UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

FORM 10-K

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

For the fiscal year ended December 31, 2008

or

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

Commission File Number  000-53201

Rockies Region 2007 Limited Partnership

(Exact name of registrant as specified in its charter)

West Virginia	20-0208835
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

1775 Sherman Street, Suite 3000, Denver, Colorado  80203

(Address of principal executive offices)     (zip code)

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

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

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

Title of Each Class

Limited Partnership Interests

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

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

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

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will 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.  T

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

Large accelerated filer     £	Accelerated filer     £
Non-accelerated filer     £	Smaller reporting company     T

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

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 March 31, 2009, the Partnership had 4,470 units of limited partnership interest and no units of general partnership interest outstanding.

ROCKIES REGION 2007 LIMITED PARTNERSHIP

INDEX TO REPORT ON FORM 10-K

		Page
	PART I
Item 1	Business	1
Item 1A	Risk Factors	13
Item 1B	Unresolved Staff Comments	21
Item 2	Properties	21
Item 3	Legal Proceedings	23
Item 4	Submission of Matters to a Vote of Security Holders	23
	PART II
Item 5	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	23
Item 6	Selected Financial Data	25
Item 7	Management’s Discussion and Analysis of Financial Condition and Results of Operations	25
Item 7A	Quantitative and Qualitative Disclosures About Market Risk	37
Item 8	Financial Statements and Supplementary Data	37
Item 9	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	37
Item 9A(T)	Controls and Procedures	37
Item 9B	Other Information	39
	PART III
Item 10	Directors, Executive Officers and Corporate Governance	39
Item 11	Executive Compensation	44
Item 12	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	44
Item 13	Certain Relationships and Related Transactions, and Director Independence	44
Item 14	Principal Accountant Fees and Services	45
	PART IV
Item 15	Exhibits, Financial Statement Schedules	46
Signatures		49
Financial Statements		F-1

PART I

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 (“Exchange Act”) regarding Rockies Region 2007 Limited Partnership’s (the “Partnership’s” or the “Registrant’s”) business, financial condition, results of operations and prospects that are subject to risks and uncertainties.  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 production and reserves, drilling plans, future cash flows, anticipated liquidity, anticipated capital expenditures and the Managing General Partner 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.  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 or future litigation and the costs incident thereto.

Further, the Partnership urges the reader to carefully review and consider the disclosures 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 Securities and Exchange Commission, or SEC.  Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date of this report.  The Partnership and Managing General Partner undertake 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.

Item 1. Business

General

The Partnership was organized as a limited partnership on May 22, 2007 (date of inception), under the West Virginia Uniform Limited Partnership Act.  Petroleum Development Corporation, a Nevada Corporation, is the Managing General Partner of the Partnership (hereafter, the “Managing General Partner,” “MGP” or “PDC”).  Upon completion of a private placement of its securities, the Partnership was funded on August 31, 2007 and commenced its business operations. The Partnership was funded with initial contributions of $89,402,885 from 1,778 limited and additional general partners (collectively, the “Investor Partners”) and a cash contribution of $38,659,808 from the Managing General Partner.  After payment of syndication costs of $9,070,450 and a one-time management fee to the Managing General Partner of $1,341,043, the Partnership had available cash of $117,651,200 to commence Partnership activities.  The Partnership owns natural gas and oil wells located in Colorado and from the wells, it produces and sells natural gas and oil.

- 1 -

Drilling Activities

The Partnership commenced drilling activities immediately following funding on August 31, 2007.  As of December 31, 2008, a total of 100 gross wells had been drilled and the activity for the applicable periods is reflected in the table below.  Wells drilled and not completed in 2007 became wells drilled, fractured and producing in 2008.  The Partnership’s 100 gross developmental wells drilled are located in the state of Colorado in the Rocky Mountain Region.  See Item 2, Properties for disclosure regarding the Partnership’s wells.

	Year 2008				Period May 22, 2007 (date of inception) Through December 31, 2007
	Gross		Net		Gross		Net
Development wells:
Drilled, fractured and producing		86.0		84.9		13.0		13.0
Drilled and not completed		-		-		40.0		39.7
Dry hole		-		-		1.0		1.0
Total		86.0		84.9		54.0		53.7

A development well is a well that is drilled close to and into the same formation as a well which has already produced and sold oil or natural gas.  The 100 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.

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

Business Segments

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

Plan of Operations

With regard to the Partnership’s wells drilled in Colorado, 75 developmental wells were drilled to the Codell formation in the Wattenberg Field and 25 Colorado wells were developmental wells drilled in the Grand Valley Field (one of which was determined to be a developmental dry hole) with the remaining 24 wells successfully completed and in production.

Partnership wells in the Wattenberg field were targeted to the Codell formation or deeper.  The Wattenberg Field, located north and east of Denver, Colorado, is in the Denver-Julesburg (DJ) Basin.  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 for most of the Partnership’s wells is the Codell which produces a combination of natural gas and oil.

Partnership wells in the Grand Valley field are targeted to the Mesa Verde formation. The Grand Valley Field is in the Piceance Basin, located near the western border of Colorado.  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.

- 2 -

The typical well production profile for wells in both the Wattenberg and Grand Valley fields 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 also produce oil.  For the natural gas, the purchase price 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.

PDC plans to recomplete most 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.  A recompletion consists of a second fracture treatment in the same formation originally fractured in the initial completion.  PDC and other producers have found that the recompletions generally increase the production rate and recoverable reserves of the wells.  On average, the production resulting from PDC's Codell recompletions has been above the modeled economics; however, all recompletions have not and may not be successful.  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 its proportionate share of costs based on the operating costs sharing ratios of the Partnership.  The Partnership may borrow the funds necessary to pay for the recompletions, and payment for those borrowings will be made from the Partnership production proceeds. Any such borrowings will be non-recourse to the Investor Partners in the Partnership.

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 Limited Partnership Agreement (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.  For additional information, see Item 2, Properties – Title to Properties.

Well Operations

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

PDC, in some cases, provides equipment and supplies, and performs salt water disposal services and other services for the Partnership.  PDC sold equipment to the Partnership as needed in the drilling or completion of Partnership wells.  All equipment and services were sold at the lesser of cost or competitive prices in the area of operations.

Gas Pipeline and Transmission.  All of the Partnership's wells are in the vicinity of transmission pipelines and gathering systems.  PDC believes there are sufficient transmission pipelines and gathering systems for the Partnership's natural gas production, subject to some seasonal curtailment and occasional limitations because of repairs, improvements or as a result of priority transportation agreements with other gas transporters.  Seasonal curtailment typically occurs during July and August as a result of high temperatures which reduce compressor capacity.  This reduction in production typically amounts to less than five percent of normal monthly production without an effect on pricing.  The cost, timing and availability of gathering pipeline connections and service varies from area to area, well to well, and over time.  In selecting prospects for the Partnership, PDC included in its evaluation the anticipated cost, timing and expected reliability of gathering connections and capacity. 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 can lead to lower natural gas prices relative to other areas as the producers compete for the available markets by reducing prices.  It can also lead to curtailments of production and periods when wells are shut-in due to lack of market.  The Partnership experienced shut in wells in October 2007 and third and fourth quarter 2008.  While the Partnership’s ability to market its natural gas has been only infrequently limited or delayed, if transportation space is restricted or unavailable, Partnership cash flows could be adversely affected.

- 3 -

Sale of Production.  The Partnership sells the oil and natural gas produced from its wells on a competitive basis at the best available terms and prices generally, under contracts with indexed monthly pricing provisions.  PDC does not make any commitment of future production that does not primarily benefit the Partnership.  Generally, purchase contracts for the sale of oil are cancelable on 30 days notice, whereas purchase contracts for the sale of natural gas may range from spot market sales of short duration to contracts with a term of a number of years and that may require the dedication of the natural gas from a well for a period ranging up to the life of the well.

The Partnership sells gas at negotiated prices based upon a number of factors, including the quality of the gas, well pressure, estimated reserves, prevailing supply conditions and any applicable price regulations promulgated by the Federal Energy Regulatory Commission, or FERC.  The Partnership sells oil produced by it to local oil purchasers at spot prices. The produced oil is stored in tanks at or near the location of the Partnership’s wells for routine pickup by oil transport trucks.

In general, the Partnership has been and expects to continue to be able to produce and sell natural gas from its 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. For instance, the Partnership experienced an approximate 10% to 15% curtailment of production in the Piceance Basin due to limited compression and pipeline capacity throughout most of fourth quarter 2008.  This interruption, due to third party infrastructure, was corrected in early 2009.

Price Risk Management.  Price volatility is a very significant and 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 maintains a conservative financial approach and proactively employs strategies to reduce the effects of commodity price volatility 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 and New York Mercantile Exchange, or NYMEX, based contracts for Colorado oil production.  The contracts provide price protection for committed and anticipated oil and natural gas sales, generally forecasted to occur within the next two to three-year period, but in no cases longer than five years beyond the derivative transaction date.  The Partnership's policies prohibit the use of oil and natural gas futures, 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, they do not qualify for use of hedge accounting 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.  See Note 2, Summary of Significant Accounting Policies−Derivative Financial Instruments, to the Partnership’s accompanying financial statements included in this report.

The Partnership is subject to price fluctuations for natural gas sold in the spot market and under market index contracts.  PDC, as Managing General Partner, continues to evaluate the potential for reducing these risks by entering into derivative transactions.  In addition, the Managing General Partner may close out any portion of derivatives that may exist from time to time which may result in a realized gain or loss on that derivative transaction.  The Partnership manages price risk on only a portion of its anticipated production, so the remaining portion of its production is subject to the full fluctuation of market pricing.  As of December 31, 2008, the Partnership has oil and natural gas derivatives in place covering substantially all of its expected oil production and 68% of its expected natural gas production for 2009.

The Partnership uses financial derivatives to establish “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 carried on the balance sheet at fair value with changes in fair values recognized currently in the statement of operations under the caption "Oil and gas price risk management gain (loss), net."  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.  For “swap” instruments, PDC as Managing General Partner, receives a fixed price for the hedged commodity and pays a floating market price to the counterparty. The fixed-price payment and the floating-price payment are netted, resulting in a net amount due to or from the counterparty. “Collars” contain a fixed floor price (put) and ceiling price (call). If the market price exceeds the ceiling strike price or falls below the fixed floor price, PDC, as Managing General Partner, receives the fixed floor price and pays the market price. If the market price is between the ceiling and floor price, no payments are due either party.  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 revenue and cash flows compared to the level the Partnership might experience if no derivative instruments were in place.

- 4 -

The Partnership participates in all derivative transactions entered into by the Managing General Partner in a given area.  The transactions are on a production month basis.  Therefore, the Partnership may participate in a derivative for a future period before it has production from that area.  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 each of the sponsored drilling partnerships, changed.  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.  This allocation methodology is considered reasonable by management of the Managing General Partner.  The Partnership believes that in this rapidly changing price environment, derivative positions are desirable to obtain more predictable results and to reduce the impact of possible severe price declines during this crucial state of flush production from the Partnership wells.

Drilling and Operating Agreement.  The Partnership has entered into a Drilling and Operating Agreement with PDC.  The Drilling and Operating Agreement provides that the operator conducts and directs drilling operations, including well recompletions, and has full control of all operations on the Partnership's wells.  The operator has no liability to the Partnership for losses sustained or liabilities incurred, except as may result from the operator's negligence or misconduct.  Under the terms of the drilling and operating agreement, PDC may subcontract responsibilities as operator for Partnership wells.  PDC retains responsibility for work performed by subcontractors.

To the extent the Partnership has less than a 100% working interest in a well, the Partnership paid only its proportionate share of total lease, development, and operating costs, and received its proportionate share of production subject only to royalties and overriding royalties. The Partnership is responsible only for its obligations and is liable only for its proportionate working interest share of the costs of developing and operating the wells.

The operator provides all necessary labor, vehicles, supervision, management, accounting, and overhead services for normal production operations, and deducts from Partnership revenues a 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 Drilling and Operating Agreement multiplied by the then current average of the Oil and Gas Extraction Index and the Professional and Technical Services Index, as published by the United States Department of Labor, Bureau of Labor Statistics, provided that the charge may not exceed the rate which would be charged by the comparable operators in the area of operations.  This average is commonly referred to as the Accounting Procedure Wage Index Adjustment which is published annually by the Council of Petroleum Accountants Societies, or COPAS.

The Partnership has the right to take in kind and separately dispose of its share of all oil and natural gas produced from its wells.  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.  If pipelines owned by PDC are used in the delivery of natural gas to market, PDC charges a gathering fee not to exceed that which would be charged by a non-affiliated third party for a similar service.

- 5 -

The Drilling and Operating Agreement continues in force as long as any well or wells produce, or are capable of 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 agreement.

Production Phase of Operations

When Partnership wells are "complete" (i.e., drilled, fractured or stimulated, and all surface production equipment and pipeline facilities necessary to produce the well are installed), production operations commence on each well.  All Partnership wells are complete, and production operations are being conducted with regard to each of the ninety-nine producing wells.

The Partnership sells the produced 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 be dedicated to particular markets at the time the Partnership acquired those leases, or subsequent to, as part of the natural gas marketing arrangements.

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 and natural gas 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.

PDC, on behalf of the Partnership, may enter into fixed price contracts, or utilize derivatives, including collars, swaps or basis swaps, in order to offset some or all of the price variability for particular periods of time, generally for two to three years, but in no cases longer than five years.  The use of derivatives may entail fees, including the time value of money for margin requirements, which are charged to the Partnership.

Seasonal factors, such as effects of weather on prices received and costs incurred, and availability of pipelines may impact the Partnership's results.  In addition, both sales volumes and prices tend to be affected by demand factors with a significant seasonal component.

Revenues, Expenses and Distributions

The Partnership's share of production revenue from a given well is burdened by and/or subject to royalties and overriding royalties, monthly operating charges, taxes and other operating costs.

The above items of expenditure involve amounts payable solely out of and expenses incurred solely by reason of production operations.  Although the Partnership is permitted to borrow funds for its operations, it is PDC's practice to deduct operating expenses from the production revenue for the corresponding period and to defer the collection of operating expenses to future periods when revenues are sufficient to render full payment.

Interests of Parties in Production Revenues

PDC, the Investor Partners, and unaffiliated third parties (including landowners) share revenues from production of natural gas and oil from wells in which the Partnership has an interest.  The following chart illustrates the interest of gross revenues derived from the wells.  For the purpose of this chart, "gross revenue" is defined as the "wellhead gas and oil revenue" paid by the purchasers.  Landowner and other royalties payable to unaffiliated third parties may vary, generally between 12.5% to 25% or more; however, the average of the royalty interests for all prospects or wells of the Partnership may not exceed 25%.

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Illustration of Partnership Revenue Sharing
Entity or Interest Owners	Partnership Interests	Gross Revenue Interests (Partnership Revenues and Third Party Royalties)
		If 12½% Royalty:	If 25% Royalty:
PDC, the Managing General Partner	37%	32.375%	27.75%
Investor Partners	63%	55.125%	47.25%
Landowners and Over-riding Royalty Owners	N/A	12.5%	25.00%
Totals	100%	100.00%	100.00%

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Production, Sales, Prices and Lifting Costs

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 December 31, 2008			Period May 22, 2007 (date of inception) Through December 31, 2007
Production
Oil (Bbls)		234,746			13,241
Natural gas (Mcf)		3,976,180			24,330
Natural gas equivalent (Mcfe)		5,384,656			103,776
Oil and Gas Sales
Oil sales	$	21,503,972		$	1,006,299
Gas sales		22,435,547			153,902
Total oil and gas sales	$	43,939,519		$	1,160,201
Realized Gain (Loss) on Derivatives, net
Oil derivatives - realized loss	$	(924,778	)	$	-
Natural gas derivatives - realized gain		3,090,653			-
Total realized gain on derivatives, net	$	2,165,875		$	-
Average Sales Price
Oil (per Bbl)	$	91.61		$	76.00
Natural gas (per Mcf)		5.64			6.33
Natural gas equivalent (per Mcfe)		8.16			11.18
Average Sales Price (including realized gain (loss) on derivatives)
Oil (per Bbl)	$	87.67		$	76.00
Natural gas (per Mcf)		6.42			6.33
Natural gas equivalent (per Mcfe)		8.56			11.18
Average Production Cost (Lifting Cost) per Mcfe	$	1.36		$	1.17

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 gas equivalents

· MMcf – One million cubic feet

· MMcfe – One million cubic feet of gas equivalents

Production as shown in the table is net and is determined by multiplying the gross production volume of properties in which the Partnership has an interest by the percentage of the leasehold or other property interest the Partnership owns.  A ratio of energy content of natural gas and oil (six Mcf of natural gas equals one barrel of oil) was used to obtain a conversion factor to convert oil production into equivalent Mcf of natural gas.

The Partnership utilizes commodity based derivative instruments to manage a portion of its exposure to price volatility of its natural gas and oil sales.  Production costs represent oil and gas operating expenses which include severance and ad valorem taxes as reflected in the Partnership’s financial statements.  See Item 7, Management’s Discussion and Analysis of Financial Conditions and Results of Operations - Production and Operating Costs.

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Oil and Natural Gas Reserves

All of the Partnership’s natural gas and oil reserves are located in the United States.   Ryder Scott Company, L.P., an independent engineer prepared the reserve reports for 2008 and 2007. The independent engineers' estimates are made using available geological and reservoir data as well as production performance data including data provided by the Managing General Partner.  The estimates are prepared with respect to reserve categorization, using the definitions for proved reserves set forth in Regulation S-X, Rule 4-10(a) and subsequent SEC staff interpretations and guidance.  When preparing the Partnership’s reserve estimates, the independent engineers did not independently verify the accuracy and completeness of information and data furnished by the Partnership with respect to ownership interests, oil and natural 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.

The tables below set forth information as of December 31, 2008, regarding the Partnership’s proved reserves as estimated by Ryder Scott.  Reserves cannot be measured exactly, because reserve estimates involve subjective judgment.  The estimates must be reviewed periodically and adjusted to reflect additional information gained from reservoir performance, 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 the Partnership owns.

	December 31, 2008
	Oil (MBbl)		Gas (MMcf)		Total (MMcfe)
Proved developed		642		29,270		33,122
Proved undeveloped		684		3,501		7,605
Total Proved		1,326		32,771		40,727

	Proved		Proved		Total
	Developed		Undeveloped		Proved
Estimated future net cash flows (in thousands)	$	103,758	$	17,524	$	121,282
Standardized measure (in thousands)		63,337	$	4,452		67,789

Estimated future net cash flow represents the estimated future gross revenue to be generated from the production of proved reserves, net of estimated production costs and future development costs, using prices and costs in effect at December 31, 2008.  The prices used in the Partnership’s reserve reports yield weighted average wellhead prices of $38.12 per barrel of oil and $4.70 per 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’s commodity hedges in place at December 31, 2008.  The amounts shown do not give effect to non-property related expenses, such as direct costs - general and administrative expenses, or to depreciation, depletion and amortization.

The standardized measure of discounted future net cash flows is calculated in accordance with SFAS No. 69, which requires the future cash flows to be discounted.  The discount rate used was 10%.  Additional information on this measure is presented in Supplemental Oil and Gas Information - Unaudited, Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Oil and Gas Reserves, included in this report.

Insurance

PDC, in its capacity as operator, carries well pollution, public liability and worker’s compensation insurance for its own benefit as well as the benefit of the Partnership, but that insurance may not be sufficient to cover all liabilities.  Each unit held by the general partners, excluding the Managing General Partner, represents an open-ended security for unforeseen events such as blowouts, lost circulation, and stuck drill pipe, which may result in unanticipated additional liability materially in excess of the per unit subscription amount.

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PDC has obtained various insurance policies, as described below, and intends to 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 limits and types of insurance from time to time as deemed appropriate under the circumstances, which may vary materially.  PDC is the beneficiary under each policy and pays the premiums for each policy, except with respect to the insurance coverage referred to in items 2 and 5 below in which case the Managing General Partner and the Partnership are co-insured and co-beneficiaries.  Additionally, PDC as operator of the Partnership's wells requires all of PDC's subcontractors to carry liability insurance coverage with respect to their activities.  In the event of a loss, the insurance policies of the particular subcontractor at risk would be drawn upon before the insurance of the Managing General Partner or that of the Partnership.  PDC has obtained and expects to maintain the following insurance.

1. Worker's compensation insurance in full compliance with the laws for the states in which the operator has employees;

2. Operator's bodily injury liability and property damage liability insurance, each with a limit of $1 million;

3. Employer's liability insurance with a limit of not less than $1 million;

4. Automobile public liability insurance with a limit of not less than $1 million per occurrence, covering all automobile equipment; and

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. 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 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 has caused significant variations in the prices of these products over recent years.

FERC Order 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 capacity release transactions.

FERC Order No. 637 also enacted other regulatory policies that increase the flexibility of interstate natural gas transportation, maximize shippers' supply alternatives, and encourage domestic gas production in order to meet projected increases in gas demand.  These increases in demand come from a number of sources, including as boiler fuel to meet increased electric power generation needs and as an industrial fuel that is environmentally preferable to alternatives such as nuclear power and coal.  This trend has been evident over the past year, particularly in the western U.S., where natural gas is the preferred fuel for environmental reasons, and electric power demand has directly affected demand for natural gas.

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The combined impact of FERC Order No. 636 and No. 637 has been to increase the competition among natural gas suppliers from different regions.

In 1995, the North American Free Trade Agreement, or NAFTA, eliminated trade and investment barriers in the United States, Canada, and Mexico, increasing foreign competition for gas production.  Legislation that Congress may consider with respect to oil and natural gas may increase or decrease the demand for the Partnership's production in the future, depending on whether the legislation is directed toward decreasing demand or increasing supply.

Members of the Organization of Petroleum Exporting Countries, or OPEC, establish prices and production quotas for petroleum products from time to time, with the intent of reducing the current global oversupply and maintaining or increasing price levels.  PDC 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.

Various parts of the fields in which the Partnership’s wells are located are crossed by pipelines belonging to Colorado Interstate Gas, Encana, DCP Midstream LP (“DCP”, formerly Duke Energy), Williams Production, RMT (“Williams”) and others.  These companies have all traditionally purchased substantial portions of their supply from Colorado producers.  Transportation on these systems requires that delivered natural gas meet quality standards and that a tariff be paid for quantities transported.

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 Colorado Interstate Gas, Williams or other pipelines.  As a result of FERC regulations that require interstate gas pipelines to separate their merchant activities from their transportation activities and require them to release available capacity on both a short and a long-term basis, local distribution companies must take an increasingly active role in acquiring their own natural gas supplies.  Consequently, pipelines and local distribution companies 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 added to competition in the natural gas marketplace.

Natural Gas and Oil Pricing

PDC sells 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 primarily 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 is subject to changes in market prices on a national level, as well as changes in the market 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 Partnership crude oil from Partnership wells to Teppco Crude Oil, LP (“Teppco”).  Generally, 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. Additionally, the cost of trucking or transporting the oil to market affects the price the Partnership ultimately receives for the oil.

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Governmental Regulation

While the prices of oil and natural gas are set by the market, other aspects of the Partnership's business and the oil and natural gas industry in general are heavily regulated.  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.  PDC management, as Managing General Partner, believes that the Partnership is in compliance with such statutes, rules, regulations and governmental orders, although there can be no assurance that this is or will remain the case.  The following summary discussion of the regulation of the United States oil and natural gas industry is not intended to constitute a complete discussion of the various statutes, rules, regulations and environmental orders to which the Partnership's operations may be subject.

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 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.

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.

Proposed Regulation

Various 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 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.

Operating Hazards

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

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Any significant problems related to Partnership wells could adversely affect our ability to conduct operations. In accordance with customary industry practice, the Partnership maintains insurance against some, but not all, potential risks; however, there can be no assurance that such insurance will be adequate to cover any losses or exposure for liability. The occurrence of a significant event not fully insured against could materially adversely affect 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 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.

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, that 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 0001407805.  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.  In particular, consider the risks related to (1) 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 and (2) the effect of constraints on the availability of credit for financing well recompletion activities.  Also consider the interplay between these two risks: the decline in oil and gas prices can lead to a reduction in the Managing General Partner’s credit line borrowing base, which it may utilize on behalf of the Partnership or other partnerships for which PDC serves as Managing General Partner, to fund Partnership well recompletion activities.  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, further eroding the Managing General Partner’s borrowing base, by its share of such oil and natural gas reserve reductions, thus increasing the likelihood for borrowing cost increases or loss of borrowing fund availability, for Partnership activities.  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 to 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 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 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 mid-2008 levels.  The 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.  Furthermore, as a result of these disruptions in the financial markets, it is possible that in future years the Partnership would not be able to borrow sufficient funds to recomplete most 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.  Any of the above factors could adversely affect the Partnership’s operating results. For more information regarding the Wattenberg Field recompletion plan, see Item 1 Business, Plan of Operation.

Risks Pertaining to Natural Gas and Oil Investments

The oil and natural gas business is speculative and may be unprofitable and result in the total loss of investment.  The 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, 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 of the prior Partnerships sponsored by PDC have, to date, generated cash distributions in excess of investor subscriptions without giving effect to tax savings.

The Partnership may retain Partnership revenues or borrow funds 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 either retain Partnership revenues or borrow the funds from the Managing General Partner or other third parties if borrowed funding is available, that is necessary for these purposes.  Retaining Partnership revenues and/or the repayment of borrowed funds 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 held 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 or to repay financial obligations of the Partnership for borrowed funds plus interest.  If future development of the Partnership's wells is not commercially successful, whether using funds retained from production revenues or borrowed funding if available, these operations could result in a reduction of cash distributions to the Investor Partners of the Partnership.

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 affect the performance and profitability of the Partnership in both the short and long term.  In the current high price environment, most oil and natural gas companies have 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 completions, and it is uncertain low 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 October 21, 2008.  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 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.

· 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.

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· 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 service, 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 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.

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.

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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 plans to recomplete various of its Wattenberg Wells in approximately five years, 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.

A significant variance from the Partnership’s estimated reserves and future net revenues could adversely affect the Partnership’s cash flows, results of operations, and the availability of capital resources.  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, results of operations and the availability of capital resources. 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 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 August 2007.  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.

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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.

Two Colorado lawsuits 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, a complaint was filed against PDC in Weld County, Colorado.  The complaint represented a class action against PDC seeking compensation for alleged underpayment of royalties on leases in Colorado, resulting from the alleged miscalculation of costs to produce marketable gas.  The case was moved to Federal Court in June 2007.  A second similar Colorado class action suit was filed against PDC on December 3, 2007.  On January 28, 2008, the Court granted a motion to consolidate the two cases, and on February 29, 2008, the Court approved a 90 day stay in the proceedings while the parties pursued mediation of the matter.

The court approved a stay in proceedings until September 22, 2008 while the parties pursued mediation of the matter.  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 75 wells in the Wattenberg field subject to the settlement.  On October 10, 2008, the court issued preliminary approval of the settlement agreement. The portion of the proposed settlement related to the Partnership’s wells for all periods through December 31, 2008 is $78,105.  This amount, plus legal costs of $7,863, were recorded to fully accrue for the settlement through December 31, 2008.  In November 2008, the Managing General Partner paid into an escrow account, on behalf of the Partnership, amounts due under the settlement.  These amounts will be deducted from future Partnership distributions.  Notice of the settlement was mailed to members of the class action suit in fourth quarter 2008 and the final settlement approval hearing is expected on April 7, 2009.

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Special Risks of an Investment in the Partnership

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.  The offer and sale of units have not been, and will not in the future be, registered under the Securities Act or under any state securities laws.  Each purchaser of units has been required to represent that such investor has purchased the units for his or her own account for investment purposes and not with a view to resale or distribution.  No transfer of a unit may be made unless the transferee is an "accredited investor" and such transfer is registered under the Securities Act and applicable state securities laws, or an exemption there from is available.  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.

Dry hole or non-commercially viable drilling prospect costs associated with the Partnership's drilling have resulted in reduced distributions to the Investor Partners.  To date, the Partnership has drilled a total of 100 developmental wells.  Of these wells, one has been evaluated and declared to be a developmental dry hole.  As dry holes result in no production of oil and natural gas, the occurrence of dry holes causes the revenues and distributions to be less than if the wells drilled had been commercially productive.  From inception through December 31, 2008, the Partnership has recorded no exploratory dry hole costs.

The Partnership assesses impairment of capitalized costs of proved oil and natural gas properties by comparing net capitalized costs to estimated undiscounted future net cash flows on a field-by-field basis using estimated production based upon prices at which management reasonably estimates such production to be sold.  From inception through December 31, 2008, the Partnership's has recorded no impairment costs.  Unlike dry holes, impaired properties may still produce oil and natural gas which can be sold, however, the impaired properties may not generate enough production for the Partnership to recoup the amounts invested in the properties.

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 October 21, 2008.  Upon completion of the drilling phase of the Partnership's wells, all additional general partners units were converted into units of limited partner interests and thereafter became limited partners of the Partnership. 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.

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.

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A substantial part of our 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 and cash flow.

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 October 2005, PDC has become compliant with its corporate Exchange Act filing and reporting obligations. Additionally, Rockies Region 2007 Limited Partnership and Rockies Region 2006 Limited Partnership have completed all required SEC filings through September 30, 2008; PDC 2005-A Limited Partnership and PDC 2005-B Limited Partnership have filed financial statements through December 31, 2007, however, these latter two partnerships are still delinquent with respect to their 2008 quarterly filing requirements. These two partnerships are currently in the process of preparing their 2008 10-K filings which will include unaudited quarterly condensed financial statements for 2008. On March 31, 2009, these two partnerships will become delinquent with respect to their 2008 10-K filings if not filed before such date. PDC 2004-A Limited Partnership has filed financial statements through December 31, 2005 but is delinquent on all quarterly and annual filing requirements from March 31, 2006 through September 30, 2008. Rockies Region Private Limited Partnership has filed financial statements through March 31, 2006, but is delinquent on all quarterly and annual filing requirements from June 30, 2006 through September 30, 2008. On March 31, 2009, these two partnerships will become delinquent with respect to their 2008 10-K filings. 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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"A material weaknesses" 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.

Item 1B. Unresolved Staff Comments

None

Item 2. Properties

The Partnership’s properties (the “Properties”) consist of working interests in gas wells and the ownership in leasehold acreage in the spacing units for the 100 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 - Drilling Activities - Plan of Operations for additional information on the Partnership’s properties.

The Partnership commenced drilling activities immediately following funding August 31, 2007.  The number of wells owned by the Partnership at December 31, for each of the periods described, is presented in the following table.

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	December 31, 2008				December 31, 2007
	Gross		Net		Gross		Net
Development wells:
Drilled, fractured and producing		99.0		97.9		13.0		13.0
Drilled and not completed						40.0		39.7
Dry hole		1.0		1.0		1.0		1.0
Total		100.0		98.9		54.0		53.7

The 100 wells at December 31, 2008, in the table above are the only wells to be drilled by the Partnership since all of the funds raised in the Partnership offering have been utilized.  Productive wells consist of producing wells and wells capable of producing oil and natural gas in commercial quantities.  Gross wells refer to the number of wells in which the Partnership has an interest.  Net wells refer to gross wells multiplied by the percentage working interest owned by the Partnership.

The Partnership drilled all 100 developmental wells in Colorado and 99 were development wells which are currently producing while one was evaluated to be a developmental dry hole.  The details of these prospect areas are further outlined below.

Colorado.  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 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 and water.  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.

Production

Production commenced during the fourth quarter of 2007, peaked during the quarter ended September 30, 2008 and is expected to continue to decrease consistent with the standard natural gas reserve production decline curve.

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 report.  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.

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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 is conducted at the time the undeveloped properties are acquired.  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 any of these burdens 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 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 February 28, 2009, the Partnership had 1,782 Investor Partners holding 4,470 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 Managing General Partner.  As of February 28, 2009, the Managing General Partner has repurchased no 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.  The offer and sale of the Investor Partners' interests ("units") have not been registered under the Securities Act or under any state securities laws.  Each purchaser of units was required to represent that such individual investor partner was purchasing the units for his or her own account for investment and not with a view to distribution.  No transfer of a unit may be made unless the transferee is an "accredited investor" and such transfer is registered under the Securities Act and applicable state securities laws, or an exemption therefrom is available.  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.

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Cash Distribution Policy.  PDC plans to make distributions of Partnership cash on a monthly basis, but no less often than quarterly, if funds are available for distribution.  PDC will make cash distributions of 63% to the Investor Partners, adjusted for any units purchased by the Managing General Partner, and 37% to the Managing General Partner throughout the term of the Partnership.

PDC cannot presently predict amounts of cash distributions, if any, from the Partnership.  However, PDC expressly conditions any distribution upon its 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 debt instruments or 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 began distributions in May 2008 and made cash distributions of $28,346,463 for the year ended December 31, 2008.

In general, the volume of production from producing properties declines with the passage of time.  The cash flow generated by the Partnership's activities and the amounts available for distribution to the Partnership's Investor Partners will, therefore, decline in the absence of significant increases in the prices that the Partnership receives for its oil and natural gas production, or significant increases in the production of oil and natural gas from the successful additional development of these prospects.  If the Partnership decides to develop its wells further, the funds necessary for that development would come from the Partnership's revenues and/or from borrowed funds.  As a result, there may be a decrease in the funds available for distribution, and the distributions to the Investor Partners may decrease.

In general, PDC divides cash distributions 63% to the Investor Partners and 37% to PDC throughout the term of the Partnership.  Cash is distributed to the Investor Partners and PDC as a return on capital, in the same proportion as their interest in the net income of the Partnership.  However, no individual investor partner will receive distributions to the extent the distributions would create or increase a deficit in that investor partner's capital account.

PDC, as Managing General Partner, intends to develop the Partnership's interests in its properties only with the proceeds of subscriptions and PDC's capital contributions.  However, these funds may not be sufficient to fund all future well costs, and it may be necessary for the Partnership to retain Partnership revenues for the payment of these costs, or for PDC to advance the necessary funds to the Partnership or for the Partnership to borrow necessary funds.  It is likely that the Partnership's Wattenberg Field, Colorado wells will benefit from recompletion services, generally in five years or longer following initial drilling of those wells.  Recompletion is the process of going into an existing zone which is already producing for a “refrac,” or refracture operation to go into a new zone at a different depth, all with the objective of increasing the production of oil or natural gas.  If PDC retains Partnership revenues for the payment of these recompletion or “refrac” costs, the amount of Partnership funds available for distribution to the Investor Partners of the Partnership will decrease correspondingly.  Development work will not include the drilling of any new wells beyond the initial wells that have been drilled.  PDC may retain payment for the recompletion or “refrac” work from Partnership proceeds, by preparing an Authority for Expenditure, or AFE, estimate for the Partnership in either of the two methods:

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· PDC will complete the development work and will bill the Partnership for the work performed and will be reimbursed from future production; or

· The Partnership will retain revenues from operations until it has accumulated or borrowed sufficient funds to pay for the development work, at which time PDC will commence the work, and PDC will be reimbursed as the work progresses from retained revenues.

Should the Partnership’s revenues be retained for the payment of recompletion or “refrac” costs, the determination of which option to use will be at PDC's discretion, based on the amount of the anticipated expenditure and the urgency of the necessary work.

The Agreement also permits the Partnership to borrow funds on behalf of the Partnership for Partnership activities. The Partnership may borrow needed funds, or receive advances, from the Managing General Partner or affiliates of the Managing General Partner or from unaffiliated persons.  On loans or advances made available to the Partnership by the Managing General Partner or affiliates of the Managing General Partner, the Managing General Partner or affiliate may not receive interest in excess of its interest costs, nor may the Managing General Partner or affiliate receive interest in excess of the amounts which would be charged the Partnership (without reference to the Managing General Partner's financial abilities or guarantees) by unrelated banks on comparable loans for the same purpose.  The Managing General Partner anticipates that borrowed funds will be utilized to finance Codell recompletion activities (see Item 1, Business).  As the Partnership will have to pay interest on borrowed funds, the amount of Partnership funds available for distribution to the partners of the Partnership will be reduced accordingly.

Individual investor partners who are independent producers are entitled to claim a percentage depletion deduction against their oil and natural gas income.  The percentage depletion rate for oil and gas properties is generally 15% of the gross income generated by the property.

Unit Repurchase Program.  Beginning with the third anniversary of the date of the first cash distribution of the Partnership, Investor Partners of the Partnership may request the Managing General Partner to repurchase their units. The Partnership initiated monthly cash distributions to Investor Partners in May 2008. If requested by individual investor partners, the Managing General Partner is obligated to purchase in any calendar year units which aggregate up to 10% of the initial subscriptions. Repurchase of units is subject to PDC’s financial ability to purchase the units. The purchase price will not be less than four times the most recent twelve months’ cash distributions from production of the Partnership.

In addition to the above repurchase program, individual investor partners periodically offer and PDC repurchases, units on a negotiated basis before the third anniversary of the date of the first cash distribution.  As of December 31, 2008, the Managing General Partner has not made any negotiated-basis unit repurchases.

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 financial statements included in this report.  Further, the Partnership encourages you to revisit Special Note Regarding Forward-Looking Statements on page 1 of this report.

Overview

The Partnership was funded on August 31, 2007 with initial contributions of $89,402,885 from the Investor Partners and a cash contribution of $38,659,808 from the Managing General Partner.  After payment of syndication costs of $9,070,450 and a one-time management fee to PDC of $1,341,043, the Partnership had available cash of $117,651,200 to commence Partnership oil and natural gas well drilling activities.

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The Partnership began exploration and development activities immediately after funding.  The full amount of the funding was paid to PDC to begin the drilling of oil and natural gas wells, on behalf of the Partnership under the Drilling and Operating Agreement.  The payment to PDC was made as an advance of exploration and development costs for oil and natural gas properties.  In August 2007, PDC commenced drilling on behalf of the Partnership.  As of December 31, 2008, a total of 100 developmental wells have been drilled, all in the Rocky Mountain Region in the state of Colorado.  Of the 100 wells drilled, 99 are producing and one was determined to be a dry hole.  These 100 wells are the only wells the Partnership will drill because the majority of the capital contributions have been utilized.  The remaining $719,724 of drilling advances to the Managing General Partner will be used for future capitalized costs.  The completed wells produce primarily natural gas, with some associated crude oil.  Sales of produced natural gas and oil commenced during the fourth quarter of 2007 as wells were connected to pipelines.  The Partnership’s wells will produce until they are depleted or until they are uneconomical to produce; however, it is the plan of the Partnership and the Managing General Partner to recomplete the Codell formation in certain wells in the Wattenberg Field after five or more years of production because these wells will have experienced a significant decline in production in that time period.  However, the exact timing of recompletion may be delayed or accelerated due to changing commodity prices.  Codell recompletions typically increase production rates and recoverable reserves.  Although PDC has experienced significant production increases following prior Codell recompletions, not all such recompletions have been successful.

2008 Overview

The year 2008 was a year of significant events: oil and natural gas prices reached record and near record highs, respectively, through July; then, in the midst of U.S. credit turmoil and a worldwide economic slump, in December, oil prices fell to their lowest in four years and natural gas prices dropped almost by half.  The Managing General Partner’s reaction to these events is one of caution.  While the Partnership certainly felt the impact of these events, the Managing General Partner believes the Partnership was successful in managing its operations in such a manner that the Partnership was able to minimize the negative impacts while capitalizing on the positive impacts.  The Partnership’s derivative position eased the impact of the fall in oil and natural gas prices.  The Partnership exited 2008 with $2.2 million in net realized derivative gains, $5.0 million in the fourth quarter alone.  Further, the Partnership estimates the net fair value of its derivative positions as of December 31, 2008, to be $15.6 million.

The decline in prices during the fourth quarter of 2008 has resulted in $15.9 million in unrealized gains on derivatives for the year ended December 31, 2008.  The $15.9 million in unrealized gains for the year is the fair value of he derivative positions as of December 31, 2008, less the related unrealized amounts recorded in prior periods.  An unrealized gain is a non-cash item and there will be further gains or losses as prices decrease or increase until the positions mature or are closed.  While 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 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,		March 31,
Commodity	Index	2007		2008		2008		2009
Natural gas:
	NYMEX	$	8.12	$	12.52	$	6.62	$	5.87
	CIG		6.78		8.86		4.49		4.13
Oil:	NYMEX		90.79		140.15		57.49		53.07

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 are expected to continue.

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Results of Operations

The following table 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, average lifting cost, other operating income and expenses for the year ended December 31, 2008 and period May 22, 2007 (date of inception) to December 31, 2007.

	Year Ended December 31, 2008			Period May 22, 2007 (date of inception) Through December 31, 2007			Percent Change 2008 to 2007
Number of producing wells (end of period)		99			13
Production:  (1)
Oil (Bbl)		234,746			13,241			*
Natural gas (Mcf)		3,976,180			24,330			*
Natural gas equivalents (Mcfe)  (2)		5,384,656			103,776			*
Average Selling Price
Oil (per Bbl)  (3)	$	91.61		$	76.00			21	%
Natural gas (per Mcf)  (3)		5.64			6.33			-11	%
Natural gas equivalents (per Mcfe)  (3)		8.16			11.18			-27	%
Average Sales Price (including realized gain (loss), net on derivatives)
Oil (per Bbl)	$	87.67		$	76.00			15	%
Natural gas (per Mcf)		6.42			6.33			1	%
Natural gas equivalent (per Mcfe)		8.56			11.18			-23	%
Average cost per Mcfe
Production and operating costs  (4)	$	1.36		$	1.17			16	%
Depreciation, depletion and amortization		2.89			4.47			-35	%
Revenues:
Oil and gas sales	$	43,939,519		$	1,160,201			*
Oil and gas price risk management, gain (loss), net		18,117,972			(319,365	)		*
Total revenues	$	62,057,491		$	840,836			*
Realized Gain (Loss) on Derivatives, net
Oil derivatives - realized loss	$	(924,778	)	$	-			*
Natural gas derivatives - realized gain		3,090,653			-			*
Total realized gain on derivatives, net	$	2,165,875		$	-			*
Operating costs and expenses:
Production and operating costs	$	7,316,813		$	121,897			*
Management fee		-			1,341,043			*
Direct costs		607,289			-			*
Depreciation, depletion and amortization		15,564,254			464,341			*
Accretion of asset retirement obligations		21,523			927			*
Total operating costs and expenses	$	23,509,879		$	1,928,208			*
Income (loss) from operations	$	38,547,612		$	(1,087,372	)		*
Interest income	$	104,001		$	1,320,134			-92	%
Net income	$	38,651,613		$	232,762			*
Cash distributions	$	28,346,463		$	-			*

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

Amounts may not calculate due to rounding

_______________

1. Production is net and determined by multiplying the gross production volume of properties in which we have an interest by the percentage of the leasehold or other property interest we own.

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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. The Partnership utilizes commodity based derivative instruments to manage a portion of our exposure to price volatility of our natural gas and oil sales.  This amount excludes realized and unrealized gains and losses on commodity based derivative instruments.

4. 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 gas equivalents

Oil and Natural Gas Sales Activity

The $42.8 million increase in total sales in 2008 as compared to the period May 22, 2007 (date of inception) through December 31, 2007 was due primarily to increased total production volumes as the Partnership completed drilling activities.  Additionally, the increase in average oil prices in 2008 resulted in an increase in sales of $3.5 million which was partially offset by decreased sales of $2.7 million due to a decrease in average gas prices.  Production commenced during the fourth quarter of 2007 when 13 of the initial Partnership wells drilled were completed and connected to pipelines and peaked during the quarter ended September 30, 2008 with the tie-in of the Partnership’s remaining 86 producing developmental wells. Production is expected to continue to decrease consistent with the standard natural gas reserve production decline curve.

Oil and Natural Gas Pricing

Financial results depend upon many factors, particularly the price of oil and natural gas and our ability to market our production effectively.  Oil and natural gas prices have been among the most volatile of all commodity prices.  These price variations have a material impact on our financial results.  Oil and natural gas prices also vary by region and locality, depending upon the distance to markets, and the supply and demand relationships in that region or locality.  This can be especially true in the Rocky Mountain Region in which all of the partnership wells are located.  The combination of increased drilling activity and the lack of local markets have resulted in a local market oversupply situation from time to time.  Such a situation existed in the Rocky Mountain Region during 2007, with production exceeding the local market demand and pipeline capacity to non-local markets.  The result, beginning in the second quarter of 2007 and continuing through and 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 compared to the New York Mercantile Exchange, or NYMEX, price.

The expansion in January 2008 of the Rockies Express pipeline (“REX”), a major interstate pipeline constructed and operated by a non-affiliated entity, resulted in a narrowing of the NYMEX and CIG price differential to under a $1.00 between the indices’ average prices in January and February 2008.  However, a substantial portion of the new capacity created by the REX Pipeline is now under contract resulting in a resumption of regional transportation capacity restraints and a widening of the NYMEX-CIG differential that peaked in June and September at average index price differentials of $4.58 and $4.00, respectively.  Index differentials closed 2008 having again narrowed to $1.30, and are expected to average $1.74 for the next 24 months (forward curve) based on index futures.  Like most producers in the region, the Partnership relies on major interstate pipeline companies to construct these facilities to increase pipeline capacity, rendering the timing and availability of these facilities beyond our control.  In view of the regional 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.  To that end, the Partnership has been able to sell all of its production to date, has not had to curtail its production 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.

Oil pricing is also driven strongly by supply and demand relationships.  In the Rocky Mountain Region for 2008, Partnership oil sales averaged $91.61 per barrel which is below the NYMEX oil market 12-month average monthly closing prices for 2008 of $104.42, due to supply competition from Rocky Mountain and Canadian oil that has driven down market prices.

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The price the Partnership receives for a large portion of the natural gas produced in the Rocky Mountain Region is based on a market basket of prices, which may include some natural gas sold at the CIG prices and some sold at mid-continent 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.

During 2009, oil and natural gas prices have continued to fluctuate, with oil prices on NYMEX as high as $53.80 on March 23, 2009 and as low as $33.98 on February 12, 2009 and natural gas prices on CIG as high as $4.585 on January 7, 2009 and as low as $2.255 on March 1, 2009.

Oil and Gas Price Risk Management Gain (Loss), Net

The Managing General Partner uses oil and natural gas commodity derivative instruments to jointly manage price risk for its corporate interests as well as sponsored drilling partnerships, including the Partnership, by area of operation.  Prior to September 30, 2008, as production volumes changed, the allocation of derivative positions between PDC’s corporate interests and each of the sponsored drilling partnerships, changed.  As of September 30, 2008, the allocation of derivative positions was fixed, based on the current estimated future production, between the Managing General Partners’ 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 Partners’ corporate interests and each sponsored drilling partnership, including the Partnership, are allocated and fixed at the time the positions are entered into based on estimated future production.  Realized and unrealized gains and losses resulting from derivative positions are reported on the statement of operations as “Oil and gas price risk management gain (loss), net.”  The net gains/losses are comprised of the change in fair value of derivative positions related to the Partnership’s production and underlying derivative contracts entered into by the Managing General Partner on behalf of the Partnership.

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.  Since December 31, 2008, through the filing of this report, the Partnership continues to experience extreme volatility in oil and gas prices resulting in extreme fluctuation in realized and unrealized derivative positions.  The following table presents the realized and unrealized gains and losses recorded for the annual periods identified:

	Year Ended December 31, 2008			Period May 22, 2007 (date of inception) Through December 31, 2007
Realized gains (losses)
Oil	$	(924,778	)	$	-
Gas		3,090,653			-
Total realized gain, net		2,165,875			-
Unrealized gain (loss), net		15,952,097			(319,365	)
Oil and gas price risk management gain (loss), net	$	18,117,972		$	(319,365	)

“Oil and gas price risk management gain (loss), 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 Note 4, Derivative Financial Instruments and Note 5, Fair Value of Financial Instruments, to the accompanying financial statements for additional details of the Partnership’s derivative financial instruments.

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During 2008, the Partnership recorded realized gains of $2.2 million and unrealized gains of $15.9 million, resulting in a net $18.1 million gain for the year.  Although oil and natural gas prices increased during the first six months of 2008, the Partnership experienced dramatic commodity price declines during the last six months of 2008, relative to the Partnership’s current derivative positions, which resulted in significant unrealized derivative gains in 2008.  For the period May 22, 2007 (date of inception) to December 31, 2007, the Partnership incurred an unrealized loss of $0.3 million.  The majority of the unrealized loss recognized for the 2007 period was due to increasing natural gas prices.  When forward prices for oil and natural gas decrease as they did throughout the second half of 2008, the Partnership’s derivative positions, which include floors, ceilings and swaps, tend to increase in value, resulting in unrealized gain positions.  Likewise, 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 gain (loss), net,” occur.

Oil and Gas Derivative Activities.  The Managing General Partner uses various derivative instruments to manage fluctuations in oil and natural gas prices.  The Managing General Partner has in place a series of collars, fixed price swaps and basis swaps on a portion of the Partnership’s oil and natural gas production.  Under the collar arrangements, if the applicable index rises above the ceiling price or swap, the Managing General Partner pays the counterparty; however, if the index drops below the floor or swap, the counterparty pays the Managing General Partner.

The following table identifies the Partnership’s derivative positions related to oil and gas sales activities in effect as of December 31, 2008, on Partnership production by area.

	Collars
	Floors				Celings				Swaps				Basis Swaps
Commodity Index/Area	Quantity (Gas-Mmbtu Oil-Bbls)		Weighted Average Contract Price		Quantity (Gas-Mmbtu Oil-Bbls)		Weighted Average Contract Price		Quantity (Gas-Mmbtu Oil-Bbls)		Weighted Average Contract Price		Quantity (Gas-Mmbtu Oil-Bbls)		Weighted Average Contract Price		Fair Value at December 31, 2008
CIG
Piceance
1Q 2009		-	$	-		-	$	-		624,611	$	8.08		-	$	-	$	2,442,841
2Q 2009		503,235		5.75		503,235		8.90		-		-		-		-		1,036,279
3Q 2009		503,235		5.75		503,235		8.90		-		-		-		-		837,651
4Q 2009		330,286		6.61		330,286		10.13		114,287		9.20						1,332,713
2010		350,180		6.66		350,180		10.81		171,430		9.20		1,079,839		1.88		1,674,226
2011		159,554		4.75		159,554		9.45		-		-		1,152,206		1.88		171,539
2012		-		-		-		-		-		-		1,134,220		1.88		(456,353	)
2013		-		-		-		-		-		-		1,003,568		1.88		(671,791	)
																	$	6,367,105
Wattenberg Field
1Q 2009		-	$	-		-	$	-		167,339	$	8.07		-	$	-	$	653,021
2Q 2009		134,463		5.75		134,463		8.89		-		-		-		-		276,888
3Q 2009		134,463		5.75		134,463		8.89		-		-		-		-		223,802
4Q 2009		89,097		6.62		89,097		10.14		30,747		9.20		-		-		359,467
2010		98,335		6.61		98,335		10.77		46,121		9.20		252,236		1.88		435,118
2011		47,882		4.75		47,882		9.45		-				268,790		1.88		43,138
2012		-		-		-		-		-		-		268,060		1.88		(107,847	)
2013		-		-		-		-		-		-		235,010		1.88		(157,310	)
																	$	1,726,277
NYMEX
Oil
1Q 2009		-	$	-		-	$	-		34,107	$	90.52		-	$	-	$	1,422,013
2Q 2009		-				-		-		34,486		90.52		-		-		1,267,206
3Q 2009		-		-		-		-		34,865		90.52		-		-		1,170,374
4Q 2009		-		-		-		-		34,865		90.52		-		-		1,074,137
2010		-		-		-		-		93,871		92.96		-		-		2,605,620
																	$	7,539,350
TOTAL																	$	15,632,732

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Production and Operating Costs

The $7.2 million increase in production and operating costs during 2008 compared to the period May 22, 2007 (date of inception) to December 31, 2007 is due to the phased-in completion of the remaining 86 Partnership developmental wells during the first half of 2008, with substantially all Partnership wells available for operation during the second half of 2008.  The Partnership experienced an approximate 10% to 15% curtailment of production in the Piceance Basin where the Partnership operates 24 wells, due to limited compression and pipeline capacity throughout most of fourth quarter 2008.  This interruption, due to third party infrastructure, was corrected in early 2009.

Production and operating costs include production taxes and transportation costs which generally vary with sales and production, well operating costs charged on a per well basis and other direct costs incurred in the production process.  As production declines as per the historical decline curve, fixed costs increase as a percentage of total costs.  This results in production costs per unit to rise.  As production continues 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.  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.

Direct Costs – General and Administrative

Direct costs – general and administrative consist primarily of professional fees for financial statement audits, income tax return preparation and legal matters.  The Partnership incurred no direct costs during the period May 22, 2007 (date of inception) to December 31, 2007 in which Partnership operations commenced. Audit and legal fees were minimal until second quarter 2008, when work began on the initial and subsequent filing of the Partnership’s Registration Statements on Form 10 and Form 10/A as well as filing of the Partnership’s Quarterly Reports on Form 10-Q and 10-Q/A for the quarters ended June 30 and September 30, 2008.  Additional direct costs in the amount of $85,968 were recorded in 2008 due to the royalty litigation settlement.  For additional information regarding the settlement, see Note 9, Commitments and Contingencies to the accompanying financial statement included in this report.

Depreciation, Depletion and Amortization

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.

The $15.1 million increase in DD&A for 2008 compared to the period May 22, 2007 (date of inception) to December 31, 2007 is the result of the production level increase of 5,281 MMcfe as the Partnership completed drilling activities and substantially all of the Partnership wells were available for operations during the second half of 2008.

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Interest Income

Interest income decreased in 2008 compared to the period May 22, 2007 (date of inception) through December 31, 2007, due to the utilization in 2008 of funds available for drilling activities that had been previously held in escrow during the Partnership’s previous year’s early drilling period.  Additionally, since the Partnership initiated cash distributions in May 2008, the Partnership had lower cash balances earning interest during the remainder of 2008.

Liquidity and Capital Resources

As the Partnership has completed its drilling activities as of December 31, 2008, the Partnership’s operations are expected to be conducted with available funds and revenues generated from oil and natural gas production activities, with the possible exception of recompletions and “refracs.”  It may be necessary for the Partnership to retain Partnership revenues for the payment of these costs, or for PDC to advance the necessary funds to the Partnership or for the Partnership to borrow necessary funds.  The Managing General Partner anticipates that borrowed funds will be utilized to finance Codell recompletion activities (see Item 1, Business).  As the Partnership will have to pay interest on borrowed funds, the amount of Partnership funds available for distribution to the partners of the Partnership will be reduced accordingly.

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 December 31, 2008, covering substantially all of the Partnership’s expected oil production and 68% of its expected natural gas production for 2009.  These contracts reduce the impact of price changes for a substantial portion of the Partnership’s 2009 cash from operations.  Additional derivative positions were entered into during 2008 for natural gas production through March 2011 and oil production through December 2010 while natural gas price basis swaps cover production through December 2013.  The current derivatives positions will change based on changes in oil and natural gas futures markets, the view of underlying oil and natural gas supply and demand trends and changes in volumes produced.  Oil and natural gas derivatives as of December 31, 2008, are detailed in Note 4, Derivative Financial Instruments to the accompanying financial statements.

Working Capital

The following table sets forth the working capital position of the Partnership, excluding the unrealized losses on derivatives contracts expiring in less than 12 months from the end of each respective period.  The Partnership believes this non-GAAP measure better reflects the Partnership’s actual working capital.  This adjusted amount generally represents the receivables from oil and natural gas sales for the preceding three months, offset by corresponding production taxes payable and accrued expenses for the same period.

	Period Ended December 31,
	2008			2007
Working capital per financial statements	$	24,393,663		$	2,039,074
Due (from) to Managing General Partner - derivatives		(12,096,394	)		319,365
Working capital excluding derivatives	$	12,297,269		$	2,358,439

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Financing and Investing Cash Flows

The Partnership initiated monthly cash distributions to investors in May 2008 and has distributed $28.3 million of its operating cash flows through December 31, 2008.  The following table sets forth the annual cash distributions to the Managing General Partner and Investor Partners for the year ended December 31, 2008.

Year Ended	Managing General Partner Distributions		Investor Partners Distributions		Total Distributions
2008	$	10,581,194	$	17,765,269	$	28,346,463

Operating Cash Flows

Net cash provided by operating activities was $28.9 million in 2008 compared to cash used by operations of $0.6 million for the period May 22, 2007 (date of inception) to December 31, 2007, an increase of $29.5 million.  The increase in cash provided by operating activities was due primarily to the following:

· Increase in oil and gas sales revenues of a $42.8 million and a $2.1 million increase in realized oil and gas price risk management gain (loss), net partially offset  by an increase in production and operating costs of $7.2 million in addition to an increase in direct costs – general and administrative expenditures of $0.6 million.

· Due from (to) Managing General Partner decreased due to the Partnership’s share of reimbursement cost paid by the Managing General Partner.

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.

No bank borrowings are anticipated until such time as recompletions of the Codell formation in the Wattenberg Field wells are undertaken by the Partnership, which is expected to occur in 2011 or later.

Critical Accounting Policies and Estimates

The Managing General Partner has identified the following accounting policies as critical to 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 accounting policies are important to the portrayal of the Partnership's financial condition and results of operations and require management's most subjective or complex judgments, and as a result, are subject to an inherent degree of uncertainty.  In applying those policies, management 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 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:

Oil and 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.

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Our 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.

Exploratory well drilling costs are initially capitalized but charged to expense if the well is determined to be economically nonproductive.  The status of each in-progress well is reviewed quarterly to determine the proper accounting treatment under the successful efforts method of accounting.  Cumulative costs on in-progress exploratory wells (“Suspended Well Costs”) remain capitalized until their productive status becomes known.  If an in-progress exploratory well is found to be unsuccessful (referred to as a dry hole) prior to the issuance of financial statements, the costs are expensed to exploratory dry hole costs.  If a final determination about the productive status of a well cannot be made prior to issuance of the financial statements, the well is classified as “Suspended Well Costs” until there is sufficient time to conduct additional completion or testing operations to evaluate the pertinent geological and engineering data obtained.  When a final determination of a well’s productive status is made, the well is removed from the suspended well status and the proper accounting treatment is recorded.  The determination of an exploratory well's ability to produce is made within one year from the completion of drilling activities.  At December 31, 2008 and 2007, the Partnership had no in-progress exploratory wells requiring “Suspended Well Costs” classification.

In accordance with Statement of Financial Accounting Standards, or SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, the Partnership reviews its proved oil and gas properties for impairment whenever events and circumstances indicate that a decline in recoverability of their carrying value may have occurred.  The Partnership estimates the expected undiscounted future net cash flows of its oil and gas properties on a field-by-field basis and compares such undiscounted future net cash flows to the carrying amount of the oil and gas properties to determine if the carrying amount is recoverable.  Estimated production is based upon prices at which management reasonably estimates such products will be sold.  These estimates of future product prices may differ from current market prices of oil and natural gas.  Any downward revisions in estimates to Partnership reserve quantities, expectations of falling commodity prices or rising operating costs could result in a reduction in undiscounted future net cash flows and an impairment of our oil and gas properties.  If net capitalized costs exceed undiscounted future net cash flows, impairment is measured by the amount by which the net capitalized costs exceed their 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.

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Revenue Recognition

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, collection of revenue from the sale is reasonably assured, and the sales price is fixed or determinable.  Natural gas is sold by the Managing General Partner under contracts with terms ranging from one month up to the life of the well.  Virtually all of the Managing General Partner’s contracts’ pricing provisions are tied to a market index with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality of gas and prevailing supply and demand conditions, so that the price of the natural gas fluctuates to remain competitive with other available natural gas supplies.  As a result, the Partnership’s revenues from the sale of natural gas will suffer if market prices decline and benefit if they increase.  The Managing General Partner may from time to time enter into derivative agreements, usually with a term of two to three years, but in no cases longer than five years beyond the derivative transaction date, which may either “swap” or “collar” a price range 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 Partnership 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 contracts at prices and in accordance with arrangements that are customary in the oil industry.

Fair Value of Financial Instruments

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 delays 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.

Derivative Financial Instruments.  The Managing General Partner uses derivative instruments to manage the Partnership’s commodity and financial market risks.  The Partnership currently does not use hedge accounting treatment for its derivatives.  Derivatives are reported on the Partnership’s accompanying balance sheets at fair value on a gross asset and liability basis.  Changes in fair value of derivatives are recorded in “Oil and gas price risk management, gain (loss), net,” in the Partnership’s accompanying statements of operations.

SFAS 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.  The three levels of inputs that may be used to measure fair value are defined as:

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Level 1 – Quoted prices (unadjusted) in active markets for identical assets or liabilities.

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

Level 3 – Unobservable inputs for the asset or liability, including situations where there is little, if any, market activity for the asset or liability.  Instruments included in Level 3 consist of Partnership commodity derivatives for CIG-based natural gas swaps, NYMEX-based oil swaps, natural gas fixed-price floor and ceiling price collars and natural gas basis protection swaps.

The Partnership measures the fair value of its derivatives based upon quoted market prices, where available.  The Managing General Partner’s valuation determination includes: (1) identification of the inputs to the fair value methodology through the review of counterparty statements and other supporting documentation, (2) determination of the validity of the source of the inputs, (3) corroboration of the original source of inputs through access to multiple quotes, if available, or other information and (4) monitoring changes in valuation methods and assumptions.  The methods described above may produce a fair value calculation that may not be indicative of future fair values.  The Managing General Partner’s valuation determination also gives consideration to the nonperformance risk on PDC’s own business interest’s and liabilities, as well as the credit standing of derivative instrument counterparties.  The Managing General Partner primarily uses two investment grade financial institutions as counterparties to its derivative contracts.  The Managing General Partner has evaluated the credit risk of the Partnership’s derivative assets from counterparties 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 of December 31, 2008, the Partnership has recorded no valuation allowance.  Furthermore, while the Managing General Partner believes these valuation methods are appropriate and consistent with that used by other market participants, the use of different methodologies, or assumptions, to determine the fair value of certain financial instruments could result in a different estimate of fair value.  The Partnership has estimated the gross net fair value of Partnership commodity based derivatives as of December 31, 2008, to be $15.6 million.

Non-Derivative Financial Assets and Liabilities.  The carrying values of the financial instruments comprising “Cash and cash equivalents,” “Accounts receivable,” “Accounts payable” and “Due to (from) Managing General Partner-other” approximate fair value due to the short-term maturities of these instruments.

Asset Retirement Obligations

The Partnership applies the provisions of SFAS 143, Accounting for Asset Retirement Obligations and Financial Accounting Standards Board, or FASB, Interpretation No. 47, Accounting for Conditional Asset Retirement Obligations, and accounts for asset retirement obligations by recording the fair value of its plugging and abandonment obligations when incurred, which is at the time the well is completely drilled.  Upon initial recognition of an asset retirement obligation, the Partnership increases the carrying amount of the long-lived asset by the same amount as the liability.  Over time, the asset retirement obligations are accreted, over the estimate life of the related asset, for the change in their present value.  The initial capitalized costs are depleted over the useful lives of the related assets, through charges to DD&A expense.  If the fair value of the estimated asset retirement obligation changes, an adjustment is recorded to both the asset retirement obligation and the asset retirement cost. Revisions in estimated liabilities can result from revisions of estimated inflation rates, escalating retirement costs and changes in the estimated timing of settling asset retirement obligations.  See Note 8, Asset Retirement Obligations to the accompanying financial statements, for a reconciliation of asset retirement obligation activity.

Recent Accounting Standards

See Note 2, Summary of Significant Accounting Policies to the accompanying financial statements, included in this report for recently issued and implemented accounting standards.

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Item 7A. Quantitative and Qualitative Disclosures About Market Risk

Not applicable

Item 8. Financial Statements and Supplementary Data

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

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.

(a)  Evaluation of Disclosure Controls and Procedures

As of December 31, 2008, 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 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 defined in Exchange Act Rules 13a-15(e) and 15d-15(e) as the controls and procedures of an issuer that are designed to ensure that information required to be disclosed by the issuer in the reports it 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’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 weaknesses described below in Management’s Report on Internal Control Over Financial Reporting included in this Item 9A(T).

(b)  Management’s Report on Internal Control Over Financial Reporting

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

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

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

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

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

Management of the Managing General Partner has assessed the effectiveness of the Partnership’s internal control over financial reporting as of December 31, 2008, based upon the criteria established in “Internal Control - Integrated Framework” issued by the Committee of  Sponsoring Organizations of the Treadway Commission.  Based on this evaluation, management of the Managing General Partner concluded that the Partnership 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:

· For the transactions that are directly related to and processed by the Partnership, the Partnership failed to maintain sufficient documentation to adequately assess the operating effectiveness of internal control over financial reporting.  More specifically, the Partnership’s financial close and reporting narrative failed to adequately describe the process, identify key controls and assess segregation of duties.  This material weakness has not been remediated.

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 until 2009.

(c)  Remediation of Material Weaknesses in Internal Control

Management of the Managing General Partner identified the following material weaknesses related to the effectiveness of the Partnership’s internal controls over financial reporting as of December 31, 2007:

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

· 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:

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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 will enhance operating efficiencies and provide 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.

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 two material weaknesses which were identified as of December 31, 2007, are remediated as of December 31, 2008.

Item 9B. Other Information

None

PART III

Item 10. Directors, Executive Officers and Corporate Governance

The Partnership has no directors or executive officers.  The Partnership is managed by PDC, the Managing General Partner.

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."  Since 1969, PDC has been engaged in the business of exploring for, developing and producing oil and gas primarily in West Virginia, Tennessee, Pennsylvania, 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.

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As the Managing General Partner, PDC actively manages and conducts the business of the Partnership.  PDC has the full and complete power to do any and all things necessary and incident to the management and conduct of 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, they devote the entirety of their daily time to the business and operations of PDC.  One of the major business segments of PDC includes the operation of the business of PDC's sponsored limited partnerships, including the Partnership.  An element of their 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 varies over the life of the Partnership.

In addition to managing the affairs of the Partnership, the management and technical staff of PDC also manage the corporate affairs of PDC, the affairs of 33 limited partnerships and other joint ventures formed over the years.  PDC owns an interest in all of the 33 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 its 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. Since PDC has an interest in all Partnership wells, the operations of such wells receive the full attention of the operations group to maximize the well's performance for both the Partnership and PDC.

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.

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Experience and Capabilities as Driller/Operator

PDC is contracted 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 prospects for drilling by PDC and who help oversee the drilling process.  In addition, PDC has an engineering staff that is responsible for well completions, 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 reserves of all wells at least annually and reviews 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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Petroleum Development Corporation

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

Name	Age	Positions and Offices Held	Director Since	Directorship Term Expires
Richard W McCullough	56	Chairman, Chief Executive Officer, President and Director	2007	2010
Gysle R. Shellum	56	Chief Financial Officer	-	-
Eric R. Stearns	50	Executive Vice President	-	-
Darwin L. Stump	53	Chief Accounting Officer	-	-
Daniel W. Amidon	47	General Counsel and Secretary	-	-
Barton R. Brookman, Jr.	46	Senior Vice President Exploration and Production	-	-
Steven R. Williams	58	Director	1983	2009
Vincent F. D'Annunzio	56	Director	1989	2010
Jeffrey C. Swoveland	53	Director	1991	2011
Kimberly Luff Wakim	50	Director	2003	2009
David C. Parke	41	Director	2003	2011
Anthony J. Crisafio	55	Director	2006	2009
Joseph E. Casabona	64	Director	2007	2011
Larry F. Mazza	47	Director	2007	2010

Richard W. McCullough was appointed Chief Executive Officer and President in June 2008.  He was additionally appointed Chairman in November 2008.  Mr. McCullough joined the Company as Chief Financial Officer in November of 2006.  A financial executive with over thirty years of experience working both for and with utilities and energy companies, Mr. McCullough previously held the position of President and CEO of Gasource, LLC and has held senior positions with JP Morgan Securities, Progress Energy, Deloitte and Touche, and the Municipal Gas Authority of Georgia.  Mr. McCullough holds both BS and MS degrees from the University of Southern Mississippi and was a practicing Certified Public Accountant for eight years.

Gysle R. Shellum, was appointed Chief Financial Officer in November 2008.  With over 25 years of energy related experience within the accounting, finance, risk management and merger and acquisition areas.  Mr. Shellum recently held the position of Vice President, Finance and Special Projects at CrossTex Energy, LP.  Mr. Shellum also served as Director of Value Capital, LLC; Chief Financial and Operating Officer at Financial Trade Solutions; Chief Financial Officer at Duer Wagner Co.; and as American International Petroleum Corporation’s Chief Financial Officer.  Mr. Shellum began his career as a practicing CPA in Arthur Andersen’s Energy Group.  Mr. Shellum is a graduate of the University of Texas at Arlington with a BBA in Accounting.

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Darwin L. Stumpwas appointed Chief Accounting Officer in November 2006.  Previously, Mr. Stump served as Chief Financial Officer and Treasurer since November 2003.  Mr. Stump has been an officer of the Company since April 1995 and held the position of Corporate Controller since 1980 when he joined the Company.  Prior to joining PDC, Mr. Stump was a senior accountant with Main Hurdman, Certified Public Accountants.  Mr. Stump is a graduate of West Virginia University with a BSBA in Accounting and a Certified Public Accountant.

Eric R. Stearns was appointed Executive Vice President in March 2008 after serving as Executive Vice President of Exploration and Development since December 2004.  Prior thereto, Mr. Stearns was Vice President of Exploration and Development since November 2003, having previously served as Vice President of Exploration since April 1995.  Mr. Stearns joined PDC as a geologist in 1985 after working for Hywell, Incorporated and for Petroleum Consultants.

Daniel W. Amidonwas appointed General Counsel in July of 2007.  An attorney with over 20 years of experience working with public and private companies, Mr. Amidon recently held the position of Vice President, Law with Wheeling-Pittsburgh Steel Corporation.  Prior thereto, Mr. Amidon worked for J&L Specialty Steel for twelve years in positions of increasing responsibility, ultimately serving as the General Counsel and Secretary.  He has also practiced with the Pittsburgh law firm of Buchanan Ingersoll for the first five years of his career and brings extensive experience to PDC in the areas of corporate law, contract negotiation, corporate governance, litigation management, mergers and acquisitions, and risk management.  Mr. Amidon earned a B.A. degree with honors from the University of Virginia in Economics and Psychology and a J.D. degree from the Dickinson School of Law of the Pennsylvania State University.

Barton R. Brookman, Jr. was appointed Senior Vice President Exploration and Production in March 2008 after serving as Vice President of Production since joining PDC in 2005.  Mr. Brookman has over twenty years of operations experience within the E&P sector.  Prior to joining PDC, Mr. Brookman worked for Patina oil and gas and its predecessor Snyder Oil for 17 years in a series of jobs of increasing responsibility ending his service as Vice President of Operations of Patina.  Mr. Brookman received a BS in Petroleum Engineering from the Colorado School of Mines and a MS in Finance from the University of Colorado/Denver.

Steven R. Williams was appointed Director as part of his planned retirement in 2008.  Previous to this, Mr. Williams was Chairman of the Board.  Until his retirement in 2008, he served as Chief Executive Officer of the Company since January 2004, as President from March 1983 until December 2004, and as a Director of PDC since March 1983.  Mr. Williams serves as Chairman of the Executive Committee.

Vincent F. D'Annunzio has been a Director since 1989.  Mr. D’Annunzio also serves as President of Beverage Distributors, Inc. located in Clarksburg, West Virginia and has held this position 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 been a director since 1991 and was selected as Presiding Independent Director in 2007.  Mr. Swoveland serves as Chief Financial Officer of Body Media and has held this position since September 2000.  Prior thereto, Mr. Swoveland was Vice President-Finance and Treasurer of Equitable Resources Inc.  Mr. Swoveland serves as Presiding Independent Director, and serves on the Planning and Finance Committee.

Kimberly Luff Wakim has been a director since 2003.  An Attorney and Certified Public Accountant, Ms. Wakim is a Partner with the law firm Thorp, Reed & Armstrong LLP, joining the firm in 1990.  Ms. Wakim serves on the Audit Committee and Nominating and Governance Committee.

David C. Parke has been a Director since 2003.  In November 2006, Mr. Parke joined Boenning & Scattergood, Inc. as Managing Director in their Investment Banking Group.  Prior thereto, Mr. Parke operated as a founder and Director of Mufson/Howe/Hunter & Company LLC, an investment-banking firm, since 2003.  From 1992-2003 Mr. Parke was with the corporate finance department of Investec, Inc. and its predecessor Pennsylvania Merchant Group, Ltd., both 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.  Mr. Parke serves as Chairman of both the Planning and Finance Committee and the Compensation Committee.  He also serves on the Nominating and Governance Committee and Audit Committee.

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Anthony J. Crisafiohas been a Director since 2006.  Mr. Crisafio serves as an independent business consultant, providing financial and operational advice to businesses, and a business owner.  Prior thereto, he was the Chief Operating Officer of Cinema World, Inc. and a Partner with Ernst & Young.  Mr. Crisafio serves as the chairman of the Audit Committee and serves on the Compensation Committee.

Joseph E. Casabona has been a Director since 2007.  Mr. 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 on the Audit Committee and the Planning and Finance Committee.

Larry F. Mazzahas been a Director since 2007.  Mr. Mazza was instrumental in the formation of and is currently serving as CEO of MVB Bank, Inc. of Harrison County, West Virginia.  Prior to the formation of MVB Bank, Mr. Mazza served as Senior Vice President Retail Banking Manager for BB&T in West Virginia and as President of two other local West Virginia Banks.  Prior to his banking experience, Mr. Mazza was a CPA with a Big-Four accounting firm.

The Audit Committee of the Board of Directors is comprised of Directors Swoveland, Crisafio, Parke, 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, with the exception of Mr. Parke, qualify as audit committee financial experts and are independent of management.

Item 11. Executive Compensation

The Partnership does not have any employees or executives of its own.  None of PDC's officers or directors receive any direct remuneration, compensation or reimbursement from the Partnership.  These persons receive compensation solely from PDC.  Amounts paid to the Managing General Partner by the Partnership are not used to directly compensate or reimburse PDC’s officers or directors.  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.

Compensation Committee Interlocks and Insider Participation

There are no Compensation Committee interlocks.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

As of December 31,2008, the Partnership had 4,470 units outstanding.  No director or officer of PDC owns any units.  As of December 31, 2008, PDC has purchased no units of Partnership interests from Investor Partners.  PDC owns a 37% partnership interest in the Partnership.

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 Partnerships business on behalf of 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.

- 44 -

Related Party Transaction Policies and Approval

The Limited Partnership Agreement and the Drilling and Operating Agreement with Petroleum Development Corporation govern related party transactions, including those described above.

Other Agreements and Arrangements

Executive officers of the Managing General Partner are eligible to invest in a Board-approved executive drilling program, as approved by the Board of Directors.

These executive officers may profit from their participation in the executive drilling program because they invest in wells at cost and do not have to pay drilling compensation, management fees or broker commissions and therefore obtain an interest in the wells at a reduced price than that which is generally charged to the investing partners in a Partnership.  Investor partners participating in drilling through a partnership are generally charged a profit or markup above the cost of the wells; management fees and commissions at rates which are generally similar to those for this Partnership outlined in Note 3, Transactions with Managing General Partner and Affiliates to the accompanying financial statements.

Through the executive drilling program, certain executive officers have invested in all of the wells owned by the Partnership prior to the drilling of each of the wells.  Ownership by each executive in Partnership wells varies depending on when the well was drilled and the amount of funds invested in the program.  The aggregate ownership percentage is 0.019% of each well in the Partnership.  The Board believes that having the executive officers invest in wells with the company 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.

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 billings from the Partnership’s independent registered public accounting firm, PricewaterhouseCoopers LLP ("PwC"), of $267,468 for audit fees for the year 2008 and $145,600 for the period May 22, 2007 (date of inception) to December 31, 2007.  The 2008 audit fees include amounts billed for professional services for the audit of the Partnership’s financial statements in its Form 10-K for the year ended December 31, 2008 and for the reviews of the condensed unaudited financial statements included in the Partnership’s Form 10-Q and 10-Q/A for the quarters ended June 30 and September 30, 2008.  The 2007 audit fees include amounts billed for professional services rendered by PwC for the audit of the Partnership’s financial statements in its Form 10 and Form 10/A for the period ended December 31, 2007 and review of the condensed unaudited financial statements for the three months ended March 31, 2008.  For the period May 22, 2007 (date of inception) to December 31, 2007 and year ended December 31, 2008, there were tax billings from independent registered public accounting firm, PwC, of $21,631 and $18,359, respectively.

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.

- 45 -

Item 15. Exhibits, Financial Statement Schedules

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

(b) Exhibit Index.

		Incorporated by Reference
Exhibit Number	Exhibit Description	Form	Sec File Number	Exhibit	Filing Date	Filed Herewith
3.1	Limited Partnership Agreement	10-12G/A Amend 1	000-53201	3	08/06/2008
3.2	Certificate of limited partnership which reflects the organization of the Partnership under West Virginia law	10-12G/A Amend 1	000-53201	3.1	08/06/2008
10.1	Form of assignment of leases to the Partnership	10-12G/A Amend 1	000-53201	10.1	08/06/2008
10.2	Drilling and operating agreement between PDC as Managing General Partner of the Partnership	10-12G/A Amend 1	000-53201	10.2	08/06/2008
10.3	Audited Consolidated Financial Statements for the year ended December 31, 2008 of Petroleum Development Corporation and its subsidiaries, as Managing General Partner of the Partnership	10-K	000-07246		02/27/2009
10.4	Gas Purchase and Processing Agreement between Duke Energy Field Services, Inc.; United States Exploration, Inc.; and Petroleum Development Corporation, dated October 28, 1999*	10-12G/A Amend 3	000-53201	10.3	03/31/2009
10.5	Gas Purchase and Processing Agreement between Natural Gas Associates, a Colorado partnership, and Aceite Energy Corporation, Walker Exploratory Program 1982-A Limited and Creek Cattle Company, dated October 14, 1983*	10-12G/A Amend 3	000-53201	10.4	03/31/2009

- 46 -

		Incorporated by Reference
Exhibit Number	Exhibit Description	Form	Sec File Number	Exhibit	Filing Date	Filed Herewith
10.6	Gas Purchase and Processing Agreement between Natural Gas Associates, a Colorado partnership, and SHF Partnership, a Colorado general partnership, Trailblazer Oil and Gas, Inc. Alfa Resources, Inc., Pulsar Oil and Gas, Inc., Overthrust Oil Royalty Corporation, Corvette Petroleum Ltd., Robert Lanari, an individual, and Toby A Martinez, an individual, dated September 21, 1983*	10-12G/A Amend 3	000-53201	10.5	03/31/2009
10.7	Domestic Crude Oil Purchase Agreement with ConocoPhillips Company, dated January 1, 1993, as amended by agreements with Teppco Crude Oil, LLC dated August 2, 2007; September 24, 2007; October 17, 2007; January 7, 2008; January 15, 2008; and April 17, 2008*	10-12G/A Amend 3	000-53201	10.6	03/31/2009
10.8	Gas Purchase Agreement between Williams Production RMT Company, Riley Natural Gas Company and Petroleum Development Corporation, dated as of June 1, 2006*	10-12G/A Amend 3	000-53201	10.7	03/31/2009
23.1	Consent of Ryder Scott Company, L.P., Petroleum Consultants					X
31.1	Rule 13a-14(a)/15d-14(c) Certification of Chief Executive Officer of Petroleum Development Corporation, the Managing General Partner of the Partnership.					X
31.2	Rule 13a-14(a)/15d-14(c) Certification of Chief Financial Officer of Petroleum Development Corporation, the Managing General Partner of the Partnership.					X

- 47 -

		Incorporated by Reference
Exhibit Number	Exhibit Description	Form	Sec File Number	Exhibit	Filing Date	Filed Herewith
32.1	Title 18 U.S.C. Section 1350 (Section 906 of Sarbanes-Oxley Act of 2002) Certification by Chief Executive Officer of Petroleum Development Corporation, the Managing General Partner of the Partnership.					X
32.2	Title 18 U.S.C. Section 1350 (Section 906 of Sarbanes-Oxley Act of 2002) Certification by Chief Financial Officer of Petroleum Development Corporation, the Managing General Partner of the Partnership.					X

_______________

*A confidential treatment request pursuant to Exchange Act rule 24b.2 was filed with the SEC with respect to portions of these agreements.

- 48 -

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.

Rockies Region 2007 Limited Partnership

By its Managing General Partner

Petroleum Development Corporation

By /s/ Richard W. McCullough

Richard W. McCullough

Chairman, Chief Executive Officer and President

March 31, 2009

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, Chief Executive Officer and President	March 31, 2009
Richard W. McCullough	Petroleum Development Corporation,
	Managing General Partner of the Registrant
	(Principal executive officer)
/s/ Gysle R. Shellum	Chief Financial Officer	March 31, 2009
Gysle R. Shellum	Petroleum Development Corporation,
	Managing General Partner of the Registrant
	(Principal financial officer)
/s/ Darwin L. Stump	Chief Accounting Officer	March 31, 2009
Darwin L. Stump	Petroleum Development Corporation,
	Managing General Partner of the Registrant
	(Principal accounting officer)
/s/ Steven R. Williams	Director	March 31, 2009
Steven R. Williams	Petroleum Development Corporation,
	Managing General Partner of the Registrant
/s/ Anthony J. Crisafio	Director	March 31 , 2009
Anthony J. Crisafio	Petroleum Development Corporation,
	Managing General Partner of the Registrant
/s/ Jeffrey C. Swoveland	Director	March 31 , 2009
Jeffrey C. Swoveland	Petroleum Development Corporation,
	Managing General Partner of the Registrant
/s/ Joseph E. Casabona	Director	March 31, 2009
Joseph E. Casabona	Petroleum Development Corporation,
	Managing General Partner of the Registrant

- 49 -

ROCKIES REGION 2007 LIMITED PARTNERSHIP

Index to Financial Statements

Report of Independent Registered Public Accounting Firm	F-2
Balance Sheets – December 31, 2008 and 2007	F-3
Statements of Operations – For the Year Ended December 31, 2008 and Period May 22, 2007 (date of inception) to December 31, 2007	F-4
Statements of Partners' Equity –For the Year Ended December 31, 2008 and Period May 22, 2007 (date of inception) to December 31, 2007	F-5
Statements of Cash Flows – For the Year Ended December 31, 2008 and Period May 22, 2007 (date of inception) to December 31, 2007	F-6
Notes to Financial Statements	F-7
Supplemental Oil and Gas Information - Unaudited	F-25

F - 1

ROCKIES REGION 2007 LIMITED PARTNERSHIP

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Partners of the Rockies Region 2007 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 Rockies Region 2007 Limited Partnership (the "Partnership") at December 31, 2008 and 2007, and the results of its operations and its cash flows for the year ended December 31, 2008 and the period from May 22, 2007 (date of inception) to December 31, 2007 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/ Pricewaterhouse Coopers LLP

Pittsburgh, Pennsylvania

March 31, 2009

F - 2

ROCKIES REGION 2007 LIMITED PARTNERSHIP

Balance Sheets

December 31, 2008 and 2007

Assets	2008			2007
Current assets:
Cash and cash equivalents	$	1,352,993		$	783,845
Accounts receivable		8,621,482			1,160,201
Oil Inventory		44,562			-
Due from Managing General Partner-derivatives, net		12,096,394			-
Due from Managing General Partner-other, net		3,029,136			-
Interest receivable		-			531,867
Total current assets		25,144,567			2,475,913
Oil and gas properties, successful efforts method		117,325,135			10,373,394
Wells in progress		-			40,286,695
Drilling advances to Managing General Partner		719,724			67,045,826
Oil and gas properties, at cost		118,044,859			117,705,915
Less accumulated depreciation, depletion and amortization		(16,028,595	)		(464,341	)
Oil and gas properties, net		102,016,264			117,241,574
Due from Managing General Partner-derivatives		3,536,338			-
Total noncurrent assets		105,552,602			117,241,574
Total Assets	$	130,697,169		$	119,717,487
Liabilities and Partners' Equity
Current liabilities:
Accounts payable and accrued expenses	$	750,904		$	87,479
Due to Managing General Partner-derivatives, net		-			319,365
Due to Managing General Partner-other, net		-			29,995
Total current liabilities		750,904			436,839
Asset retirement obligations		416,110			55,643
Total liabilities		1,167,014			492,482
Commitments and contingencies
Partners' equity:
Managing General Partner		42,962,019			39,242,116
Limited Partners - 4,470 units issued and outstanding		86,568,136			79,982,889
Total Partners' equity		129,530,155			119,225,005
Total Liabilities and Partners' Equity	$	130,697,169		$	119,717,487

See accompanying notes to financial statements.

F - 3

ROCKIES REGION 2007 LIMITED PARTNERSHIP

Statements of Operations

For the Year Ended December 31, 2008 and

Period from May 22, 2007 (date of inception) to December 31, 2007

	2008		Period May 22, 2007 (date of inception) through December 31, 2007
Revenues:
Oil and gas sales	$	43,939,519	$	1,160,201
Oil and gas price risk management gain (loss), net		18,117,972		(319,365	)
Total revenues		62,057,491		840,836
Operating costs and expenses:
Production and operating costs		7,316,813		121,897
Management fee		-		1,341,043
Direct costs - general and administrative		607,289		-
Depreciation, depletion and amortization		15,564,254		464,341
Accretion of asset retirement obligations		21,523		927
Total operating costs and expenses		23,509,879		1,928,208
Income (loss) from operations		38,547,612		(1,087,372	)
Interest income		104,001		1,320,134
Net income	$	38,651,613	$	232,762
Net income allocated to partners	$	38,651,613	$	232,762
Less Managing General Partner interest in net income		14,301,097		582,308
Net income (loss) allocated to Investor Partners	$	24,350,516	$	(349,546	)
Net income (loss) per Investor Partner unit	$	5,448	$	(78	)
Investor Partner units outstanding		4,470		4,470

See accompanying notes to financial statements.

F - 4

ROCKIES REGION 2007 LIMITED PARTNERSHIP

Statements of Partners' Equity

For the Year Ended December 31, 2008 and

Period from May 22, 2007 (date of inception) to December 31, 2007

	Investor Partners			Managing General Partner			Total
Balance, May 22, 2007	$	-		$	-		$	-
Partners' initial contributions		89,402,885			38,659,808			128,062,693
Syndication costs		(9,070,450	)		-			(9,070,450	)
Net income (loss)		(349,546	)		582,308			232,762
Balance, December 31, 2007		79,982,889			39,242,116			119,225,005
Distributions to partners		(17,765,269	)		(10,581,194	)		(28,346,463	)
Net income		24,350,516			14,301,097			38,651,613
Balance, December 31, 2008	$	86,568,136		$	42,962,019		$	129,530,155

See accompanying notes to financial statements.

F - 5

ROCKIES REGION 2007 LIMITED PARTNERSHIP

Statements of Cash Flows

For the Year Ended December 31, 2008 and

Period from May 22, 2007 (date of inception) to December 31, 2007

	2008			Period May 22, 2007 (date of inception) through December 31, 2007
Cash flows from operating activities:
Net income	$	38,651,613		$	232,762
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization		15,564,254			464,341
Accretion of asset retirement obligations		21,523			927
Unrealized loss (gain) on derivative transactions		(15,952,097	)		319,365
Changes in operating assets and liabilities:
Increase in accounts receivable		(7,461,281	)		(1,160,201	)
Increase in oil inventory		(44,562	)		-
Decrease (increase) in interest receivable		531,867			(531,867	)
Increase in accounts payable and accrued expenses		663,425			87,479
(Decrease) increase  in due from/to Managing General Partner, net		(3,059,131	)		29,995
Net cash provided by (used in) operating activities		28,915,611			(557,199	)
Cash flows from investing activities:
Capital expenditures for oil and gas properties and drilling advances to the MGP		-			(117,651,199	)
Net cash used in investing activities		-			(117,651,199	)
Cash flows from financing activities:
Investor Partners' contributions		-			89,402,885
Managing General Partner contribution		-			38,659,808
Syndication costs paid		-			(9,070,450	)
Distributions to Partners		(28,346,463	)		-
Net cash (used in) provided by financing activities		(28,346,463	)		118,992,243
Net increase in cash and cash equivalents		569,148			783,845
Cash and cash equivalents, beginning of period		783,845			-
Cash and cash equivalents, end of period	$	1,352,993		$	783,845
Supplemental disclosure of non-cash activity:
Asset retirement obligation, with corresponding increase to oil and gas properties	$	338,944		$	54,716

See accompanying notes to financial statements.

F - 6

ROCKIES REGION 2007 LIMITED PARTNERSHIP

Notes to Financial Statements

Note 1 - Organization

The Rockies Region 2007 Limited Partnership (the “Partnership” or the “Registrant”) was organized as a limited partnership on May 22, 2007, in accordance with the laws of the State of West Virginia for the purpose of engaging in the exploration and development of oil and natural gas properties and commenced business operations as of the date of organization.

Purchasers of partnership units subscribed to and fully paid for 38.5 units of limited partner interests and 4,431.5 units of additional general partner interests at $20,000 per unit.  As of December 31, 2008, there are 1,782 Investor Partners.  Petroleum Development Corporation (“PDC”) has been designated the Managing General Partner of the Partnership and has a 37% ownership in the Partnership. Generally, throughout the term of the Partnership, revenues, costs, and cash distributions are allocated 63% to the limited and additional general partners (collectively, the “Investor Partners”), which are shared pro rata based upon the amount of their investment in the Partnership, and 37% to the Managing General Partner.  As of December 31, 2008, the Managing General Partner has not repurchased any units of Partnership interests from Investor Partners.

Upon completion of the drilling phase of the Partnership's wells, all additional general partners units were converted into units of limited partner interests and thereafter became limited partners of the Partnership.

In accordance with the terms of the Limited Partnership Agreement (the “Agreement”), the Managing General Partner manages all activities of the Partnership and acts as the intermediary for substantially all Partnership transactions.

Executive Drilling Program

Executive officers of the Managing General Partner are eligible to invest in a Board-approved executive drilling program, as approved by the Board of Directors.  These executive officers may profit from their participation in the executive drilling program because they invest in wells at cost and do not have to pay drilling compensation, management fees or broker commissions and therefore obtain an interest in the wells at a reduced price than that which is generally charged to the investing partners in a Partnership.  Investor partners participating in drilling through a partnership are generally charged a profit or markup above the cost of the wells, management fees and commissions.  See Note 3, Transactions with Managing General Partner.

Through the executive drilling program, certain executive officers have invested in the wells owned by the Partnership.  Ownership by each executive in Partnership wells varies depending on when the well was drilled and the amount of funds invested in the program.  The aggregate ownership percentage is 0.019% 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.

Note 2 - Summary of Significant Accounting Policies

Basis of Presentation

The financial statements include only those assets, liabilities and results of operations of the partners which relate to the business of the Partnership.  The statements do not include any assets, liabilities, revenues or expenses attributable to any of the partners' other activities.

Cash and Cash Equivalents

The Partnership considers all highly liquid investments with original maturities of three months or less to be cash equivalents.  The Partnership maintains substantially all of its cash and cash equivalents in a bank account at one financial institution.  The balance in the Partnership’s account is temporarily insured by the Federal Deposit Insurance Corporation, or FDIC, in an amount up to $250,000 through December 31, 2009, after such date the FDIC limit will revert to $100,000 unless the temporary limit is extended or made permanent.  At times, the Partnership’s account balance may exceed FDIC limits.  The Partnership has not experienced losses in any such accounts and limits its exposure to credit loss by placing its cash and cash equivalents with high-quality financial institutions.

F - 7

ROCKIES REGION 2007 LIMITED PARTNERSHIP

Notes to Financial Statements

Accounts Receivable and Allowance for Doubtful Accounts

The Partnership’s accounts receivable are from purchasers of oil and natural gas production.  The Partnership sells substantially all of its oil and natural gas to customers who purchase oil and natural gas from other partnerships managed by the Partnership’s Managing General Partner.  Inherent to our industry is the concentration of oil and natural gas sales to a few customers.  This industry concentration has the potential to impact the Partnership’s overall exposure to credit risk, either positively or negatively, in that its customers may be similarly affected by changes in economic, industry or other conditions.

As of December 31, 2008 and 2007, the Partnership did not record an allowance for doubtful accounts.  Historically, neither PDC nor any of the other partnerships managed by the Partnership’s Managing General Partner have experienced significant losses on accounts receivable.  The Managing General Partner periodically reviews accounts receivable for credit risks resulting from changes in the financial condition of its customers.  The Partnership did not incur any losses on accounts receivable for the year ended December 31, 2008 or the period from May 22, 2007 (date of inception) to December 31, 2007.

Due from (to) Managing General Partner – Other, net

The Managing General Partner transacts business on behalf of the Partnership.  Other than undistributed oil and natural gas revenues by PDC to the Partnership and the Partnership’s portion of unexpired derivatives instruments, which are included in separate balance sheet captions, all other unsettled transactions with PDC and its affiliates are recorded net on the balance sheet under the caption “Due from (to) MGP – Other, net.”  Refer to note 3.  In addition certain amounts recorded by the Partnership as liabilities in the account “Due from (to) Managing General Partner-other, net” were funded by the Managing General Partner and are currently held in escrow for distribution to litigants, which represent unpaid royalties on Partnership production from 2007 and 2008 which will be deducted from future Partner distributions.  These amounts, which total $78,105 as of December 31, 2008, represent the Partnership’s share of the court approved royalty litigation settlement, more fully described in Note 9, Commitments and Contingencies.

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

Inventories

Oil inventories are stated at the lower of average lifting cost or market, and are removed at carrying value.

Oil and Gas Properties

The Partnership accounts for its oil and natural gas properties (the “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 obtains reserve reports from independent petroleum engineers annually as of December 31 of each year.  See Supplemental Oil and Gas Information–Unaudited, Net Proved Oil and Gas Reserves for additional information regarding the Partnership’s reserve reporting.  In accordance with the Agreement, all capital contributed to the Partnership after deducting syndication costs and a one-time management fee is required to be used solely for the drilling of oil and natural gas wells.  Accordingly, all such funds were advanced to the Managing General Partner  as of December 31, 2007.  Amounts that have not yet been used by the Managing General Partner for drilling activities are reported under the caption “Drilling advances to Managing General Partner.”  The Partnership does not maintain an inventory of undrilled leases.

F - 8

ROCKIES REGION 2007 LIMITED PARTNERSHIP

Notes to Financial Statements

Partnership 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.  Independent petroleum engineers prepare the annual reserve and economic evaluation of all properties on a well-by-well basis.  Additionally, the Partnership adjusts oil and gas reserves for major well rework or abandonment during the year as needed. 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 our Depletion, Depreciation and Amortization (“DD&A”) expense, a change in our estimated reserves could have an effect on our net income.

Exploratory well drilling costs are initially capitalized but charged to expense if the well is determined to be nonproductive.  The status of each in-progress well is reviewed quarterly to determine the proper accounting treatment under the successful efforts method of accounting. Cumulative costs on in-progress wells (“Suspended Well Costs”) remain capitalized until their productive status becomes known. If an in-progress exploratory well is found to be unsuccessful (referred to as a dry hole) prior to the issuance of financial statements, the costs incurred as of the balance sheet date are expensed to exploratory dry hole costs. If a final determination about the productive status of a well is unable to be made prior to issuance of the financial statements, the well is classified as “Suspended Well Costs” until there is sufficient time to conduct additional completion or testing operations to evaluate the pertinent geological and engineering data obtained. When a final determination of a well’s productive status is made, the well is removed from the suspended well status and the proper accounting treatment is recorded. The determination of an exploratory well's ability to produce is made within one year from the completion of drilling activities.  At December 31, 2008 and 2007, the Partnership had no in-progress exploratory wells requiring “Suspended Well Cost” classification.

In accordance with Statement of Financial Accounting Standards, or SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, the Partnership reviews its proved oil and gas properties for impairment whenever events and circumstances indicate that a decline in recoverability of their carrying value may have occurred.  The Partnership estimates the expected undiscounted future net cash flows of its oil and gas properties on a field-by-field basis and compares such undiscounted future net cash flows to the carrying amount of the oil and gas properties to determine if the carrying amount is recoverable.  Estimated production is based upon prices at which management reasonably estimates such products will be sold. These estimates of future product prices may differ from current market prices of oil and natural gas. Any downward revisions to the Partnership’s estimates of future production or product prices could result in an impairment of the Partnership's oil and natural gas properties in subsequent periods. If net capitalized costs exceed undiscounted future net cash flows, impairment is measured by the amount by which the net capitalized costs exceed their fair value. The Partnership has incurred no impairment losses from May 22, 2007 (date of inception) to December 31, 2008 on its proved oil and natural gas properties.

Revenue Recognition

Sales of natural gas are recognized when natural gas has been delivered to a custody transfer point, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser upon delivery, collection of revenue from the sale is reasonably assured, and the sales price is fixed or determinable.  Natural gas is sold by the Managing General Partner under contracts with terms ranging from one month up to the life of the well.  Virtually all of the Managing General Partner’s contracts pricing provisions are tied to a market index with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality of natural gas and prevailing supply and demand conditions, so that the price of the natural gas fluctuates to remain competitive with other available gas supplies.

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Notes to Financial Statements

The Partnership currently uses the “Net-Back” method of accounting for transportation arrangements of natural gas sales.  The Partnership 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 is currently able to sell all the oil that it can produce under existing sales contracts with petroleum refiners and marketers.  The Partnership does not refine any of its oil production.  The Partnership’s crude oil production is sold 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.

The Partnership presents any taxes collected from customers and remitted to a government agency on a net basis in its statements of operations in accordance with EITF 06-3, How Taxes Collected from Customers and Remitted to Governments Should be Presented in the Income Statement.

The Partnership sold natural gas and oil to three customers: DCP Midstream LP (“DCP”), Teppco Crude Oil, LP (“Teppco”) and Williams Production RMT (“Williams”), which accounted for 14%, 48%, and 38%, respectively, of the Partnership’s total natural gas and oil sales for the year ended December 31, 2008.  Two of these customers in 2007: DCP and Teppco, accounted for 13% and 87% respectively, of the Partnership’s total natural gas and oil sales for the period ended December 31, 2007.

Asset Retirement Obligations

The Partnership applies the provisions of SFAS No. 143, Accounting for Asset Retirement Obligations and Financial Accounting Standards Board, or FASB, Interpretation No. 47, Accounting for Conditional Asset Retirement Obligations, and accounts for asset retirement obligations by recording the fair value of its plugging and abandonment obligations when incurred, which is at the time the well is completely drilled.  Upon initial recognition of an asset retirement obligation, the Partnership increases the carrying amount of the long-lived asset by the same amount as the liability.  Over time, the asset retirement obligations are accreted, over the estimated life of the related asset, for the change in their present value.  The initial capitalized costs are depleted over the useful lives of the related assets, through charges to DD&A expense.  If the fair value of the estimated asset retirement obligation changes, an adjustment is recorded to both the asset retirement obligation and the asset retirement cost. Revisions in estimated liabilities can result from revisions of estimated inflation rates, escalating retirement costs and changes in the estimated timing of settling asset retirement obligations.  See Note 8, Asset Retirement Obligations for a reconciliation of asset retirement obligation activity.

Derivative Financial Instruments

The Partnership accounts for derivative financial instruments in accordance with Statement of Financial Accounting Standards (“SFAS”) No. 133, Accounting for Derivative Instruments and Certain Hedging Activities, as amended.

During 2008 and the period from May 22, 2007 (date of inception) to December 31, 2007, none of the Partnership’s derivative instruments qualified for use of hedge accounting under the provisions of SFAS No. 133.  Accordingly, the Partnership recognizes all derivative instruments as either assets or liabilities on its balance sheets at fair value, and changes in the derivatives' fair values are recorded on a net basis in the Partnership’s statements of operations.  Changes in the fair value of derivative instruments related to the Partnership’s oil and gas sales activities are recorded in “Oil and gas price risk management, gain (loss), net.”

See Note 4, Derivative Financial Instruments, and Note 5, Fair Value of Financial Instruments, for a discussion of the Partnership’s derivative fair value measurements and a summary fair value table of open positions as of December 31, 2008 and 2007, respectively.

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Notes to Financial Statements

Income Taxes

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

Production Tax Liability

The Partnership is responsible for production taxes which are primarily made up of severance and property taxes to be paid to the states and counties in which the Partnership produces oil and natural gas. The Partnership’s share of these taxes is expensed to production and operating costs.  The Partnership’s production taxes payable are included in the caption “Accounts payable and accrued expenses” on the Partnership’s Balance Sheet.

Use of Estimates

The Partnership has made a number of estimates and assumptions relating to the reporting of assets and liabilities and revenues and expenses and the disclosure of contingent assets and liabilities to prepare these Partnership financial statements in conformity with accounting principles generally accepted in the United States of America. Actual results could differ from those estimates. Estimates which are particularly significant to the financial statements include estimates of oil and natural gas reserves, future cash flows from oil and natural gas properties which are used in assessing impairment of long-lived assets, estimated production and severance taxes, asset retirement obligations, and valuation of derivative instruments.

Recently Adopted Accounting Standards

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 delays 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.  As of the adoption date, the Partnership has applied the provisions of SFAS No. 157 to its recurring measurements and the impact was not material to the Partnership’s underlying fair values and no amounts were recorded relative to the cumulative effect of a change in accounting principle.  The Partnership is currently evaluating the potential effect that the nonfinancial assets and liabilities provisions of SFAS No. 157 will have on its financial statements when adopted in 2009.  See Note 5, Fair Value Measurements.

In October 2008, the FASB issued FSP No. FAS 157-3, Determining the Fair Value of a Financial Asset in a Market That Is Not Active, which applies to financial assets within the scope of accounting pronouncements that require or permit fair value measurements in accordance with SFAS No. 157. This FSP clarifies the application of SFAS No. 157 in a market that is not active and defines additional key criteria in determining the fair value of a financial asset when the market for that financial asset is not active.  FSP No. FAS 157-3 was effective upon issuance and did not have a material impact on the Partnership’s financial statements.

In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities.  SFAS No. 159 permits entities to choose to measure, at fair value, many financial instruments and certain other items that are not currently required to be measured at fair value.  The objective is to improve financial reporting by providing entities with the opportunity to mitigate volatility in reported earnings caused by measuring related assets and liabilities differently without having to apply complex hedge accounting provisions.  SFAS No. 159 establishes presentation and disclosure requirements designed to facilitate comparisons between entities that choose different measurement attributes for similar types of assets and liabilities.  The statement will be effective as of the beginning of an entity's first fiscal year beginning after November 15, 2007.  The Partnership has not and does not intend to measure additional financial assets and liabilities at fair value.

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Notes to Financial Statements

In April 2007, the FASB issued FASB Interpretation (“FIN”) No. 39-1, Amendment of FASB Interpretation No. 39,  to amend certain portions of Interpretation 39.  FIN 39-1 replaces the terms “conditional contracts” and “exchange contracts” in Interpretation 39 with the term “derivative instruments” as defined in Statement 133.  FIN 39-1 also amends Interpretation 39 to allow for the offsetting of fair value amounts for the right to reclaim cash collateral or receivable, or the obligation to return cash collateral or payable, arising from the same master netting arrangement as the derivative instruments.  FIN 39-1 applies to fiscal years beginning after November 15, 2007, with early adoption permitted.  The January 1, 2008, adoption of FSP FIN 39-1 had no impact on the Partnership’s financial statements.

Recently Issued Accounting Standards

In December 2007, the FASB issued SFAS No. 141 (revised 2007), Business Combinations (“SFAS No. 141R”).  SFAS No. 141R requires an acquirer to recognize the assets acquired, the liabilities assumed and any noncontrolling interest in the acquiree at their acquisition-date fair values.  SFAS No. 141R also requires disclosure of the information necessary for investors and other users to evaluate and understand the nature and financial effect of the business combination.  Additionally, SFAS No. 141R requires that acquisition-related costs be expensed as incurred.  The provisions of SFAS No. 141R will become effective for acquisitions completed on or after January 1, 2009; however, the income tax provisions of SFAS No. 141R will become effective as of that date for all acquisitions, regardless of the acquisition date.  SFAS No. 141R amends SFAS No. 109, Accounting for Income Taxes, to require the acquirer to recognize changes in the amount of its deferred tax benefits recognizable due to a business combination either in income from continuing operations in the period of the combination or directly in contributed capital, depending on the circumstances.  SFAS No. 141R further amends SFAS No. 109 and FIN 48, Accounting for Uncertainty in Income Taxes, to require, subsequent to a prescribed measurement period, changes to acquisition-date income tax uncertainties to be reported in income from continuing operations and changes to acquisition-date acquiree deferred tax benefits to be reported in income from continuing operations or directly in contributed capital, depending on the circumstances.

In December 2007, the FASB issued SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements—An Amendment of ARB No. 51.  SFAS No. 160 states that accounting and reporting for minority interests will be recharacterized as non-controlling interests and classified as a component of equity.  Additionally, SFAS No. 160 establishes reporting requirements that provide sufficient disclosures which clearly identify and distinguish between the interests of the parent and the interests of the non-controlling owners.  SFAS No. 160 is effective as of the beginning of an entity’s first fiscal year beginning after December 15, 2008.  The Partnership is evaluating the impact that SFAS No. 160 will have, if any, on its financial statements and related disclosures when adopted in 2009.

In March 2008, the FASB issued SFAS No. 161, Disclosures about Derivative Instruments and Hedging Activities—An Amendment of FASB Statement No. 133, which changes the disclosure requirements for derivative instruments and hedging activities.  Enhanced disclosures are required to provide information about (a) how and why an entity uses derivative instruments, (b) how derivative instruments and related hedged items are accounted for under Statement 133 and its related interpretations and (c) how derivative instruments and related hedged items affect an entity’s financial position, financial performance and cash flows.  SFAS No. 161 is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008, with early application encouraged.  The Partnership is currently evaluating the impact that SFAS No. 161 will have, if any, on its financial statements and related disclosures when adopted in 2009.

In January 2009, the SEC published its final rule, Modernization of Oil and Gas Reporting, which modifies the SEC’s reporting and disclosure rules for oil and natural gas reserves.  The most notable changes of the final rule include the replacement of the single day period-end pricing for valuing oil and natural gas reserves to a 12-month average of the first day of the month price for each month within the reporting period.  The final rule also permits voluntary disclosure of probable and possible reserves, a disclosure previously prohibited by SEC rules.  The revised reporting and disclosure requirements are effective for the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2009.  Early adoption is not permitted.  The Partnership is evaluating the impact that adoption of this final rule will have on the Partnership’s financial statements, related disclosure and management’s discussion and analysis.

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Notes to Financial Statements

Reclassfications

Certain amounts in the prior period have been reclassified to conform with the current year classifications with no effect on previously reported net income or Partners’ equity during the period May 22, 2007 (date of inception) to December 31, 2007.

Note 3 - Transactions with Managing General Partner and Affiliates

The Managing General Partner transacts business on behalf of the Partnership.  Revenues and other cash inflows received on behalf of the Partnership are distributed to the Partners net of (after deducting) corresponding operating costs and other cash outflows incurred on behalf of the Partnership.  Undistributed oil and natural gas revenues are recorded on the balance sheet under the caption “Accounts receivable.”  The portion due from third parties amounted to $2,801,449 and $734,881 as of December 31, 2008 and 2007, respectively, with the remaining portion due from the Managing General Partner.  The fair value of the Partnership’s portion of unexpired derivative instruments is recorded on the balance sheet under the caption “Due from the Managing General Partner–derivatives” in the case of net unrealized gains or “Due to Managing General Partner–derivatives, net” in the case of net unrealized losses.  Realized gains or losses that have not yet been distributed to the Partnership are included in the balance sheet captions “Due from (to) Managing General Partner-other, net”, respectively.  Undistributed realized gains amounted to $5,028,480 as of December 31, 2008.  The Partnership recorded no realized gains (losses) for the period May 22, 2007 (date of inception) to December 31, 2007.  All other unsettled transactions between the Partnership and the Managing General Partner are recorded net on the balance sheet under the caption “Due to or from Managing General Partner - other, net.”  At December 31, 2008, "Due from (to) Managing General Partner - other, net" consisted of undistributed realized gains on derivatives of $5,028,480, net of unsettled liabilities totaling $1,999,344.  At December 31, 2007, "Due from (to) Managing General Partner - other, net" consisted of unsettled liabilities totaling $29,995.

The following table presents transactions with the Managing General Partner and its affiliates for year ended December 31, 2008 and the period from May 22, 2007 (date of inception) to December 31, 2007.

	Year Ended December 31, 2008		Period May 22, 2007 (date of inception) Through December 31, 2007
Capital contribution (1)	$	-	$	38,659,808
Syndication costs (2)		-		9,070,450
Management fee (3)		-		1,341,043
Drilling advances to Managing General Partner (4)(5)		-		67,045,826
Purchases of leases (4)(5)				389,150
Drilling costs (4)(5)				44,553,454
Drilling compensation (4)(5)				5,666,769
Well charges (5)		485,593
Gas marketing, supplies and equipment (6)		2,161,871		-
Gathering, compression and processing fees (7)		593,022		121,897
Direct costs - general and administrative (8)		607,289		-
Distributions (9)		10,581,194		-

1. The Managing General Partner contributed capital of $38.7 million to the Partnership as of December 31, 2007 in exchange for the 37% interest in the Partnership.

2. The Partnership reimbursed PDC Securities Inc., a wholly owned subsidiary of the Managing General Partner, for dealer manager commissions, due diligence costs, marketing and support expenses and wholesaling fees as outlined in the Partnership Agreement.  Costs incurred by PDC relating to start-up and organization charges, for which no reimbursement was made, were insignificant.

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Notes to Financial Statements

3. In accordance with the Partnership Agreement, a one-time management fee equal to 1½% of Investor Partners’ subscriptions was charged to the Partnership by the Managing General Partner.  This fee was paid by the Partnership to the Managing General Partner upon funding the Partnership.  The fee is treated as a period cost in the year of formation and is non-refundable.

4. The Partnership entered into a Drilling and Operating Agreement with the Managing General Partner to drill and complete the Partnership's wells at cost plus the Managing General Partner's drilling compensation of 12.6% of the total well cost. Total well cost includes the cost of leases acquired from the Managing General Partner and drilling costs.  The drilling compensation percentage of 12.6% was determined prior to formation of the Partnership and disclosed in the offering documents.  The drilling compensation amounts were calculated using this rate in accordance with the offering documents.  The Managing General Partner sells undeveloped prospects (leases) to the Partnership to drill the Partnership’s wells.  Leases are sold to the Partnership at the lower of the Managing General Partner’s cost to purchase the lease or the leases’ fair market value.   Drilling costs include an overhead charge to the Managing General Partner of 1½% of each well’s Authority for Expenditure.

If the Managing General Partner provides other services in the drilling and completion of the wells, it charges those services at its cost, not to exceed competitive rates charged in its area of operation by unaffiliated persons and these charges are included in the total well cost when determining the Managing General Partner's drilling compensation.

Cost, when used with respect to services, generally means the reasonable, necessary, and actual expense incurred in providing the services, determined in accordance with generally accepted accounting principles.  The cost of the well also includes all ordinary costs of drilling, testing and completing the well.

The well costs charged to the Partnership are proportionately reduced to the extent the Partnership acquires less than 100% of the working interest in a prospect.  The amount of compensation that the Managing General Partner could earn as a result of these arrangements depends on the degree to which it provides services for the wells, and the number and type of wells that are drilled.  If the Managing General Partner supplies other goods and services to the Partnership, it is required to supply them at cost, and they will be included in the total well costs for determining the Managing General Partner's and the investor partners' contributions, the division of oil and natural gas revenues, and calculation of the Managing General Partner's drilling compensation.

All drilling activities performed by the Managing General Partner on behalf of the Partnership in 2007 was paid directly by the Partnership. The following table presents the usage in 2008 of the drilling advances by the Partnership in the amount of $67,045,826 made to the Managing General Partner in 2007 based on the drilling activities of the Managing General Partner:

	Year Ended December 31, 2008
Purchase of leases	$	1,463,240
Drilling costs		57,440,937
Drilling compensation		7,421,925
Drilling advances to Managing General Partner		(66,326,102	)

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Notes to Financial Statements

5. Under the Drilling and Operating Agreement, the Managing General Partner, as operator of the wells, receives the following from the Partnership when the wells begin producing:

· reimbursement at actual cost for all direct expenses incurred on behalf of the Partnership;

· monthly well operating charges for operating and maintaining the wells during producing operations at a competitive rate; and

· monthly administration charge for Partnership activities.

During the production phase of operations, the Managing General Partner as operator receives a monthly fee for each producing well based upon competitive industry rates for operations and field supervision and $100 for Partnership-related general and administrative expenses that include accounting, engineering and management.  The Managing General Partner as operator bills non-routine operations and administration costs to the Partnership at its cost.  The Managing General Partner may not benefit by inter-positioning itself between the Partnership and the actual provider of operator services.  In no event is any consideration received for operator services duplicative of any consideration or reimbursement received under the Agreement.

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

· well tending, routine maintenance, and adjustment;

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

· preparing production related reports to the Partnership and government agencies.

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

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

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

· brine disposal; and

· rebuilding of access roads.

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

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

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

8. The Managing General Partner is reimbursed by the Partnership for all direct costs expended by them on the Partnership’s behalf for administrative and professional fees, such as legal expenses, audit fees and engineering fees for reserve reports.

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Notes to Financial Statements

9. The Agreement provides for the allocation of cash distributions 63% to the Investor Partners and 37% to the Managing General Partner.  For additional disclosure regarding the allocation of cash distributions, refer to Note 6, Partners’ Equity and Cash Distributions.

Additionally, refer to Note 4, Derivative Financial Instruments for derivative transactions between the Partnership and the Managing General Partner.

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 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 leases is acceptable for purposes of the Partnership.

Note 4 - Derivative Financial Instruments

The Partnership is exposed to the effect of market fluctuations in the prices of oil and natural gas as they relate to oil and natural gas sales.  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.  Partnership policy prohibits the use of oil and natural gas derivative instruments for speculative purposes.

Concentration of Credit Risk. A significant portion of the Partnership’s liquidity is concentrated in derivative instruments that enables the Partnership to manage a portion of its exposure to price volatility from producing oil and natural gas.  These arrangements expose the Partnership to credit risk.  These contracts consist of fixed-price swaps, basis swaps and collars.  Credit risk is the failure of the counterparty to perform under the terms of the derivative contract.  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 seeks to diversify counterparty exposure by entering into transactions with high-quality counterparties including two investment grade financial institutions.  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 this evaluation, the Managing General Partner has determined that the impact of the nonperformance of counterparties on the fair value of the Partnership’s derivative instruments is insignificant.  The Managing General Partner has experienced no counterparty defaults during the year ended December 31, 2008 or the period from May 22, 2007 (date of inception) to December 31, 2007 and no valuation allowance has been recorded by the Partnership.  However, the recent disruption in the credit market has had a significant impact on a number of financial institutions.  The Managing General Partner believes that its procedures are sufficient and customary, but no amount of analysis can guarantee performance in these uncertain times.

Risk Management 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 instruments. 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 Colorado Interstate Gas Index, or CIG, based contracts for Colorado gas production and New York Mercantile Exchange, or NYMEX, based contracts for Colorado oil production.  In addition to the fixed-price 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.  Through October 31, 2007, the Partnership’s natural gas derivative instruments were comprised of natural gas floors and collars while its oil derivative instruments were comprised of oil “floors.”

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Notes to Financial Statements

· For swap instruments, PDC, as Managing General Partner, receives a fixed price for the hedged commodity and pays a floating market price to the counterparty.  The fixed-price payment and the floating-price payment are netted, resulting in a net amount due to or from the counterparty.

· Basis protection swaps are arrangements that guarantee a price differential for natural gas valued at a specified pricing point, or hub.  For 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.

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

· Floors contained a floor price (put) whereby PDC, as Managing General Partner, received from the counterparty the floor price if the commodity market price fell below the floor strike price, but received no payment when the commodity market price exceeded 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 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.

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Notes to Financial Statements

Valuation of a contract’s fair value is performed internally.  While the Managing General Partner uses common industry practices to develop the Partnership’s valuation techniques, changes in pricing methodologies or the underlying assumptions could result in different fair values.  At December 31, 2008 and 2007, the Partnership had the following asset and liability positions related to its open commodity based derivative instruments for a portion of the Partnership’s oil and natural gas production.

	December 31,
	2008			2007
Derivative net assets (liabilities)
Oil and gas sales activities:
Fixed-price natural gas swaps	$	4,422,716		$	-
Natural gas collars		4,092,030			-
Natural gas basis protection swaps		(421,364	)		-
Fixed-price oil swaps		7,539,350			(319,365	)
Estimated net fair value of derivative instruments	$	15,632,732		$	(319,365	)

At December 31, 2008 and 2007, the maximum term for the derivative positions listed above is 60 months and 12 months, respectively.

The following table identifies the fair value of commodity based derivatives as classified in the Partnership’s balance sheets:

	December 31,
	2008		2007
Classification in the Balance Sheets
Fair value of current assets
Due from Managing General Partner-derivatives	$	12,096,394	$	-
Fair value of other assets-long term
Due from Managing General Partner-derivatives		3,536,338		-
		15,632,732		-
Fair value of current liabilities
Due to Managing General Partner-derivatives		-		319,365
Net fair value of commodity based derivatives- asset (liability)	$	15,632,732	$	(319,365	)

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Notes to Financial Statements

The following table identifies the changes in the fair value of commodity based derivatives as reflected in the Partnership’s statements of operations.

	Year Ended December 31, 2008			Period May 22, 2007 (date of inception) Through December 31, 2007
Realized gains (losses)
Oil	$	(924,778	)	$	-
Gas		3,090,653			-
Total realized gain, net		2,165,875			-
Unrealized gain (loss), net		15,952,097			(319,365	)
Oil and gas price risk management gain (loss), net	$	18,117,972		$	(319,365	)

Note 5 – Fair Value of Financial Instruments

Derivative Financial Instruments

Determination of fair value.  The Partnership measures fair value based upon quoted market prices, where available.  The Managing General Partner’s valuation determination includes: (1) identification of the inputs to the fair value methodology through the review of counterparty statements and other supporting documentation, (2) determination of the validity of the source of the inputs, (3) corroboration of the original source of inputs through access to multiple quotes, if available, or other information and (4) monitoring changes in valuation methods and assumptions.  The methods described above may produce a fair value calculation that may not be indicative of future fair values.  The Managing General Partner’s valuation determination also gives consideration to the nonperformance risk on Partnership liabilities in addition to nonperformance risk on PDC’s own business interests and liabilities, as well as the credit standing of derivative instrument counterparties.  The Managing General Partner primarily uses two investment grade financial institutions as counterparties to its derivative contracts.  The Managing General Partner has evaluated the credit risk of the Partnership’s derivative assets from counterparties 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.  Thus, no valuation allowance has been recorded by the Partnership as of December 31, 2008.  Furthermore, while the Managing General Partner believes these valuation methods are appropriate and consistent with that used by other market participants, the use of different methodologies, or assumptions, to determine the fair value of certain financial instruments could result in a different estimate of fair value.

Valuation hierarchy.  SFAS 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.  The three levels of inputs that may be used to measure fair value are defined as:

Level 1 – Quoted prices (unadjusted) in active markets for identical assets or liabilities.

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

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Notes to Financial Statements

Level 3 – Unobservable inputs for the asset or liability, including situations where there is little, if any, market activity for the asset or liability.  Instruments included in Level 3 consist of Partnership commodity derivatives for CIG based natural gas swaps, NYMEX based oil swaps, natural gas fixed-price floor and ceiling price collars and natural gas basis protection swaps.

SFAS No. 157 requires fair value measurements to be separately disclosed by level within the fair value hierarchy and requires a separate reconciliation of fair value measurements categorized as Level 3.  The following table presents for each hierarchy level, the Partnership’s assets and liabilities including both current and non-current portions, measured at fair value on a recurring basis as of December 31, 2008:

	Level 1		Level 2		Level 3		Total
Assets:
Commodity based derivatives	$	-	$	-	$	15,632,732	$	15,632,732
Net fair value of commodity based derivatives	$	-	$	-	$	15,632,732	$	15,632,732

The table below sets forth a reconciliation of our Level 3 fair value measurements in which derivative asset and liability fair values are presented on a “net” basis.  See Note 4 for additional disclosure related to the Partnership’s derivative financial instruments.

	Year Ended December 31, 2008
Fair value, net asset (liability), beginning of period	$	(319,365	)
Realized and unrealized gains (losses) included in
Oil and gas price risk management gain (loss), net		18,117,972
Purchases, sales, issuances and settlements, net		(2,165,875	)
Fair value, net asset (liability), end of period	$	15,632,732

Non-Derivative Financial Instruments

The carrying values of the financial instruments comprising “Cash and cash equivalents,” “Accounts receivable,” “Accounts payable” and “Due to (from) Managing General Partner-other ” approximate fair value due to the short-term maturities of these instruments.

Note 6 - Partners’ Equity and Cash Distributions

Partners’ Equity

A unit represents the individual interest of an individual investor partner in the Partnership.  No public market exists or will develop for the units.  While units of the Partnership are transferable, assignability of the units is limited, requiring the consent of the Managing General Partner.

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Notes to Financial Statements

Allocation of Partners’ Interest

The table below summarizes the participation of the Investor Partners and the Managing General Partner in the revenues and costs of the Partnership, taking into account the Managing General Partner's capital contribution, which was equal to 43.24% of the Investor Partners’ initial capital.

	Investor Partners			Managing General Partner
Partnership Revenue:
Oil and gas sales		63	%		37	%
Oil and gas price risk management gain (loss)		63	%		37	%
Sale of productive properties		63	%		37	%
Sale of equipment		63	%		37	%
Sale of undeveloped leases		63	%		37	%
Interest income		63	%		37	%
Partnership Costs:
Administrative costs (a)		0	%		100	%
Broker-dealer commissions and expenses/syndication costs (a)		100	%		0	%
Cost of oil and gas properties: (b)
Undeveloped lease costs		0	%		100	%
Tangible well costs		0	%		100	%
Intangible drilling costs		100	%		0	%
Managing General Partner's drilling compensation		100	%		0	%
Other costs and expenses:
Management fee (c)		100	%		0	%
Production and operating costs (d)		63	%		37	%
Depreciation, depletion and amortization expense		63	%		37	%
Accretion of asset retirement obligations		63	%		37	%
Direct costs (e)		63	%		37	%

(a) The Managing General Partner paid all legal, accounting, printing, and filing fees associated with the organization of the Partnership and the offering of units and is allocated 100% of these costs.  The Investor Partners paid all dealer manager commissions, discounts, and due diligence reimbursements and are allocated 100% of these costs.

(b) The allocations are for tax reporting purposes and do not impact cash distributions.

(c) Represents a one-time fee paid to the Managing General Partner on the day the Partnership was funded equal to 1-1/2% of total investor subscriptions.

(d) Represents operating costs incurred after the completion of productive wells, including monthly per-well charges paid to the Managing General Partner.

(e) The Managing General Partner receives monthly reimbursement from the Partnership for direct costs – general and administrative costs incurred by the Managing General Partner on behalf of the Partnership.

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Notes to Financial Statements

The following table presents the allocation of net income (loss) to the Investor Partners and the Managing General Partner for each of the periods presented.

	Year Ended December 31, 2008		Period May 22, 2007 (date of inception) Through December 31, 2007
Net Income	$	38,651,613	$	232,762
Plus Management fee		-		1,341,043
Net Income allocable to the partners	$	38,651,613	$	1,573,805
Net Income allocable to Investor Partners:
63% of Net Income allocable to the Investor Partners	$	24,350,516	$	991,497
100% of Management Fee		-		(1,341,043	)
Net income (loss) allocable to Investor Partners		24,350,516		(349,546	)
Net Income allocable to Managing General Partner
37% of Net Income allocable to the Managing General Partner		14,301,097		582,308
Net Income allacoble to Managing General Partner		14,301,097		582,308
Net Income	$	38,651,613	$	232,762

Unit Repurchase Provisions

Investor Partners may request that the Managing General Partner repurchase units at any time beginning with the third anniversary of the first cash distribution of the Partnership.  The Partnership initiated monthly cash distributions to Investor Partners in May 2008.  The repurchase price is set at a minimum of four times the most recent twelve months of cash distributions from production.  The Managing General Partner is obligated to purchase, in any calendar year, Investor Partner units aggregating to 10% of the initial subscriptions if requested by an individual investor partner, subject to its financial ability to do so and upon receipt of opinions of counsel that the repurchase will not cause the Partnership to be treated as a “publically traded partnership” or result in the termination of the Partnership for federal income tax purposes.  Repurchase requests are fulfilled by the Managing General Partner on a first-come, first-served basis.

In addition to the above repurchase program, individual investor partners periodically offer and PDC repurchases, units on a negotiated basis before the third anniversary of the date of the first cash distribution.  As of December 31, 2008, the Managing General Partner has not made any negotiated-basis unit repurchases from Investor Partners.

Cash Distributions

The Agreement requires the Managing General Partner to distribute cash available for distribution not less frequently than quarterly.  The Managing General Partner will determine and distribute, if funds are available for distribution, cash on a monthly basis.  The Managing General Partner will make cash distributions of 63% to the Investor Partners and 37% to the Managing General Partner throughout the term of the Partnership.  The Partnership has paid cash distributions each month since May 2008.  Distributions for the year ended December 31, 2008 were $28,346,463.

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Notes to Financial Statements

Note 7 - Oil and Gas Properties

The Partnership is engaged solely in oil and natural gas activities, all of which are located in the continental United States.  Drilling operations began upon funding on August 31, 2007 with payments made for all planned drilling and completion costs for the Partnership in 2007.  Costs capitalized for these activities at December 31, 2008 and 2007 are as follows:

	Year Ended December 31, 2008		Year Ended December 31, 2007
Leasehold costs	$	2,085,789	$	438,183
Development costs		115,239,346		9,935,211
Oil and gas properties, successful efforts method		117,325,135		10,373,394
Wells in progress		-		40,286,695
Drilling advances to Managing General Partner		719,724		67,045,826
Oil and gas properties at cost	$	118,044,859	$	117,705,915

Wells in progress represents expenditures incurred for wells for which drilling and/or completion activities have commenced but had not been completed.  “Drilling advances to Managing General Partner” represent prepayments to the Managing General Partner for the development of oil and gas properties for which drilling has not commenced.  Development costs include the Partnership’s asset retirement obligations.

Note 8 - Asset Retirement Obligations

Changes in the carrying amount of asset retirement obligations associated with the Partnership’s working interest in oil and natural gas properties are as follows:

	2008		2007
Balance at beginning of period	$	55,643	$	-
New liabilities incurred		338,944		54,716
Accretion expense		21,523		927
Balance at end of period	$	416,110	$	55,643

If the fair value of the estimated asset retirement obligation changes, an adjustment is recorded to both the asset retirement obligation and the asset retirement cost.  New liabilities incurred are due to drilling activity which occurred throughout 2008 and 2007.

Note 9 - Commitments and Contingencies

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 Partnership’s Managing General Partner in the District Court, Weld County, Colorado alleging that the Managing General Partner underpaid royalties on gas produced from wells operated by the Managing General Partner in the State of Colorado (the "Droegemueller Action").  The plaintiff seeks declaratory relief and to recover an unspecified amount of compensation for underpayment of royalties paid by the Managing General Partner pursuant to leases.  The Managing General Partner moved the case to Federal Court on June 28, 2007, and on July 10, 2007, the Managing General Partner filed its answer and affirmative defenses.

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Notes to Financial Statements

A second similar Colorado class action suit was filed against the Managing General Partner in the U.S. District Court for the District of Colorado on December 3, 2007 by Ted Amsbaugh, et al.  On December 31, 2007, the plaintiffs in this second action filed a motion to consolidate the case with the Droegemueller action above.  On January 28, 2008, the Court granted the plaintiff’s motion to consolidate the action with the Droegemueller Action.

The court approved a stay in proceedings until September 22, 2008 while the parties pursued mediation of the matter.  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 75 wells in the Wattenberg field.  On October 10, 2008, the court issued preliminary approval of a settlement agreement.

The portion of the proposed settlement related to the Partnership’s wells for all periods through December 31, 2008 is $78,105.  This amount, plus legal costs of $7,863, were recorded to fully accrue for the settlement through December 31, 2008.  In November 2008, the Managing General Partner paid into an escrow account, on behalf of the Partnership, amounts due under the settlement.  These amounts will be deducted from future Partnership distributions.  Notice of the settlement was mailed to members of the class action suit in the fourth quarter 2008 and the final settlement approval hearing is expected on April 7, 2009.

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Supplemental Oil and Gas Information - Unaudited

Costs Incurred in Oil and Gas Property Development Activities

Costs incurred in oil and gas property development are presented below:

	Year Ended December 31, 2008			Period May 22, 2007 (date of inception) Through December 31, 2007
Leasehold costs	$	1,647,606		$	438,183
Developmental costs		(1,308,662	)		117,267,732
Total costs incurred	$	338,944		$	117,705,915

Development costs include costs incurred to gain access to and prepare development well locations for drilling, to drill and equip development wells, recompletions and to provide facilities to extract, treat, gather and store oil and gas.  Development costs also include estimated asset retirement costs as discussed in Note 8.

Net Proved Oil and Gas Reserves

Our proved oil and natural gas reserves have been estimated by independent petroleum engineers. Ryder Scott Company, L.P. prepared Partnership reserve reports estimating proved reserves at December 31, 2008 and 2007. These reserve estimates have been prepared in compliance with professional standards and the reserves definitions prescribed by the SEC.

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 following Partnership reserve estimates present the estimate of the proved gas and oil reserves and net cash flows of the Partnership’s Properties which are United States properties.  The Managing General Partner’s management emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries are more imprecise than those of producing gas and oil properties.  Accordingly, the estimates are expected to change as future information becomes available.

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Supplemental Oil and Gas Information - Unaudited

Below are the net quantities of net proved reserves of the Partnership’s Properties.

	Oil (MBbl)
	2008			2007
Proved reserves:
Beginning of year		361			-
Extensions, discoveries, and improved recovery, less related cost		1,238			374
Revisions of previous estimates		(38	)		-
Production		(235	)		(13	)
End of Year		1,326			361

	Gas (MMcf)
	2008			2007
Proved reserves:
Beginning of year		1,207			-
Extensions, discoveries, and improved recovery, less related cost		35,624			1,231
Revisions of previous estimates		(84	)		-
Production		(3,976	)		(24	)
End of Year		32,771			1,207

	December 31,
Proved Developed Reserves	2008		2007
Oil (MBbl)		642		191
Natural Gas (MMcf)		29,270		600

Definitions used throughout Supplemental Oil and Gas Information-Unaudited

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

· MBbl – One thousand barrels

· Mcf – One thousand cubic feet

· MMcf – One million cubic feet

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Supplemental Oil and Gas Information - Unaudited

Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Oil and Gas Reserves

Summarized in the following table is information with respect to the standardized measure of discounted future net cash flows relating to proved oil and gas reserves.  Future cash inflows are computed by applying year-end prices of oil and gas relating to our proved reserves to the year-end quantities of those reserves. Future production, development, site restoration and abandonment costs are derived based on current costs, including production – related taxes, primarily severance and property, assuming continuation of existing economic conditions.  Future development costs include the development costs related to recompletions of wells drilled in the Codell formation, as described in Item 1, Business—Plan of Operations.  Since Partnership taxable income is reported in the separate tax returns of individual investor partners, no future estimated income taxes are computed and presented herein.

	December 31,
	2008			2007
	(in thousands)
Future estimated revenues	$	204,486		$	38,137
Future estimated production costs		(66,425	)		(6,114	)
Future estimated development costs		(16,779	)		(2,506	)
Future net cash flows		121,282			29,517
10% annual discount for estimated timing of cash flows		(53,493	)		(14,741	)
Standardized measure of discounted future estimated net cash flows	$	67,789		$	14,776

The following table summarizes the principal sources of change in the standardized measure of discounted future estimated net cash flows for the years ended December 31, 2008 and 2007:

	December 31,
	2008			2007
	(in thousands)
Sales of oil and gas production, net of production costs	$	(36,623	)	$	(1,038	)
Net changes in prices and production costs		(7,679	)		521
Extensions, discoveries, and improved recovery, less related cost		93,231			14,776
Revisions of previous quantity estimates		(754	)		-
Accretion of discount		951			-
Timing and other		3,887			517
Net change	$	53,013		$	14,776

The data presented should not be viewed as representing the expected cash flow from, or current value of, existing proved reserves since the computations are based on a large number of estimates and arbitrary assumptions.  Reserve quantities cannot be measured with precision and their estimation requires many judgmental determinations and frequent revisions.  The required projection of production and related expenditures over time requires further estimates with respect to pipeline availability, rates of demand and governmental control. Actual future prices and costs are likely to be substantially different from the current prices and costs utilized in the computation of reported amounts.  Any analysis or evaluation of the reported amounts should give specific recognition to the computational methods utilized and the limitations inherent therein.

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Supplemental Oil and Gas Information - Unaudited

The estimated present value of future cash flows relating to proved reserves is extremely sensitive to prices used at any measurement period.  The average December 31 price used for each commodity at December 31, 2008 and 2007 is presented below.

	Year End Price
As of December 31,	Oil (Bbls)		Gas (Mcf)
2008	$	38.12	$	4.70
2007		80.22		8.26

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