is measured by the amount by which the net capitalized costs exceed their fair value. Due to the significant reduction in oil and natural gas prices during the fourth quarter of 2008 and the availability of new reserve information, the Partnership reviewed its proved oil and natural gas properties for impairment at December 31, 2008. The Partnership did not incur any impairment loss as a result of this review. Although cash flow estimates used by the Partnership are based on the relevant information available at the time the estimates are made, estimates of future cash flows are, by nature, highly uncertain and may vary significantly from actual results.

- 35 -

Index

Revenue Recognition

Natural Gas Sales. Sales of natural gas are recognized when natural gas has been delivered to a custody transfer point, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser upon delivery, collection of revenue from the sale is reasonably assured, and the sales price is fixed or determinable. Natural gas ~~upon delivery~~ is sold upon delivery by the Managing General Partner under contracts with terms ranging from one month up to the life of the well. Virtually all of the Managing General Partner’s contracts’ pricing provisions are tied to a market index with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality of gas and prevailing supply and demand ~~conditions,~~ ~~so that the price of the natural gas fluctuates to remain competitive with other available natural gas supplies~~conditions. As a result, the Partnership’s revenues from the sale of natural gas will ~~suffer~~decrease if market prices decline and ~~benefit~~increase if ~~they~~market prices increase. The Managing General Partner may from time to time enter into derivative agreements which may either “swap” or “collar” a price range or provide for basis protection in order to reduce the impact of market price fluctuations. The Partnership believes that the pricing provisions of its natural gas contracts are customary in the industry.

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

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~~24 ~~contracts at prices and in accordance with arrangements that are customary in the oil industry.~~-

Fair Value Measurements

The Partnership adopted the provisions of Statement of SFAS No. 157, Fair Value Measurements, effective January 1, 2008. SFAS No. 157 defines fair value, establishes a framework for measuring fair value and expands disclosures related to fair value measurements. SFAS No. 157 applies broadly to financial and nonfinancial assets and liabilities that are measured at fair value under other authoritative accounting pronouncements, but does not expand the application of fair value accounting to any new circumstances. In February 2008, the Financial Accounting Standards Board (“FASB”) issued FASB Staff Position (“FSP”) FAS No. 157-2, Effective Date of FASB Statement No. 157, which delayed the effective date of SFAS No. 157 by one year (to January 1, 2009) for nonfinancial assets and liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually). Nonfinancial assets and liabilities for which the Partnership has not applied the provisions of SFAS No. 157 include those initially measured at fair value, including the Partnership’s asset retirement obligations.

Determination of Fair Value. The Partnership determines the fair value of its assets and liabilities, unless specifically excluded, pursuant to FAS No. 157. FAS No. 157 defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date.

FAS No. 157 establishes a fair value hierarchy that requires an entity 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:

- 36 -

Index

~~Level~~Oil 1Sales. Sales ~~– Quoted~~of ~~prices~~oil ~~(unadjusted)~~are inrecognized ~~active~~when ~~markets~~persuasive ~~for~~evidence ~~identical~~of ~~assets~~a ~~or liabilities~~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. ~~Included~~The inPartnership ~~Level~~does 1not ~~would~~refine beany ~~commodity~~of ~~derivative instruments~~its ~~for~~oil ~~New~~production. The ~~York~~Partnership’s ~~Mercantile~~crude ~~Exchange~~oil ~~(“NYMEX”)~~production ~~natural~~is ~~gas swaps~~sold to purchasers at or near the Partnership’s wells under short-term purchase contracts at prices and in accordance with arrangements that are customary in the oil industry.

~~Level~~Fair 2Value ~~– Inputs~~of ~~other~~Financial 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.Instruments

~~Level~~Determination 3of ~~– Unobservable~~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 ~~for~~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, ~~including~~as ~~situations~~of ~~where~~the ~~there is~~measurement ~~little~~date, ifgiving ~~any~~the highest priority to quoted prices in active markets (Level 1) and the lowest priority to unobservable data (Level 3). In some cases, ~~market~~the ~~activity~~inputs ~~for~~used to measure fair value might fall in different levels of the ~~asset~~fair ~~or liability~~value hierarchy. ~~Included~~The lowest level input that is significant to a fair value measurement in ~~Level~~its 3entirety ~~are~~determines the ~~Partnership’s~~applicable ~~commodity~~level ~~based and~~in ~~basis~~the ~~protection~~fair ~~derivative~~value ~~instruments~~hierarchy. Assessing ~~for~~the ~~Colorado~~significance ~~Interstate~~of ~~Gas~~a particular input to the fair value measurement in its entirety requires judgment, considering factors specific to the asset or ~~CIG~~liability, ~~based~~ ~~fixed-price~~and ~~natural~~may ~~gas~~affect ~~swaps,~~the ~~collars~~valuation ~~and~~of ~~floors,~~the ~~oil~~assets ~~swaps,~~and liabilities and ~~natural gas~~their ~~basis~~placement ~~protection~~within ~~swaps~~the fair value hierarchy levels. The three levels of inputs that may be used to measure fair value are defined as:

~~Derivative~~· ~~Financial Instruments. The~~Level ~~Partnership~~1 ~~measures~~– ~~the~~Quoted ~~fair value of its derivatives based upon quoted market~~ prices, ~~where available. The Managing General Partner’s valuation determination includes:~~ (1unadjusted) ~~identification of~~in ~~the~~active ~~inputs~~markets tofor ~~the~~identical ~~fair~~assets 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~~Included ~~General~~in ~~Partner~~Level ~~primarily uses~~1 ~~two~~are ~~investment grade financial institutions as counterparties to its derivative contracts who hold~~ the ~~majority of the Managing General Partner’s derivative assets. The Managing General Partner has evaluated the credit risk of the~~ Partnership’s ~~derivative~~commodity ~~assets from counterparties using relevant credit market default rates, giving consideration to amounts outstanding for each counterparty and the duration of each outstanding~~ derivative ~~position. The Managing General Partner has determined based on this evaluation, that the impact of counterparty non-performance on the fair value of the Partnership’s derivative~~ instruments ~~is insignificant~~ for ~~the Partnership. As~~New ofYork ~~December~~Mercantile 31Exchange, 2008, no valuation allowance by the Partnership has been 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~~NYMEX, tobased ~~determine~~fixed ~~the~~price ~~fair~~natural ~~value~~gas ofswaps ~~certain financial instruments could result in a different estimate of fair value. The Partnership has estimated the net fair value of Partnership’s commodity based~~ and ~~basis protection derivatives as of December 31, 2008 to be $1~~collars.~~2 million.~~

~~Non-Derivative~~· ~~Financial~~Level ~~Assets~~2 ~~and Liabilities. The~~– ~~carrying~~Inputs ~~values~~other ofthan ~~the~~quoted ~~financial~~prices ~~instruments comprising~~included ~~“Cash~~within ~~and~~Level ~~cash~~1 ~~equivalents,”~~that ~~“Accounts~~are ~~receivable~~either directly or indirectly observable for the asset or liability,” ~~“Accounts~~including ~~payable and~~(i) ~~accrued~~quoted ~~expenses”~~prices ~~and~~for ~~“Due~~similar ~~from~~assets or liabilities in active markets, (toii) ~~Managing~~quoted ~~General~~prices ~~Partner-other~~for identical or similar assets or liabilities in inactive markets, ~~net” approximate~~(iii) ~~fair~~inputs ~~value~~other ~~due~~than toquoted prices that are observable for the ~~short-term~~asset ~~maturities~~or ofliability ~~these instruments~~and (iv) inputs that are derived from observable market data by correlation or other means.

~~In accordance~~· ~~with~~Level ~~FAS~~3 ~~144,~~– ~~Accounting~~Unobservable inputs for the ~~Impairment~~asset or ~~Disposal~~ ~~of Long-Lived Assets~~liability, ~~the~~including ~~Partnership~~situations ~~assesses~~where ~~its~~there ~~proved~~is ~~oil and gas properties for possible impairment~~little, ~~upon~~if ~~a triggering event~~any, ~~by comparing~~market ~~net~~activity ~~capitalized~~for ~~costs~~the toasset ~~estimated~~or ~~undiscounted~~liability. ~~future~~Included ~~net~~in ~~cash~~Level ~~flows on~~3 aare ~~field-by-field basis using estimated production based upon prices at which~~ the Partnership’s ~~reasonably estimates the~~ commodity toderivative beinstruments ~~sold. The estimates~~for ofColorado ~~future~~Interstate ~~prices~~Gas, ~~may~~or ~~differ~~CIG, ~~from~~based ~~current~~fixed-price ~~market prices of oil and~~ natural gas~~. Certain~~ ~~events~~swaps, ~~including~~oil ~~but not limited to~~swaps, ~~downward revisions~~natural ingas ~~estimates~~and tooil ~~the Partnership’s reserve quantities~~collars, ~~expectations of falling commodity prices or rising operating costs could result in a triggering event~~ and, ~~therefore, a possible impairment of~~ the Partnership’s ~~oil and~~ natural gas ~~properties. If~~basis ~~net~~protection ~~capitalized~~derivative costs exceed undiscounted future net cash flows, the measurement of impairment is based on estimated fair value utilizing a future discounted cash flow analysis and is measured by the amount by which the net capitalized costs exceed their fair valueinstruments. ~~During the year ended December 31, 2008, no impairment of oil and gas properties was recognized.~~

~~The Partnership~~Derivative ~~accounts~~Financial ~~for~~Instruments. The ~~asset~~Managing ~~retirement~~General ~~obligations~~Partner bymeasures ~~recording the~~ fair value of ~~its~~the ~~plugging~~Partnership’s ~~and~~derivatives ~~abandonment~~based ~~obligations~~upon ~~when~~quoted ~~incurred~~market prices, ~~which~~where isavailable. The atManaging General Partner’s valuation determination includes: (1) identification of the ~~time~~ inputs to the ~~well~~fair isvalue ~~completely~~methodology ~~drilled. Upon~~through ~~initial~~the ~~recognition~~review of ~~an asset~~counterparty ~~retirement~~statements ~~obligation~~and other supporting documentation, ~~the~~(2) ~~Partnership~~determination ~~increases~~of the ~~carrying~~validity ~~amount~~of the source of the ~~long-lived~~inputs, ~~asset~~(3) bycorroboration of the ~~same~~original ~~amount~~source asof ~~the~~inputs ~~liability. Over~~through ~~time, the~~access ~~asset~~to ~~retirement~~multiple ~~obligations~~quotes, ~~are~~if ~~accreted~~available, ~~over~~or ~~the~~other ~~estimated~~information ~~lives~~and of(4) ~~the related~~monitoring ~~assets,~~changes ~~for~~in ~~the~~valuation ~~change~~methods inand ~~their~~assumptions. The ~~present~~methods described above may produce a fair value calculation that may not be indicative of future fair values. The ~~initial capitalized~~Managing ~~costs~~General ~~are~~Partner’s ~~depleted~~valuation ~~over~~determination also gives consideration to the ~~useful~~nonperformance ~~lives~~risk ofon PDC’s own business interests and liabilities as well as the ~~related~~credit ~~assets, through~~standing ~~charges~~of derivative instrument counterparties. The Managing General Partner primarily uses two investment grade financial institutions as counterparties to ~~DD&A~~its ~~expense~~derivative contracts. IfThe Managing General Partner has evaluated the ~~fair~~credit ~~value~~risk of the ~~estimated~~ ~~asset~~Partnership’s ~~retirement~~derivative ~~obligation~~assets ~~changes,~~from ancounterparties ~~adjustment~~default, isgiving ~~recorded~~consideration to ~~both the~~amounts ~~asset~~outstanding ~~retirement~~for ~~obligation~~each counterparty and the ~~asset~~duration ~~retirement~~of ~~cost.~~each ~~Revisions~~outstanding ~~in estimated~~derivative ~~liabilities~~position. The ~~can~~Managing ~~result~~General ~~from~~Partner ~~revisions~~has ofdetermined ~~estimated~~based ~~inflation~~on ~~rates~~this evaluation, ~~escalating~~ ~~retirement~~that ~~costs~~the ~~and~~impact ~~changes~~of incounterparty nonperformance on the ~~estimated~~fair ~~timing~~value of ~~settling asset~~the ~~retirement~~Partnership’s ~~obligations~~derivative instruments is not material. ~~See~~As ~~Note~~of 8December 31, ~~Asset~~2009, ~~Retirement~~no ~~Obligations~~ 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 ~~accompanying~~fair value of certain financial ~~statements,~~instruments ~~for~~could result in a ~~reconciliation~~different estimate of ~~asset retirement~~fair ~~obligation activity~~value.

- 37 25 -

Index

Natural Gas and Oil Properties

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

Annually, the Managing General Partner engages an independent petroleum engineer to prepare a reserve and economic evaluation of the Partnership’s properties on a well-by-well basis as of December 31. The process of estimating and evaluating natural gas and oil reserves is complex, requiring significant decisions in the evaluation of available geological, geophysical, engineering and economic data. The data for a given property may also change substantially over time as a result of numerous factors, including additional development activity, evolving production history and a continual reassessment of the viability of production under changing economic conditions. As a result, revisions in existing reserve estimates occur from time to time. Although every reasonable effort is made to ensure that reserve estimates reported represent the Managing General Partner’s most accurate assessments possible, the subjective decisions and variances in available data for various properties increase the likelihood of significant changes in these estimates over time. Because estimates of reserves significantly affect the Partnership’s DD&A expense, a change in the Partnership’s estimated reserves could have an effect on its net income.

Proved developed reserves are those natural gas and oil quantities expected to be recovered from currently producing zones under the continuation of present operating methods. Proved undeveloped reserves, or PUDs, are those reserves expected to be recovered from existing wells where a relatively major expenditure is required for recompletion.

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

Recent Accounting Standards

See Note 2, Summary of Significant Accounting Policies −to the Partnership’s accompanying financial statements included in this report~~, for recently issued and implemented accounting standards including the SEC published final rule, Modernization of Oil and Gas Reporting~~. The most notable change of this final rule includes the replacement of the single day period-ending pricing for valuing oil and natural gas reserves with a 12-month average of the first day of the month price for each month within the reporting period.

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

~~Market-Sensitive~~Not ~~Instruments and Risk Management~~applicable.

The Partnership's primary market risk exposure is commodity price risk and related credit exposure. Management of the Managing General Partner has established risk management processes to monitor and manage this market risk.

Commodity Price Risk

See Part II, Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations−Critical Accounting Policies and Estimates, Fair Value of Financial Instruments, for further discussion of the accounting for derivative contracts.

The Partnership is exposed to the effect of market fluctuations in the prices of oil and natural gas as they relate to the Partnership’s oil and natural gas sales and marketing activities. Price risk represents the potential risk of loss from adverse changes in the market price of oil and natural gas commodities. The Managing General Partner employs established policies and procedures to manage the risks associated with these market fluctuations using commodity derivatives. The Partnership's policy prohibits the use of oil and natural gas derivative instruments for speculative purposes.

Valuation of a contract’s fair value is performed internally and, while the Managing General Partner uses common industry practices to develop the Partnership’s valuation techniques, changes in pricing methodologies or the underlying assumptions could result in 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.

Derivative Strategies

The Partnership’s results of operations and operating cash flows are affected by changes in market prices for oil and natural gas. To mitigate a portion of the exposure to adverse market changes, the Managing General Partner has entered into various derivative contracts. As of December 31, 2008, the Partnership’s oil and natural gas derivative instruments were comprised of “swaps” and “collars” in addition to “basis protection swaps.” These instruments generally consist of CIG-based contracts for Colorado gas production and NYMEX-based contracts for Colorado oil production. In addition to the swaps, collars and basis protection swaps, derivative instruments which remain in effect at December 31, 2008, the Managing General Partner previously utilized “floor” contracts to reduce the impact of natural gas and oil price declines in subsequent periods.

- 38 -

Index

· Collars contain a fixed floor price (put) and ceiling price (call). If the market 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 market price from the counterparty. If the market 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 market price to the counterparty. If the market price is between the call and put strike price, no payments are due to or from the counterparty.

· Swaps are arrangements that guarantee a fixed price. If the market 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 market price and the fixed contract price from the counterparty. If the market 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 market price and the fixed contract price to 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 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.

· Floors contain a floor price (put) whereby PDC, as Managing General Partner, receives the market price from the purchaser and the difference between the market price and floor price from the counterparty if the commodity market price falls below the floor strike price, but receives no payment when the commodity market price exceeds the floor price.

The Managing General Partner enters into derivative instruments for Partnership production to reduce the impact of price declines in future periods. While these derivatives are structured to reduce the Partnership’s exposure to changes in price associated with the derivative commodity, they also limit the benefit the Partnership might otherwise have received from price changes in the physical market. The Partnership believes the derivative instruments in place continue to be effective in achieving the risk management objectives for which they were intended.

The following table presents monthly average CIG and NYMEX closing prices for natural gas and oil in 2008 and 2007, as well as average sales prices the Partnership realized for the respective commodity.

	Year Ended December 31,
	2008		2007
Average index closing price
Natural gas (per MMbtu)
CIG	$	6.22	$	3.97
Oil (per Barrel)
NYMEX		104.42		69.79
Average sales price
Natural gas (per Mcf)	$	6.51	$	4.89
Oil (per Barrel)		89.15		58.04

As of December 31, 2008, the fair value of the Partnership’s derivative instruments was a net asset of $1.2 million compared to a net liability of approximately $39,000 as of December 31, 2007. Based on a sensitivity analysis as of June 30, 2009, it was estimated that a 10% increase in oil and gas prices, inclusive of basis, over the entire period for which the Partnership has derivatives currently in place would result in a decreased fair value of approximately $5,000 and a 10% decrease in oil and gas prices would result in an increase in fair value of $1.1 million.

See Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations, Results of Operations−Oil and Gas Price Risk Management, Net for a detailed discussion of the Partnership’s open derivative positions related to the Partnership’s oil and gas sales activities and a summary of the Partnership’s open derivative positions.

- 39 -

Index

Credit Risk

Credit risk represents the loss that the Partnership would incur if a counterparty fails to perform under its contractual obligations. When the fair value of a derivative contract is positive, the counterparty owes the Managing General Partner, which in turn owes the Partnership, thus creating repayment risk from counterparties.

The Managing General Partner attempts to reduce credit risk by diversifying its counterparty exposure and entering into transactions with high-quality counterparties. When exposed to credit risk, the Managing General Partner analyzes the counterparties’ financial condition prior to entering into an agreement, establishes credit limits and monitors the appropriateness of those limits on an ongoing basis. PDC, the Managing General Partner has had no counterparty default losses. The Managing General Partner’s receivables are from a diverse group of companies, including major energy companies, both upstream and mid-stream, financial institutions and end-users in various industries. The Managing General Partner monitors their creditworthiness through credit reports and rating agency reports.

The Managing General Partner has evaluated the credit risk of the Partnership’s assets from counterparties using relevant credit market default rates, giving consideration to amounts outstanding for each counterparty and the duration of each outstanding derivative position. Based on the Managing General Partner’s evaluation, the Partnership has determined that the impact of the nonperformance of counterparties on the fair value of the Partnership’s derivative instruments is insignificant. At December 31, 2008 and 2007 no valuation allowance has been recorded by the Partnership. 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 fair value of certain financial instruments could result in a different estimate of fair value.

Disclosure of Limitations

As the information above incorporates only those exposures which existed as of or prior to June 30, 2009, it does not consider those exposures or positions which could arise after that date. As a result, the Partnership's ultimate realized gain or loss with respect to commodity price fluctuations depends on the future exposures that arise during the period, the Partnership's hedging strategies at the time and commodity prices at the time.

Item 8. Financial Statements and Supplementary Data

The financial statements are attached to this Form 10-K beginning at page F-1.

Supplemental financial information required by this Item can be found in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations of this report.

- 26 -

Index

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

None

Item 9A(T). Controls and Procedures

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

-2008 ~~40 -~~Material Weakness

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

(a) Evaluation of Disclosure Controls and Procedures

As of December 31, ~~2008~~2009, 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 ~~its~~the Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of the Partnership's disclosure controls and ~~procedures. Disclosure~~ ~~controls and~~ procedures ~~are~~pursuant ~~defined~~to in Exchange Act Rules 13a-15(e) and 15d-15(e). This asevaluation considered the ~~controls~~various ~~and~~processes ~~procedures~~carried out under the direction of ~~an issuer~~the ~~that~~Managing ~~are~~General ~~designed~~Partner’s Disclosure Committee in an effort to ensure that information required to be disclosed ~~by the issuer~~ in the SEC reports itthe 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 ~~issuer~~Partnership’s management, including its principal executive and principal financial officers, ~~or persons performing similar functions,~~ as appropriate to allow timely decisions regarding required ~~disclosure. Based~~ ~~upon that evaluation, the Managing General Partner’s Chief Executive Officer and Chief Financial Officer concluded that the Partnership’s~~ disclosure controls and procedures were not effective as of December 31, 2008 due to the existence of the material weakness described below in Management’s Report on Internal Control Over Financial Reporting included in this Item 9A(T).

~~(b) Management~~Based upon the evaluation, the Managing General Partner’s ~~Report~~Chief ~~on Internal~~Executive ~~Control~~Officer ~~Over~~and Chief Financial ~~Reporting~~Officer concluded that the Partnership’s disclosure controls and procedures were effective as of December 31, 2009.

~~Management of~~This ~~PDC,~~2009 ~~the~~Annual ~~Managing~~Report ~~General~~on ~~Partner~~Form 10-K does not include an attestation report of the Partnership,’s isindependent ~~responsible~~registered ~~for establishing~~public ~~and~~accounting ~~maintaining~~firm ~~adequate~~regarding internal control over financial ~~reporting. Internal~~ ~~control over financial~~ reporting ispursuant ~~defined~~to ~~in Exchange~~Item ~~Act~~308T ~~Rules 13a-15~~(fa) ~~and 15d-15~~(f4) asof aRegulation ~~process~~S-K. Pursuant ~~designed~~to ~~by,~~Final orOrder ~~under the~~dated ~~supervision~~October of19, ~~the issuer’s principal executive and principal financial officers~~2009, ortemporary ~~persons~~Item ~~performing~~308T ~~similar~~was ~~functions,~~extended ~~and~~through ~~effected~~December ~~by the issuer’s board of directors~~15, ~~management and other personnel~~2010. Accordingly, tothe ~~provide~~Partnership ~~reasonable assurance~~will ~~regarding~~file the ~~reliability~~attestation report of ~~financial reporting and~~ the ~~preparation of~~Partnership’s ~~financial~~independent ~~statements~~registered ~~for~~public ~~external~~accounting ~~purposes~~firm inregarding ~~accordance~~internal control with ~~accounting principles generally accepted in~~ the ~~United~~Partnership’s ~~States~~Annual ofReport ~~America~~on ~~and~~Form ~~includes~~10-K ~~those policies~~as ~~and~~of ~~procedures~~December ~~that:~~31, 2010.

~~Pertain to~~(b) Remediation ~~the maintenance~~ of ~~records~~Material ~~that~~Weakness in ~~reasonable~~Internal ~~detail accurately and fairly reflect the transactions and dispositions of the assets of the issuer;~~Control

·PDC, ~~Provide~~the ~~reasonable~~Managing ~~assurance~~General ~~that~~Partner, ~~transactions~~with ~~are~~participation ~~recorded~~from asthe ~~necessary~~Audit toCommittee ~~permit preparation~~ of ~~financial~~its ~~statements~~Board inof ~~accordance~~Directors, ~~with~~addressed ~~accounting~~the ~~principles~~material ~~generally~~weakness ~~accepted~~disclosed in the ~~United~~Partnership’s ~~States~~2008 ofAnnual ~~America~~Report ~~and~~on Form 10-K. The Managing General Partner believes that ~~receipts~~the ~~and~~effective ~~expenditures~~implementation of ~~the~~changes ~~issuer~~in ~~are~~internal ~~being~~controls ~~made~~over ~~only~~financial inreporting ~~accordance~~outlined ~~with~~below ~~authorizations~~remediated ofthis ~~management~~known ~~and~~material ~~directors~~weakness as of ~~the~~December ~~issuer;~~31, ~~and~~2009.

·The ~~Provide~~Partnership ~~reasonable~~made ~~assurance~~the ~~regarding~~following ~~prevention~~changes orin ~~timely~~its ~~detection~~internal ofcontrol ~~unauthorized~~over ~~acquisition,~~financial ~~use~~reporting ~~or disposition~~ of the ~~issuer’s~~Partnership ~~assets~~(as ~~that~~defined ~~could~~in ~~have~~Rules a13a-15(f) ~~material~~and ~~effect~~15d-15(f) onof the ~~financial~~Securities ~~statements~~Exchange Act of ~~the~~1934) ~~issuer~~during 2009.

· ~~Because~~In ofthe ~~its~~second ~~inherent limitations~~quarter, ~~internal~~the ~~control~~Partnership developed and implemented a plan to improve controls over certain key financial ~~reporting~~statement ~~may~~spreadsheets ~~not~~that ~~prevent~~support orall ~~detect~~significant ~~misstatements~~balance sheet and income statement accounts. ~~Also,~~The ~~projections~~Partnership ofalso ~~any~~created ~~evaluation~~and ofdocumented ~~effectiveness~~a procedural framework to ~~future~~ensure ~~periods~~the ~~are~~completeness ~~subject~~and toaccuracy of the ~~risk~~Partnership’s ~~that~~derivative ~~controls~~activities. ~~may~~Additionally, ~~become~~the ~~inadequate~~Partnership ~~because~~has completed the development of ~~changes~~a inrevised ~~conditions,~~financial orclose and reporting narrative that adequately describes the ~~degree~~process, ofidentifies ~~compliance~~key ~~with~~controls ~~policies~~and orassesses ~~procedures~~segregation ~~may~~of ~~deteriorate~~duties.

Management of the Managing General Partner has assessed the effectiveness of the Partnership’s internal control over financial reporting as of December 31, 2008, based upon the criteria established in “Internal Control - ~~Integrated~~27 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 did not maintain effective internal control over financial reporting as of December 31, 2008 due to the material weakness discussed below. A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the registrant’s annual or interim financial statements will not be prevented or detected on a timely basis. Management of PDC, the Managing General Partner, identified the following material weakness related to the effectiveness of the Partnership’s internal control over financial reporting as of December 31, 2008:-

- 41 -

Index

· ~~For~~In the ~~transactions~~third quarter, the Partnership developed documentation that ~~are~~describes ~~directly~~the ~~related~~business toprocesses and ~~processed~~identifies bykey ~~the~~controls ~~Partnership,~~for ~~the~~internal ~~Partnership~~control ~~failed~~over tofinancial ~~maintain~~reporting ~~sufficient~~that ~~documentation~~assisted tothe ~~adequately~~Managing ~~assess~~General ~~the~~Partner ~~operating~~in ~~effectiveness~~adequately ofassessing internal control over financial reporting for the Partnership. ~~More~~In ~~specifically~~addition, the Partnership’s ~~financial~~developed ~~close~~documentation and ~~reporting~~procedures ~~narrative failed~~ to adequately ~~describe~~assess ~~the~~segregation ~~process,~~of ~~identify~~duties. ~~key~~The controls and ~~assess~~procedures ~~segregation~~were oftested ~~duties~~prior to December 31, 2009. ~~This~~At ~~material~~present, ~~weakness~~the Partnership has not ~~been~~quantified ~~remediated~~the total cost of this initiative; however, the majority of this cost is expected to be paid by the Managing General Partner.

This Annual Report does not include an attestation report of the Partnership’s independent registered public accounting firm regarding internal control over financial reporting which is not required to be included until the 2010 Annual Report is filed, pursuant to the final implementation extension of Item 308T (ac)~~(4)~~ Other ofChanges ~~Regulation~~in ~~S-K,~~Internal ~~granted~~Control byover ~~the~~Financial ~~SEC on October 2, 2009.~~Reporting

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

~~Management~~ · Effective July 1, 2009, as part of PDC’s broader financial reporting system, PDC implemented a new partnership investor distribution accounting module replacing the ~~Managing~~existing ~~General~~accounting ~~Partner~~software. ~~identified~~PDC has taken the ~~following~~necessary ~~material~~steps ~~weaknesses~~ 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 ~~effectiveness~~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 ~~Partnership~~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 is ongoing and is included in the scope of PDC’s assessment of its internal control over financial reporting as of December 31, ~~2007:~~2009.

· The ~~support~~Managing ~~for~~General ~~the~~Partner ~~Partnership’s~~continues ~~general~~to ~~ledger~~evaluate ~~depends~~the inongoing ~~part~~effectiveness onand sustainability of the ~~effectiveness~~changes ofPDC ~~controls~~made ofin ~~the~~internal ~~Managing~~control ~~General~~over ~~Partner’s~~financial ~~spreadsheets.~~reporting, ~~The~~and ~~overall~~as ~~ineffectiveness~~a result of the ~~Managing~~ongoing ~~General~~evaluation, ~~Partner's~~may ~~spreadsheet~~identify ~~controls~~additional ~~could~~changes ~~have~~to aimprove ~~material~~internal ~~effect~~control onover ~~the Partnership’s~~ financial ~~statements~~reporting. Further ~~The~~information ~~Partnership~~regarding ~~did~~the ~~not~~material ~~maintain~~weakness ~~effective~~of ~~controls~~the toPartnership ~~ensure~~referenced ~~the~~above ~~completeness,~~may ~~accuracy,~~be ~~and~~found ~~validity~~in ofthe ~~key~~Partnership’s ~~financial~~Annual ~~statement~~Report ~~spreadsheets~~on ~~generated~~10-K byfor the ~~Managing~~year ~~General~~ended ~~Partner.~~December ~~These~~31, ~~spreadsheets~~2008 ~~are~~under ~~utilized~~Item by9A ~~the~~(T), ~~Partnership~~Controls toand ~~support~~Procedures ~~significant~~− ~~balance~~Management’s ~~sheet~~Report ~~and~~on ~~income~~Internal ~~statement~~Control ~~accounts~~Over Financial Reporting.

· 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 effectiveness 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.

The Partnership made no changes in its internal control over financial reporting (such as defined in Rules 13a-15(f) and 15d-15(f) of the Securities Exchange Act of 1934) during the quarter ended December 31, 2008. During the first and third quarters of 2008, the Managing General Partner made the following changes in the Partnership's internal control over financial reporting that has materially affected, or is reasonably likely to materially affect, the Partnership's internal controls over financial reporting:

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 Managing General Partner had planned to implement a Partnership distribution module in 2008, however, the Managing General Partner currently expects this module to be in place during 2009. The new financial system enhanced operating efficiencies and provided more effective management of Partnership business operations and processes. The Managing General Partner believes the phased-in implementation approach it is taking reduces the risks associated with the new financial system implementation. 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 these new systems was included in the scope of the Managing General Partner's assessment of the Partnership's internal control over financial reporting for 2008.

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Index

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 documentation 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.

Based on the changes in the Managing General Partner’s internal control over financial reporting discussed above, the Managing General Partner has concluded that the first two material weaknesses which were identified as of December 31, 2007 had been remediated as of December 31, 2008.

Item 9B. Other Information

None

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Index

PART III

Item 10. Directors, Executive Officers and Corporate 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 orand executive officers~~. The~~ ~~Partnership is~~and ~~managed~~other bykey employees receive direct remuneration, compensation or reimbursement solely from PDC, and not the ~~Managing~~Partnership, ~~General~~with ~~Partner~~respect to services rendered in their capacity to act on behalf of the Partnership.

~~PDC, a publicly~~-~~owned~~ ~~Nevada~~28 corporation, was organized in 1955. The common stock of PDC is traded on the NASDAQ Global Select Market under the symbol "PETD." Since 1969, PDC has been engaged in the business of exploring for, developing and producing oil and gas primarily in West Virginia, Tennessee, Pennsylvania, Ohio, Michigan and the Rocky Mountains. As of December 31, 2008, PDC had approximately 317 employees. PDC will make available to Investor Partners, upon request, audited financial statements of PDC for the most recent fiscal year and unaudited financial statements for interim periods. PDC's Internet address is www.petd.com. PDC posts on its Internet Web site its periodic and current reports and other information, including its audited financial statements, that it files with the SEC, as well as various charters and other corporate governance information.-

As the Managing General Partner, PDC actively manages and conducts the business of the Partnership. PDC has the full authority under the D&O Agreement to conduct the Partnership's business. PDC is responsible for maintaining Partnership bank accounts, collecting Partnership revenues, making distributions to the partners, delivering reports to the partners, and supervising the drilling, completion, and operation of the Partnership's natural gas and oil wells. The executive officers of PDC are full-time employees of PDC. As such, these individuals devote the entirety of their daily time to the business and operations of PDC. An element of these individuals’ job responsibilities requires that they devote such time and attention to the business and affairs of the Partnership as is reasonably required. This time commitment varies for each individual and may vary over the life of the Partnership.Index

~~In addition~~Board toManagement ~~managing the affairs of the Partnership, the management~~ and ~~technical~~ ~~staff~~Risk of PDC also manage the corporate affairs of PDC, the affairs of 32 other limited partnerships and other joint ventures formed over the years. PDC owns an interest in all of the 32 limited partnerships for which it acts as Managing General Partner. Because PDC must divide its attention and efforts among many unrelated parties, the Partnership does not receive PDC’s full attention or efforts at all times, however, PDC believes that it devotes sufficient time, attention and expertise to the Partnership to appropriately manage the affairs of the Partnership.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. With respect to the separation of the offices of Chairman and Chief Executive Officer, or CEO, the Board believes it is most prudent to address this issue as a part of its succession planning process and to make a final determination based on the facts and circumstances at the time of the Chairman’s election, annually or as circumstances warrant.

The Board has established the Planning and Finance Committee to oversee the responsibilities of the Board related to planning and finance with respect to the risk assessment and management process that includes 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. The 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 the integrity of the financial reporting systems and internal controls as well as PDC’s legal and regulatory compliance. In addition to these two standing committees, the Board has created a Special Committee that has considered, upon Board request, the potential repurchase of certain of the sponsored drilling partnerships for which PDC serves as Managing General Partner.

Managing General Partner Duties and Resource Allocation

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

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

Market-responsive oil and gas marketing and prudent field operations cost management which support predictable cash flows; and

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

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

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

~~PDC~~- ~~is contracted~~29 to serve as operator for the Partnership wells. Since 1969, PDC has drilled wells in Colorado, West Virginia, Tennessee, Michigan, North Dakota, Kansas, Wyoming, Texas and Pennsylvania. PDC currently operates approximately 4,712 wells.-

PDC employs geologists who develop opportunities for drilling by PDC and who help oversee the drilling process. In addition, PDC has an engineering staff that is responsible for well completions and recompletions, pipelines, and production operations. PDC retains drilling subcontractors, completion subcontractors, and a variety of other subcontractors in the performance of the work of drilling contract wells. In addition to technical management, 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 an oil and natural gas field employee who provides skilled general labor for assembling well components and other similar tasks. PDC may lay short gathering lines, or may subcontract all or part of the work where it is more cost effective for the Partnership. PDC employs full-time well tenders and supervisors to operate its wells. In addition, the engineering staff evaluates oil and natural gas reserves of all wells at least annually and reviews individual well performance against expectations. All services provided by PDC are provided at rates less than or equal to prevailing rates for similar services provided by unaffiliated persons in the area.

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Index

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

Petroleum Development Corporation

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

Name	Age	Positions and Offices Held	Director Since	Directorship Term Expires
Richard W. McCullough	5758	Chairman and Chief Executive Officer	2007	2010
Gysle R. Shellum	5758	Chief Financial Officer	-	-
R. Scott Meyers	35	Chief Accounting Officer	-	-
Daniel W. Amidon	49	General Counsel and Secretary	-	-
Barton R. Brookman, Jr.	47	Senior Vice President Exploration and Production	-	-
Lance Lauck	4647	Senior Vice President Business Development	-	-
Vincent F. D'Annunzio	57	Director	1989	2010
Jeffrey C. Swoveland	54	Director	1991	2011
Kimberly Luff Wakim	51	Director	2003	2012
David C. Parke	4243	Director	2003	2011
Anthony J. Crisafio	5657	Director	2006	2012
Joseph E. Casabona	66	Director	2007	2011
Larry F. Mazza	49	Director	2007	2010
James M. Trimble	61	Director	2009	2010

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Index

Richard W. McCullough was appointed Chief Executive Officer in June 2008 and Chairman in November 2008. Mr. McCullough also served PDC as President since March 2008. Mr. McCullough served as Chief Financial Officer from November 2006 until November 2008. Prior to joining PDC, Mr. McCullough served as an energy consultant from July 2005 to November 2006. From January 2004 to July 2005, Mr. McCullough served as President and Chief Executive Officer of Gasource, LLC, Dallas, Texas, a marketer of long-term, natural gas supplies. From 2001 to 2003, Mr. McCullough served as an investment banker with J.P. Morgan Securities, Atlanta, Georgia, and served 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. Mr. McCullough, a CPA, was a practicing certified public accountant for 8 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 effective November 11, 2008. Prior to joining PDC, Mr. Shellum served as Vice President, Finance and Special Projects of Crosstex Energy, L.P., Dallas, Texas. Mr. Shellum served in this capacity from September 2004 through September 2008. Prior thereto from March 2001 until September 2004, Mr. Shellum served as a consultant to Value Capital, a private consulting firm in Dallas, where he worked on various projects, including corporate finance and Sarbanes-Oxley Act compliance. Crosstex Energy, L.P. is a publicly traded Delaware limited partnership, whose securities are listed on the NASDAQ Global Select Market and is an independent midstream energy company engaged in the gathering, transmission, treating, processing and marketing of natural gas and natural gas liquids.

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Index

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.

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

Barton 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.

Lance Lauck was appointed Senior Vice President Business Development on August 31, 2009. Prior to joining PDC, Mr. Lauck served as Vice President Acquisitions and Business Development with Quantum Resources Management, LLC based in Denver Colorado. Beginning in June 2006, Mr. Lauck was responsible for valuation and acquisition of oil and gas exploration and production properties. Prior to his employment at Quantum Resources, Mr. Lauck was employed by Anadarko Petroleum Corporation from 1988 to 2006 in The Woodlands, Texas. Mr. Lauck served Anadarko in various capacities beginning as a Senior Production Engineer and exited as General Manager, Corporate Development.

Vincent F. D’Annunzio has served as president of Beverage Distributors, Inc. located in Clarksburg, West Virginia since 1985. Mr. D’Annunzio serves as Chairman of the Nominating and Governance Committee and serves on the Executive Committee and the Compensation Committee.

Jeffrey C. Swoveland has served as Chief Operating Officer of ReGear, Inc. (previously named Coventina Healthcare Enterprises), a medical device company that develops and markets products which reduce pain and increase the rate of healing through therapeutic, deep tissue heating, since May 2007. Previously, 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, from September 2000 to May 2007. 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.

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Index

Kimberly Luff Wakim, an Attorney and a Certified Public Accountant, is a Partner with the Pittsburgh, Pennsylvania law firm, Thorp, Reed & Armstrong LLP, where she serves as a member of the Executive Committee. Ms. Wakim has practiced law with Thorp, Reed & Armstrong LLP since 1990. Ms. Wakim serves as Chairman of the Compensation Committee and serves on the Audit Committee and the Nominating and Governance Committee.

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

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Index

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

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 to his retirement in May 2007. Mr. Casabona’s responsibilities included strategic planning as well as executive oversight of the drilling operations in the continental United States and internationally. In 2008 Mr. Casabona assumed the title of Chief Executive Officer of Paramax Resources Ltd, a junior public Canadian oil & gas company (PMXRF) engaged in the business of acquiring and exploration of oil and gas prospects, primarily in Canada and Idaho. Mr. Casabona serves as Chairman of the Planning and Finance Committee and serves on the Audit Committee.

Larry F. Mazza is President and Chief Executive Officer of MVB Financial Corporation 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 such position, Mr. Mazza served as Senior Vice President Retail Banking Manager & President & CEO for BB&T and its predecessors in West Virginia, where he was employed from June 1986 to March 2005. Mr. Mazza serves on the Nominating and Governance Committee and the Compensation Committee.

James M. Trimble serves as Managing Director and Chief Executive Officer of the parent and US subsidiaries of Grand Gulf Energy Limited, a public company traded on the Australian Exchange. In January 2005, Mr. Trimble founded Grand Gulf Energy Company LLC, an Exploration and Development company focused primarily on drilling in mature basins in Texas, Louisiana, and Oklahoma. Prior to founding Grand Gulf Energy, Mr. Trimble served as President, Chief Executive Officer and Chairman of the Board of TexCal Energy LLC from June 2002 through December 2004. From July 2000 to December 2001, Mr. Trimble was President and a member of the Board of Directors of Elysium Energy L.L.C., an exploration and production company. From 1983 to 2000, he served as Senior Vice President – Exploration and Production of Cabot Oil and Gas Company, a publicly held, mid-sized exploration and production company. Mr. Trimble serves on the Planning and Finance Committee.

The Audit Committee of the Board of Directors is comprised of Directors Swoveland, Crisafio, Wakim and Casabona. The Board has determined that the Audit Committee is comprised entirely of independent directors as defined by the NASDAQ rule 4200(a) (15). Anthony J. Crisafio chairs the Audit Committee. All audit committee members qualify as audit committee financial experts ~~and are independent of management~~.

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Index

Item 11. Executive Compensation

The Partnership does not have any ~~employees~~ or executives of its own. None of PDC's ~~officers~~directors or ~~directors~~executive officers receive any direct remuneration, compensation or reimbursement from the Partnership. These persons receive compensation solely from PDC. ~~The~~None ~~management~~of ~~fee~~PDC’s compensation policies and ~~other~~practices ~~amounts~~that ~~paid~~are available to ~~the~~key ~~Managing General~~employees, ~~Partner~~executive byofficers ~~the~~or ~~Partnership~~directors ~~are~~who ~~not~~act ~~used~~on tobehalf ~~directly~~of ~~compensate~~the ~~or reimburse~~Partnership ~~PDC’s~~are ~~officers~~reasonably orlikely ~~directors. No~~to ~~management~~have ~~fee~~a ~~was~~material ~~paid~~adverse ~~to PDC~~effect inon ~~2008~~the orPartnership’s ~~2007~~operations asor ~~the~~conduct ~~Partnership~~of isPDC ~~not~~when ~~required~~carrying toout ~~pay~~duties aand ~~management~~responsibilities ~~fee other~~to ~~than~~the aPartnership ~~one~~as ~~time~~Managing ~~fee~~General ~~paid~~Partner inunder the ~~initial~~Agreement, ~~year~~or ofas ~~formation~~operator ~~per~~under the D&O Agreement. The ~~Partnership~~management ~~pays a monthly~~ fee ~~for~~and ~~each~~other ~~producing~~amounts ~~well based~~paid ~~upon~~to ~~competitive~~the ~~industry~~Managing ~~rates~~General ~~for~~Partner ~~operations~~by ~~and~~the ~~field~~Partnership ~~supervision~~are ~~and $75~~not ~~per~~used ~~well~~to ~~per~~directly ~~month~~compensate ~~for~~or ~~Partnership~~reimburse ~~related~~PDC’s ~~general~~officers ~~and~~or ~~administrative expenses~~directors. For ~~that~~more ~~include~~information ~~accounting,~~on ~~engineering~~the ~~and~~Partnership’s ~~management~~compensation ofto the ~~Partnership by the~~ Managing General Partner~~. See~~, 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~~below.

Compensation Committee Interlocks and Insider Participation

There are no Compensation Committee interlocks.

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Index

Item 12.

Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

AsThe ~~of September~~following ~~30,~~table ~~2009~~presents ~~the~~information ~~Partnership~~as ~~had 899.94 units~~ of ~~limited~~December ~~partnership interest~~31, ~~and~~2009 noconcerning ~~units~~the ofManaging ~~additional~~General ~~general~~Partner’s ~~partnership~~ interest ~~outstanding. No~~ ~~director~~in orthe ~~officer~~Partnership ofand ~~PDC~~other ~~owns~~persons ~~any units. Subject~~known toby ~~certain conditions, individual investor partners may present their units to PDC for purchase. Pursuant to~~ the Partnership ~~Agreement, PDC is not obligated~~ to ~~purchase~~own beneficially more than 105% of the ~~total~~ ~~outstanding~~interests ~~units~~ in ~~any~~the ~~calendar year if such units are presented to PDC for repurchase~~Partnership. AsEach ofpartner ~~June~~exercises ~~30,~~sole ~~2009,~~voting ~~PDC~~and ~~has~~investing ~~purchased~~power ~~17.02 Partnership~~with ~~units~~respect ~~from~~to ~~Investor~~the ~~Partners. PDC owns a 20% Managing General Partner partnership~~ interest inbeneficially ~~the Partnership~~owned.

	Limited Partnership Units
Person or Group	Number of Units Outstanding Which Represent 80% of Total Partnership Interests (1)		Number of Units Beneficially Owned		Percentage of Total Units Outstanding			Percentage of Total Partnership Interests Beneficially Owned
		899.94
Petroleum Development Corporation (2) (3)		-		18.02		2.00	%		1.60	%
Investor Partners beneficially owning 5% or more, of limited partner interests		-		-		-			-
Petroleum Development Corporation (2), Managing General Partner		-		-		-			20.00	%

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

(2)	Petroleum Development Corporation, 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.

Item 13. Certain Relationships and Related Transactions, and Director Independence

Compensation to the Managing General Partner and Affiliates

The Managing General Partner transacts all of the Partnership’s business on behalf of the Partnership. ~~See~~ Under ~~Note~~the 3D&O Agreement, ~~Transactions~~PDC ~~with~~provides ~~Managing~~all ~~General Partner~~necessary labor, vehicles, supervision, management, accounting, and ~~Affiliates~~overhead toservices ~~the~~for ~~accompanying~~normal ~~financial~~production ~~statements~~operations, and may deduct from Partnership revenues a fixed monthly charge for ~~information~~ ~~regarding~~these ~~compensation~~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 ~~transactions~~administration ~~with~~fees may be adjusted annually to an amount equal to the ~~Managing~~rates ~~General Partner~~initially established by the Drilling and ~~affiliates~~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

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

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

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

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

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

PDC retains drilling subcontractors, completion subcontractors and a variety of other subcontractors in the performance of the work of drilling contract wells. In addition to technical management, 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 an oil and natural gas field employee who provides skilled general labor for assembling well components and other similar tasks. PDC may lay short gathering lines, or may subcontract all or part of the work where it is more cost effective for the Partnership.

See Note 3, 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 ~~Limited~~ ~~Partnership~~ Agreement and the ~~Drilling~~D&O ~~and Operating~~ Agreement with Petroleum Development Corporation 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 the agreements.

Other Agreements and Arrangements

Executive officers of the Managing General Partner ~~are~~were eligible to invest in ~~a Board-approved~~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.

~~These~~ Through the executive drilling program, certain former executive officers ~~may~~of ~~profit~~PDC ~~from~~invested ~~their~~in ~~participation~~the wells developed by PDC in which the Partnership invested. The executive ~~drilling~~ program ~~because~~allowed ~~they~~PDC ~~invest~~to sell working interests to PDC executive officers in the wells atthat ~~cost~~PDC ~~and~~developed dofor ~~not~~the ~~have~~Partnership. Participating officers thereby owned parallel undivided working interests in all of the wells that the Partnership has invested in. Prior to ~~pay~~the ~~drilling compensation~~funding of the Partnership, ~~management~~each ~~fees~~executive orofficer ~~broker~~who ~~commissions~~chose to participate in the executive program advised PDC of the dollar amount of his investment participation, and ~~therefore~~thereby ~~obtain~~acquired an a working interest in the wells atin which the Partnership acquired a ~~reduced~~working ~~price~~interest, ~~than~~the ~~that~~acquired ~~which~~working isinterest ~~generally~~being ~~charged~~parallel to the ~~investing~~working ~~partners~~interest inof athe Partnership and the investor partners. ~~Investor~~The ~~partners participating~~officers’ percentage in ~~drilling~~certain ~~through~~wells ais ~~partnership~~proportionate ~~are~~to ~~generally~~the ~~charged~~Partnership’s aworking ~~profit or~~interest ~~markup~~among ~~above~~all of the ~~cost~~Partnership’s ofwells based upon the officers’ investment amount. PDC had the option to sell working interests in these wells to other parties unaffiliated with PDC, ~~management~~prior ~~fees~~to ~~and~~the ~~commissions~~funding atof ~~rates which~~the ~~are~~Partnership. The ~~generally~~aggregate ~~similar~~ownership percentage of these former executive officers ranges from .1269% to ~~those~~.145% ~~for~~of ~~this~~each well in the Partnership. The ~~outlined~~Board inbelieved ~~Note~~that ~~3, Transactions~~having ~~with~~the ~~Managing General~~executive ~~Partner~~officers invest in wells with PDC and ~~Affiliates~~other investor partners helped to create a commonality of interests much like share ownership creates a commonality of interests between the ~~accompanying~~shareholders ~~financial statements~~and executive officers. As of March 1, 2010, no current executive officer owns any beneficial interest in the Partnership.

~~Through the~~- ~~executive~~34 drilling program, certain former executive officers 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 will develop for the Partnership. Participating officers thereby own 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 each well is proportionate to the Partnership’s working interest among all of the Partnership’s wells based upon the officers’ investment amount. PDC may also 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 .1269% to .145% of each well in the Partnership. The Board believes that having the executive officers invest in wells with PDC and other investor partners helps to create a commonality of interests much like share ownership creates a commonality of interests between the shareholders and executive officers.-

- 48 -

Index

Director Independence

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

Item 14. Principal Accountant Fees and Services

~~There were~~The ~~audit~~following ~~billings~~table presents amounts charged by from the Partnership’s independent registered public accounting firm, PricewaterhouseCoopers LLP (“PwC”), ~~of approximately $145,000 and $82,000~~ for the ~~audits for the~~ years ended December 31, 2008 and 2007, respectively. For the years ended December 31, 2008 and 2007, there were tax billings from the Partnership’s independent registered public accounting firm, PwC, of approximately $7,000 and $8,000, respectively.described:

	Year Ended December 31,
Type of Service	2009		2008

Audit Fees (1)	$	185,000	$	145,000
Tax Fees (2)		3,000		7,000
Total fees	$	188,000	$	152,000

(1)

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

(2)

Tax fees consist primarily of professional services fees billed for preparation of the Partnership’s annual IRS Form 1065 and individual partners’ Schedule K-1.

Audit Committee Pre-Approval Policies and Procedures

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

- 35 -

Index

Item 15. Exhibits, Financial Statement 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~~

Filed Herewith

3.1

Limited Partnership Agreement

10-K

000-51219

3.1

08/05/2009

3.2

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

10-K

000-51219

3.2

~~08/05/2009~~

08/05/2009

10.1

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

10-K

000-51219

10.1

~~08/05/2009~~

08/05/2009

10.3

Audited Consolidated Financial Statements for the year ended December 31, ~~2008~~2009 of Petroleum Development Corporation and its subsidiaries, as Managing General Partner of the Partnership

10-K

000-07246

~~02/27/2009~~

03/04/2010

23.1

Consent of Ryder Scott Company, L.P., Petroleum Consultants

31.1

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

31.2

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

32.1

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

- 49 36 -

Index

Incorporated by Reference

Exhibit Number

Exhibit Description

Form

SEC File Number

Exhibit

Filing Date

Filed Herewith

23.1

Consent of Ryder Scott Company, L.P., Petroleum Consultants

31.1

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

31.2

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

32.1

- 50 -

Index

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 2004-B Limited Partnership

By its Managing General Partner

Petroleum Development Corporation

By /s/ Richard W. McCullough

Richard W. McCullough

Chairman and Chief Executive Officer

~~October 23~~March 15, ~~2009~~2010

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

Signature	Title	Date
/s/ Richard W. McCullough	Chairman and Chief Executive Officer	~~October~~March 2315, ~~2009~~2010
Richard W. McCullough	Petroleum Development Corporation
	Managing General Partner of the Registrant
	(Principal executive officer)
/s/ Gysle R. Shellum	Chief Financial Officer	~~October~~March 2315, ~~2009~~2010
Gysle R. Shellum	Petroleum Development Corporation
	Managing General Partner of the Registrant
	(Principal financial officer)
/s/ R. Scott Meyers	Chief Accounting Officer	~~October~~March 2315, ~~2009~~2010
R. Scott Meyers	Petroleum Development Corporation
	Managing General Partner of the Registrant
	(Principal accounting officer)
/s/ Kimberly Luff Wakim	Director	~~October~~March 2315, ~~2009~~2010
Kimberly Luff Wakim	Petroleum Development Corporation
	Managing General Partner of the Registrant
/s/ Anthony J. Crisafio	Director	~~October~~March 2315, ~~2009~~2010
Anthony J. Crisafio	Petroleum Development Corporation
	Managing General Partner of the Registrant
/s/ Jeffrey C. Swoveland	Director	~~October~~March 2315, ~~2009~~2010
Jeffrey C. Swoveland	Petroleum Development Corporation
	Managing General Partner of the Registrant
/s/ Joseph E. Casabona	Director	~~October~~March 2315, ~~2009~~2010
Joseph E. Casabona	Petroleum Development Corporation
	Managing General Partner of the Registrant

- 51 37 -

Index

PDC 2004-B LIMITED PARTNERSHIP

Index to Financial Statements

Report of Independent Registered Public Accounting Firm	F-2
Balance Sheets - December 31, 2008 and 2007	F-3
Balance Sheets - December 31, 2009 and 2008	F-3
Statements of Operations - For the Years Ended December 31, 2008 and 2007	F-4
Statements of Operations - For the Years Ended December 31, 2009 and 2008	F-4
Statements of Partners' Equity - For the Years Ended December 31, 2008 and 2007	F-5
Statements of Partners' Equity - For the Years Ended December 31, 2009 and 2008	F-5
Statements of Cash Flows - For the Years Ended December 31, 2008 and 2007	F-6
Statements of Cash Flows - For the Years Ended December 31, 2009 and 2008	F-6
Notes to Financial Statements	F-7
Supplemental Oil and Gas Information - Unaudited	F-2625
Unaudited Condensed Quarterly Financial Statements:
Balance Sheets - 2008	F-30
Balance Sheets - 2007	F-31
Statements of Operations - 2008	F-32
Statements of Operations - 2007	F-33
Statements of Cash Flows - 2008	F-34
Statements of Cash Flows - 2007	F-35
Notes to Unaudited Condensed Quarterly Financial Statements	F-36

F-1

Index

PricewaterhouseCoopers LLP 600 Grant Street Pittsburgh PA 15219 Telephone (412) 355 6000 Facsimile (412) 355 8089

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Partners of the PDC 2004-B 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 2004-B Limited Partnership (the "Partnership") at December 31, ~~2008~~2009 and ~~2007~~2008, and the results of its operations and its cash flows for each of the two years in the period ended December 31, ~~2008~~ 2009 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 3 to the financial statements, the Partnership has significant related party transactions with Petroleum Development Corporation and its subsidiaries.

/s/ PricewaterhouseCoopers LLP

Pittsburgh, Pennsylvania

~~October 22~~March 15, ~~2009~~2010

F-2

Index

PDC 2004-B LIMITED PARTNERSHIP

Balance Sheets

Balance Sheets
As of December 31, 2009 and 2008


Assets	2009			2008

Current assets:
Cash and cash equivalents	$	818		$	91,612
Accounts receivable		133,846			147,587
Oil inventory		14,634			21,608
Due from Managing General Partner-derivatives		270,075			995,593
Due from Managing General Partner-other, net		171,143			964,412
Total current assets		590,516			2,220,812


Oil and gas properties, successful efforts method, at cost		20,180,948			20,106,098
Less: Accumulated depreciation, depletion and amortization		(9,475,278	)		(8,156,676	)
Oil and gas properties, net		10,705,670			11,949,422

Due from Managing General Partner-derivatives		288,344			319,803
Due from Managing General Partner-other, net		-			-
Other assets		19,067			7,464
Total noncurrent assets		11,013,081			12,276,689


Total Assets	$	11,603,597		$	14,497,501


Liabilities and Partners' Equity

Current liabilities:
Accounts payable and accrued expenses	$	18,806		$	30,331
Due to Managing General Partner-derivatives		282,174			-
Due to Managing General Partner-other		-			-
Total current liabilities		300,980			30,331

Due to Managing General Partner-derivatives		821,918			100,327
Due to Managing General Partner-other		-
Asset retirement obligations		240,559			161,487
Total liabilities		1,363,457			292,145

Commitments and contingent liabilities

Partners' equity:
Managing General Partner		2,051,899			2,844,942
Limited Partners - 899.94 units issued and outstanding		8,188,241			11,360,414
Total Partners' equity		10,240,140			14,205,356

Total Liabilities and Partners' Equity	$	11,603,597		$	14,497,501

As of December 31, 2008 and 2007

Assets	2008			2007
Current assets:
Cash and cash equivalents	$	91,612		$	43,507
Accounts receivable		147,587			365,136
Oil inventory		21,608			-
Due from Managing General Partner-derivatives		995,593			30,002
Due from Managing General Partner-other, net		964,412			821,800
Total current assets		2,220,812			1,260,445
Oil and gas properties, successful efforts method, at cost		20,106,098			20,135,900
Less: Accumulated depreciation, depletion and amortization		(8,156,676	)		(6,758,975	)
Oil and gas properties, net		11,949,422			13,376,925
Due from Managing General Partner-derivatives		319,803			-
Due from Managing General Partner-other, net		-			83,133
Other assets		7,464			-
Total noncurrent assets		12,276,689			13,460,058
Total Assets	$	14,497,501		$	14,720,503
Liabilities and Partners' Equity
Current liabilities:
Accounts payable and accrued expenses	$	30,331		$	36,555
Due to Managing General Partner-derivatives		-			68,645
Total current liabilities		30,331			105,200
Due to Managing General Partner-derivatives		100,327			-
Asset retirement obligations		161,487			152,707
Total liabilities		292,145			257,907
Partners' equity:
Managing General Partner		2,844,942			2,896,389
Limited Partners - 899.94 units issued and outstanding		11,360,414			11,566,207
Total Partners' equity		14,205,356			14,462,596
Total Liabilities and Partners' Equity	$	14,497,501		$	14,720,503

See accompanying notes to financial statements.

F-3

Index

PDC 2004-B LIMITED PARTNERSHIP

Statements of Operations

Statements of Operations
For the Years Ended December 31, 2009 and 2008


	2009			2008
Revenues:
Natural gas and oil sales	$	1,412,764		$	3,763,882
Commodity price risk management (loss) gain, net		(539,884	)		1,324,026
Total revenues		872,880			5,087,908

Operating costs and expenses:
Natural gas and oil production costs		606,138			901,832
Direct costs - general and administrative		547,088			102,909
Depreciation, depletion and amortization		1,318,602			1,397,701
Accretion of asset retirement obligations		5,290			8,780
Total operating costs and expenses		2,477,118			2,411,222

(Loss) income from operations		(1,604,238	)		2,676,686

Interest expense		(584	)		-
Interest income		21,489			38,335

Net (loss) income	$	(1,583,333	)	$	2,715,021

Net (loss) income allocated to partners	$	(1,583,333	)	$	2,715,021
Less: Managing General Partner interest in net (loss) income		(316,667	)		543,004
Net (loss) income allocated to Investor Partners	$	(1,266,666	)	$	2,172,017

Net (loss) income per Investor Partner unit	$	(1,408	)	$	2,414

Investor Partner units outstanding		899.94			899.94

For the Years Ended December 31, 2008 and 2007

	2008		2007
Revenues:
Oil and gas sales	$	3,763,882	$	3,019,510
Oil and gas price risk management gain (loss), net		1,324,026		(171,459	)
Total revenues		5,087,908		2,848,051
Operating costs and expenses:
Production and operating costs		901,832		776,600
Direct costs - general and administrative		102,909		49,037
Depreciation, depletion and amortization		1,397,701		1,388,803
Accretion of asset retirement obligations		8,780		8,304
Total operating costs and expenses		2,411,222		2,222,744
Income from operations		2,676,686		625,307
Interest income		38,335		49,440
Net income	$	2,715,021	$	674,747
Net income allocated to partners	$	2,715,021	$	674,747
Less: Managing General Partner interest in net income		543,004		134,949
Net income allocated to Investor Partners	$	2,172,017	$	539,798
Net income per Investor Partner unit	$	2,414	$	600
Investor Partner units outstanding		899.94		899.94

See accompanying notes to financial statements.

F-4

Index

PDC 2004-B LIMITED PARTNERSHIP

Statements of Partners' Equity

Statements of Partners' Equity
For the Years Ended December 31, 2009 and 2008

	Investor Partners			Managing General Partner			Total

Balance, December 31, 2007	$	11,566,207		$	2,896,389		$	14,462,596

Distributions to partners		(2,377,810	)		(594,451	)		(2,972,261	)

Filing Compare · PDC 2004-B Limited Partnership