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


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





Commission File Number  000-51959





Rockies Region Private Limited Partnership


(Exact name of registrant as specified in its charter)





West Virginia
20-3890540(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 ClassLimited Partnership Interests





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





Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  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     o
Accelerated filer     oNon-accelerated filer     o
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 o  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 1,786.78 units of limited partnership interest and no units of general partnership interest outstanding.













ROCKIES REGION PRIVATE LIMITED PARTNERSHIP


INDEX TO REPORT ON FORM 10-K





PagePART IExplanatory Note
1Item 1
Business
2Item 1A
Risk Factors
12Item 1B
Unresolved Staff Comments
20Item 2
Properties
20Item 3
Legal Proceedings
22Item 4
Submission of Matters to a Vote of Security Holders
22PART IIItem 5
Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
22Item 6
Selected Financial Data
24Item 7
Management’s Discussion and Analysis of Financial Condition and Results of Operations
24Item 7A
Quantitative and Qualitative Disclosure About Market Risk
39Item 8
Financial Statements and Supplementary Data
41Item 9
Changes in and Disagreements With Accountants on Accounting and Financial Disclosure
41Item 9A(T)
Controls and Procedures
41Item 9B
Other Information
44PART IIIItem 10
Directors, Executive Officers and Corporate Governance
44Item 11
Executive Compensation
47Item 12
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
48Item 13
Certain Relationships and Related Transactions, and Director Independence
48Item 14
Principal Accountant Fees and Services
49PART IVItem 15
Exhibits, Financial Statement Schedules
50Signatures
53Financial Statements
F-1





Index





PART I








Explanatory Note





Rockies Region Private Limited Partnership (the “Partnership” or the “Registrant”), which was formed on December 6, 2005, filed a Comprehensive Annual Report on Form 10-K for the period December 6, 2005 (date of inception) to December 31, 2005 and the years ended December 31, 2006 and 2007 on March 8, 2009. The
report included condensed quarterly unaudited financial statements for each of the applicable quarters in 2005, 2006 and 2007.





This annual report on Form 10-K for the years ended December 31, 2007 and 2008 is the first periodic report the Partnership has filed with the Securities and Exchange Commission (“SEC”) since the filing of the previously mentioned Form 10-K for 2005-2007. The financial information presented in this Annual Report on Form 10-K
includes audited financial statements for the years ended December 31, 2008 and 2007 as well as unaudited condensed financial information for each applicable interim period in 2007 and 2008.





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 Private 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 and/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.





- 1 -
 Index





Item1.
Business





General





The Partnership was organized as a limited partnership on December 6, 2005 (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 Partnership units on December 30, 2005, the Partnership was funded and commenced its business operations. The Partnership was funded with initial contributions of $35,735,509 from 952 limited and additional general partners (collectively, the “Investor Partners”) and a cash contribution of $11,231,670 from the Managing General Partner.  After payment of syndication costs of $3,583,551 and a one-time management fee
to the Managing General Partner of $536,033, the Partnership had available cash of $42,847,595 to commence Partnership activities.  The Partnership owns natural gas and oil wells located in Colorado and from the wells, it produces and sells gas and oil.





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





Drilling Activities





The Partnership commenced drilling activities immediately following funding on December 30, 2005.  As of December 31, 2008, a total of 49 gross wells (48.6 net) had been drilled.  The Partnership’s 48 gross developmental wells (47.9 net) were drilled in Colorado.  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.  One exploratory well (.7 net) was drilled in Wyoming.  An exploratory well is one which is drilled in an area where there has been no oil or natural gas production, or a well which is drilled to a previously untested or non-producing zone in an area where there are wells producing from other formations.  There were no drilling activities for the years ended December 31,
2008 and 2007.





The Partnership drilled 47 productive developmental wells (46.9 net) and one developmental well that was evaluated to be commercially unproductive and was declared a dry hole.  The one exploratory well (.7 net) drilled was determined to be commercially unproductive and therefore declared to be an exploratory dry hole.  See
Item 2, Propertiesfor disclosure regarding the Partnership’s wells.





The 49 wells discussed above are the only wells to be drilled by the Partnership since all of the funds raised in the Partnership offering have been utilized.  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.





Business Segments





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





Plan of Operations





With regard to the Partnership’s developmental wells drilled in Colorado, 38 wells were drilled to the Codell formation in the Wattenberg Field (one of which was determined to be a dry hole) and the 10 remaining wells were drilled in the Grand Valley Field. The partnership drilled one exploratory well in Wyoming which was determined
to be a dry hole.





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.





- 2 -
 Index





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.





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, the majority of the wells in the Wattenberg Field 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.





Wyoming.  The Red Desert Basin, located in southwestern Wyoming, was the third target area and successful wells drilled in this area were expected to produce primarily natural gas with small associated amounts of oil.  The deepest potential targets are
part of the Mesaverde formation and the Lewis, Fox Hills and Lance formations with shallower Tertiary aged Fort Union and Wasatch Sands, secondary targets.  The single well drilled by the Partnership in Wyoming was to a depth of 12,525 feet and was determined to be a dry hole.





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.  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 -
 Index





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 a minor 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.





PriceRisk 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 84% of its expected oil production and 81% of its expected natural gas production
for 2009.





- 4 -
 Index





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.  “Floors” contain a floor price (put) whereby PDC, as Managing General Partner, receives from the counterparty, the floor price if the commodity market price falls below the floor strike
price, but receives no payment when the commodity market price exceeds the floor price.  For “swap” instruments, 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 fixed
call strike price, PDC, as Managing General Partner, receives the market price from the purchaser and pays the difference between the call strike price and the market price to the counterparty.  If the market price falls below the fixed put strike price, PDC, as Managing General Partner, receives the market price from the purchaser and receives the difference between the put strike price and market price from the counterparty. If the market price is between the call and put 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.





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 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.





- 5 -
 Index





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.





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 47 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.





- 6 -
 Index





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


Year Ended December 31, 2007ProductionOil (Bbls)


45,907



76,039Natural gas(Mcf)


874,353



1,212,711Natural gas equivalent (Mcfe)


1,149,795



1,668,945Oil and Gas SalesOil sales

$
3,995,407


$
4,345,751Gas sales


5,890,379



6,005,222Total oil and gas sales

$
9,885,786


$
10,350,973Realized Gain (Loss) on Derivatives, netOil derivatives - realized loss

$
(142,973
)

$
(24,151
)Natural gas derivatives - realized gain


257,789



529,222Total realized gain on derivatives, net

$
114,816


$
505,071Average Sales PriceOil (per Bbl)

$
87.03


$
57.15Natural gas(per Mcf)


6.74



4.95Natural gas equivalent (per Mcfe)


8.60



6.20Average Sales Price (including realized gain (loss) on derivatives)Oil (per Bbl)


83.92



56.83Natural gas (per Mcf)


7.03



5.39Natural gas equivalent (per Mcfe)


8.70



6.50Average Production Cost (Lifting Cost) (per Mcfe)

$
2.08


$
1.29





Definitions used throughout Item 1, Business:


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


·
MBbl – One thousand barrels


·
Mcf – One thousand cubic feet


·
Mcfe – One thousand cubic feet of natural gas equivalents


·
MMcf – One million cubic feet


·
MMcfe – One million cubic feet of natural 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 Condition and Results of Operations - Production and Operating Costs.





- 7 -
 Index





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 engineer’s 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, 2008Oil (MBbl)


Gas (MMcf)


Total(MMcfe)Proved developed


188



7,099



8,227Proved undeveloped


450



2,419



5,119Total Proved


638



9,518



13,346Proved Developed


Proved Undeveloped


Total ProvedEstimated future net cash flows (in thousands)

$
22,223


$
14,980


$
37,203Standardized measure of discounted future net cash flows(in thousands)


13,432



4,580



18,012





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 $38.46 per barrel of oil and $4.73 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, Disclosures About Oil and Gas Producing Activities, 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.





The Partnership’s well fields are crossed by pipelines belonging to 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 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.  Beginning January 1, 2009, the Partnership began selling the majority of its crude oil to Suncor Energy Marketing, Inc. (“Suncor”).





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.





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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 industry historically has been very heavily regulated; therefore, there is no assurance that the less stringent regulatory approach recently pursued by FERC and Congress will continue.  The 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 0001350567.  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.








Item1A.
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.





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.





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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.





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 how long such low pricing shall persist.





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 Index





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 December 22, 2006.  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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 Index





·
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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 Index





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 future production based upon prices at which the Managing General Partner reasonably estimates
such products may be sold.  The Partnership has recorded no impairments since its operations commenced in December 2005.  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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 Index





The standardized measure of estimated proved reserves, in accordance with SFAS No. 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.  Based on the mediation held on May 28, 2008, and subsequent negotiations, $74,412 was accrued by the Partnership for this litigation for the year ended December 31, 2007.  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 38 wells in the Wattenberg Field.  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 approximately $111,000 which includes legal fees of approximately $8,000.  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 proposed settlement was mailed to members of the class action suit in fourth quarter 2008.  Final settlement was approved by the court at a hearing on April 7, 2009.





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 Index





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 49 wells.  Of these wells, one developmental
well and one exploratory well, have been determined to be commercially unproductive and were therefore declared to be a developmental and an exploratory dry hole, respectively.  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 recorded approximately $2,240,600 in 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 has recorded no impairment charges.  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 December 22, 2006.  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.





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 Index





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





A substantial part of our natural gas and oil production is located in the Rocky Mountain Region, making it vulnerable to risks associated with operating in a single major geographic area.  The Partnership’s operations are focused in the Rocky Mountain Region
and its producing properties are geographically concentrated in that area.  Because Partnership operations are not geographically diversified, the success of its operations and profitability may be disproportionately exposed to the effect of any regional events, including fluctuations in prices of natural gas and oil produced from the wells in the region, natural disasters, restrictive governmental regulations, transportation capacity constraints, curtailment of production or interruption of transportation,
and any resulting delays or interruptions of production from existing or planned new wells.  During the last four months of 2008, natural gas prices in the Rocky Mountain Region fell disproportionately when compared to other markets, due in part to continuing constraints in transporting gas from producing properties in the region.  Because of the concentration of Partnership operations in the Rocky Mountain Region, and although in late 2008 the Partnership entered into a significant multi-year
basis hedge minimizing the price risk of the Partnership’s operational concentration in the Rocky Mountain region, such price decreases could have a material adverse effect on Partnership revenue, profitability 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, Rockies Region 2006 Limited Partnership, PDC 2005-A Limited Partnership and PDC 2005-B Limited Partnership have completed all required SEC filings through December
31, 2008.  Rockies Region Private Limited Partnership has filed financial statements through December 31, 2007, and (with this filing) will have completed all filings for 2008.  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 December 31, 2008.  All remaining limited partnerships sponsored by PDC which are subject to the Exchange Act have been, and
continue to be, delinquent in filing their respective periodic reports in accordance with the requirements of the Exchange Act.  Until these partnerships file their delinquent periodic reports, investors will be unable to review the financial statements of the various limited partnerships as an additional source of information they can use in their evaluation of their investment in the Partnership.  Currently the Managing General Partner has in place a compliance effort addressing the delinquent
reports of the various limited partnerships.  However, due to the amount of effort, time and financial resources required to bring the limited partnerships into compliance with Exchange Act periodic reporting requirements, the Partnership and the various limited partnerships may be unable to bring their delinquent reports current and may be unable in the future to file their required periodic reports with the Securities and Exchange Commission in a timely manner.





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 Index





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





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





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








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 49 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 sections titled Item 1, Business - Drilling ActivitiesandPlan of Operations for additional information on the Partnership’s properties.





The Partnership commenced drilling activities immediately following funding December 2005.  As of December 31, 2008 and 2007, the Partnership had drilled 47 productive developmental wells (46.9 net) and one developmental well that was evaluated to be commercially unproductive and was declared a dry hole. The 48 developmental
wells (47.9 net) are located in Colorado.  One exploratory well (.7 net) drilled in Wyoming, was determined to be commercially unproductive and therefore declared to be an exploratory dry hole.  This well was plugged and abandoned in 2008.





These 49 wells at December 31, 2008 are the only wells to be drilled by the Partnership since all of the funds raised in the Partnership offering have been utilized.  With regard to the Partnership’s developmental wells drilled in Colorado, 38 wells were drilled to the Codell formation in the Wattenberg Field (one of which
was determined to be a dry hole) and the 10 remaining wells were drilled in the Grand Valley Field. The Partnership drilled one exploratory well in Wyoming which was determined to be a dry hole. 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.





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 Index





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.





Wyoming.  The Red Desert Basin, located in southwestern Wyoming, was the third target area and successful wells drilled in this area were expected to produce primarily natural gas with small associated amounts of oil.  The deepest potential targets are part of
the Mesaverde formation and the Lewis, Fox Hills and Lance formations with shallower Tertiary aged Fort Union and Wasatch Sands, secondary targets.  The single well drilled by the Partnership in Wyoming was to a depth of 12,525 feet, fractured in multiple zones and was evaluated as commercially unproductive and therefore declared to be an exploratory dry hole.





Production





Production commenced during the first quarter of 2006, peaked during the quarter ended September 30, 2006 and has decreased as anticipated each quarter since then.  A complete disclosure of quarterly production volumes, prices and sales is presented in Item 7, Management’s
Discussion and Analysis of Financial Condition and Results of Operations in this report.





Oil and Natural Gas Reserves





All of the Partnership’s gas and oil reserves are located in the United States.  The Partnership utilized the services of an independent petroleum engineer, Ryder Scott Company, L.P., for its 2008 and 2007 reserve reports.  The independent engineer’s estimates are made using available geological and reservoir
data as well as production performance data. The estimates are prepared with respect to reserve categorization, using the definitions for proved reserves set forth in SEC Regulation S-X, Rule 4-10(a) and subsequent SEC staff interpretations and guidance. When preparing the Partnership's reserve estimates, the independent engineer did not independently verify the accuracy and completeness of information and data furnished by the Managing General Partner with respect to ownership interests, oil and gas production,
well test data, historical costs of operations and developments, product prices, or any agreements relating to current and future operations of properties and sales of production.  The Partnership's independent reserve estimates are reviewed and approved by the Managing General Partner's internal engineering staff and management.  See Supplemental Oil and Gas Information – Unaudited, Net Proved Oil and Gas Reserves for additional
information regarding the Partnership’s reserves.





Title to Properties





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





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 Index





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 March 31, 2009, the Partnership had 962 Investor Partners holding 1,786.78 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 March 31, 2009, the Managing General Partner has not repurchased any 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.





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 70% to the Investor Partners, adjusted for any units purchased by the Managing General Partner, and 30% to the Managing General Partner throughout the term of the Partnership.





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 Index





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 July 2006 and made cash distributions of $8,294,184 and $10,440,213 for the years ended December 31, 2008 and 2007, respectively.





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.





PDC divides cash distributions 70% to the Investor Partners and 30% 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, developed 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:





·
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 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.





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 Index





Item 6.
Selected Financial Data





Not applicable








Item7.
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 December 6, 2005 with initial contributions of $35,735,509 from the Investor Partners and a cash contribution of $11,231,670 from the Managing General Partner.  After payment of syndication costs of $3,583,551 and a one-time management fee to PDC of $536,033, the Partnership had available cash of
$42,847,595 to commence Partnership oil and natural gas well drilling activities.





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.  On December 30, 2005, PDC commenced drilling on behalf of the Partnership.  As of December 31, 2008, a total of 49 wells have been drilled, predominantly in Colorado.  Of the 49 wells drilled, 47 are producing and two (one an exploratory well and the other a developmental well) are dry holes.  These 49 wells are the only wells the Partnership will drill because all of the capital contributions have been utilized.  The
completed wells produce primarily natural gas, with some associated crude oil.  Sales of produced natural gas and oil commenced during the first quarter of 2006 as wells were connected to pipelines.  Production and sales increased through the third quarter of 2006 as additional wells were completed and connected to pipelines.  As expected for wells in this area, the Partnership has recognized a steady decline in quarterly production and net sales.  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 $0.1 million in net realized derivative gains, $0.9 million of which occurred in the fourth quarter.  Further, the Partnership estimates the net fair value of its derivative positions as of December 31, 2008, to be $3.2 million.





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 Index





The decline in prices during the fourth quarter of 2008 resulted in $3.6 million in unrealized gains on derivatives for the year ended December 31, 2008.  The $3.6 million in unrealized gains for the year is the fair value of the 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.





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





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





Commodity

Index

December 31, 2007


June 30, 2008


December 31, 2008


March 31, 2009Natural gas: (per MMbtu)NYMEX

$
8.12


$
12.52


$
6.62


$
5.87CIG


6.78



8.86



4.49



4.13Oil: (per Bbl)

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.





- 25 -
 Index





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 years ended December
31, 2008 and 2007.





Year Ended December 31, 2008


Year Ended December 31, 2007


Percentage 2007 to 2008Number of producing wells (end of period)


47



47



--Production:  (1)Oil (Bbl)


45,907



76,039



-40
%Natural gas (Mcf)


874,353



1,212,711



-28
%Natural gas equivalents (Mcfe)  (2)


1,149,795



1,668,945



-31
%Average Selling PriceOil (per Bbl)  (3)

$
87.03


$
57.15



52
%Natural gas (per Mcf)  (3)


6.74



4.95



36
%Natural gas equivalents (per Mcfe)  (3)


8.60



6.20



39
%Average Selling Price (including realized gain (loss), net on derivatives)Oil (per Bbl)

$
83.92


$
56.83



48
%Natural gas (per Mcf)


7.03



5.39



30
%Natural gas equivalents (per Mcfe)


8.70



6.50



34
%Average cost per McfeProduction and operating costs  (4)

$
2.08


$
1.29



61
%Depreciation, depletion and amortization


2.94



2.58



14
%Revenues:Oil and gas sales

$
9,885,786


$
10,350,973



-4
%Oil and gas price risk management, gain (loss), net


3,743,682



(899,196
)


*Total revenues

$
13,629,468


$
9,451,777



44
%Realized Gain (Loss) on Derivatives, netOil derivatives - realized loss

$
(142,973
)

$
(24,151
)


*Natural gas derivatives - realized gain


257,789



529,222



-51
%Total realized gain on derivatives, net

$
114,816


$
505,071



-77
%Operating costs and expenses:Production and operating costs

$
2,390,535


$
2,144,778



11
%Direct costs - general and administrative


432,297



101,279



*Depreciation, depletion and amortization


3,383,520



4,310,845



-22
%Exploratory dry hole cost


105,320



77,911



35
%Accretion of asset retirement obligations


17,804



16,620



7
%Total operating costs and expenses

$
6,329,476


$
6,651,433



-5
%Income from operations

$
7,299,992


$
2,800,344



161
%Interest income


46,424



101,818



-54
%Net income

$
7,346,416


$
2,902,162



153
%Cash distributions

$
8,294,184


$
10,440,213



-21
%





*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.


(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.





- 26 -
 Index





(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 natural gas equivalents


·
MMcfe – One million cubic feet of natural gas equivalents





Oil and Natural Gas Sales Activity





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





2008


2007Total

Sales(In thousands)


MMcfe


per Mcfe


Sales(In thousands)


MMcfe


per McfeJan-Mar

$
2,709



301


$
8.99


$
3,178



515


$
6.17Apr-Jun


3,483



324



10.76



2,671



444



6.01Jul-Sept


2,402



261



9.21



2,358



412



5.73Oct-Dec


1,292



264



4.90



2,144



298



7.19Total

$
9,886



1,150


$
8.60


$
10,351



1,669


$
6.20Change (year over year)


-4
%


-31
%


39
%2008


2007Oil

Sales(In thousands)


MBbl


per Bbl


Sales(In thousands)


MBbl


per BblJan-Mar

$
1,167



14


$
83.09


$
1,152



25


$
45.01Apr-Jun


1,234



11



114.01



1,013



19



54.27Jul-Sept


972



9



107.30



1,093



17



64.60Oct-Dec


623



12



52.00



1,088



15



73.19Total

$
3,996



46


$
87.03


$
4,346



76


$
57.15Change (year over year)


-8
%


-40
%


52
%2008


2007Natural Gas

Sales(In thousands)


MMcf


per Mcf


Sales(In thousands)


MMcf


per McfJan-Mar

$
1,542



217


$
7.10


$
2,026



362


$
5.60Apr-Jun


2,249



259



8.69



1,658



332



4.99Jul-Sept


1,430



206



6.93



1,265



310



4.08Oct-Dec


669



192



3.49



1,056



209



5.05Total

$
5,890



874


$
6.74


$
6,005



1,213


$
4.95Change (year over year)


-2
%


-28
%


36
%





The 4% decrease in total sales in 2008 as compared to 2007 was due to decreased total production volumes, in Mcfe or energy equivalency basis, of 31% partially offset by an increase in average sales price per Mcfe of 39%.





Decreased volumes contributed to a reduction in sales of $3.2 million partially offset by commodity price increases which amounted to $2.7 million, resulting in an overall $0.5 million decrease in oil and natural gas sales in 2008 as compared to 2007.  This change in production volumes is consistent with the historically declining
production curves for wells drilled in the Wattenberg and Piceance fields.  The year-to-year decrease in both oil and natural gas revenues of 8% and 2%, respectively, reflects the historically steeper decline in oil production volumes during the earlier portions of the production life cycle as compared to natural gas that was offset, however, by a more substantial increase in oil prices (52%) than natural gas prices (36%) during the period.





- 27 -
 Index





On a quarterly basis, decreased volumes during the quarter ended December 31, 2008, as compared to the same period in 2007, contributed to a reduction in sales of $0.3 million and reduced revenues due to commodity price decreases amounted to $0.6 million resulting in the $0.9 million decrease in oil and natural gas sales.  The
Partnership experienced a minor curtailment of producing volumes of natural gas in the Piceance Basin due to limited compression and pipeline capacity in the fourth quarter of 2008.  First quarter 2008 sales also decreased $0.4 million overall, due to volume reductions of $1.3 million that were partially offset by a $0.9 million higher commodity price effect.  Favorable oil and natural gas commodity price conditions during the second quarter 2008, contributed $1.5 million of the overall $0.8
million sales increase for the quarter, which partially offset volume reduction impacts of $0.7 million, compared to the same period in 2007.





Decreased volumes during the quarters ended March 31, 2008, June 30, 2008 and September 30, 2008 contributed to a reduction in sales of $1.3 million, $0.7 million and $0.9 million, respectively, offset by commodity prices increases amounting to $0.9 million, $1.5 million and $0.9 million, respectively, resulting in decreased oil and natural
gas sales of $0.4 million for the quarter ended March 31, 2008, and increased oil and natural gas sales of $0.8 million for the quarter ended June 30, 2008, as compared to the same quarterly period in 2007.  The sales variance for the quarter ended September 30, 2008, as compared to the same quarter in 2007 is negligible.





The Partnership expects to experience continued declines in both oil and natural gas production volumes over the wells’ life cycles until the Wattenberg wells are recompleted.





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 (per (MMbtu) compared to the New York Mercantile Exchange, or NYMEX, price (per MMbtu).





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 the Partnership’s 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 significantly curtail its production for long periods of time because of an inability to sell its production because of pipeline unavailability and believes that it will be able to sell all of its future production.





Oil pricing is also driven strongly by supply and demand relationships.  In the Rocky Mountain Region for 2008, Partnership oil sales averaged $87.03 per barrel which is below the NYMEX oil market 12-month average monthly closing prices (per Barrel) for 2008 of $104.42, due to supply competition from other Rocky Mountain oil
and Canadian oil that has driven down market prices.





- 28 -
 Index





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 (per Barrel) as high as $54.34 per barrel on March 26, 2009 and as low as $33.98 per barrel on February 12, 2009 and natural gas prices (per MMbtu) on CIG as high as $4.59 per MMbtu on January 7, 2009 and as low as $1.325 per MMbtu on April 14,
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 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 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.  During
2008, the Partnership experienced extreme volatility in oil and gas prices that resulted in extreme fluctuation in both realized and unrealized derivative positions.





The following table presents the realized and unrealized gains and losses recorded for each of the quarterly and annual periods identified:





Quarter EndedMarch 31, 2008


June 30, 2008


September 30, 2008


December 31, 2008


TotalRealized gains (losses)Oil

$
(72,794
)

$
(175,769
)

$
(126,619
)

$
232,209


$
(142,973
)Natural gas


(41,824
)


(474,076
)


151,747



621,942



257,789Total realized gain (loss), net


(114,618
)


(649,845
)


25,128



854,151



114,816Unrealized gain (loss)


(750,318
)


(2,425,933
)


4,542,308



2,262,809



3,628,866Oil and gas price risk management gain (loss), net

$
(864,936
)

$
(3,075,778
)

$
4,567,436


$
3,116,960


$
3,743,682Quarter EndedMarch 31, 2007


June 30, 2007


September 30, 2007


December 31, 2007


TotalRealized gains (losses)Oil

$
(9,851
)

$
(8,483
)

$
(2,868
)

$
(2,949
)

$
(24,151
)Natural gas


(7,808
)


134,214



264,811



138,005



529,222Total realized gain (loss), net


(17,659
)


125,731



261,943



135,056



505,071Unrealized gain (loss)


(630,131
)


195,419



(40,829
)


(928,726
)


(1,404,267
)Oil and gas price risk management gain (loss), net

$
(647,790
)

$
321,150


$
221,114


$
(793,670
)

$
(899,196
)





“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.





- 29 -
 Index





For the year ended December 31, 2008, the Partnership recorded realized gains of $0.1 million and unrealized gains of $3.6 million, resulting in a net $3.7 million gain for the year.  During the quarter ended March 31, 2008, prices increased and remained above December 31, 2007 prices resulting in a realized loss of $0.1 million
and an unrealized loss of $0.8 million for a total loss of $0.9 million.  The CIG-index monthly average of daily natural gas prices (per MMbtu) and oil prices on NYMEX (per barrel) in the second quarter 2008 remained above December 31, 2007 levels, resulting in the $0.6 million realized and $2.4 million unrealized losses for that period.  Although Rockies Region oil and natural gas prices increased during the first seven months of 2008, the Partnership experienced significant commodity price
declines during the last five months of 2008, relative to the Partnership’s current derivative positions, which resulted in significant unrealized derivative gains for the year and for the quarters ended September 30 and December 31.  Monthly averages of daily natural gas prices for the months August through December declined in August to $5.45 and retrenched further to a low during October of $2.90.  Oil prices experienced a steep decline from a July 2008 high of $145.29 to $44.60 at
December 31, 2008.  This pricing pattern in the Rockies Region for oil and natural gas resulted in the Partnership’s third quarter unrealized gain of $4.5 million and fourth quarter realized and unrealized gains of $0.9 million and $2.2 million, respectively.  When forward prices for oil and natural gas decrease as they did throughout the last five months of 2008, the Partnership’s derivative positions, which include floors, ceilings and swaps, tend to increase in value, resulting
in unrealized gain positions.





In 2007, the Partnership incurred a realized gain of $0.5 million and an unrealized loss of $1.4 million, resulting in the $0.9 million net loss for the year.  The majority of the unrealized losses recognized for 2007 and for the quarters ended March 31 and December 31, respectively, were due to increasing natural gas prices.  The
decline in the CIG market during the second and third quarters of 2007, which fell to a low of $1.05 for the September average of natural gas daily prices (per MMbtu), resulted in the realized gain during 2007.  When forward prices for oil and natural gas prices increase as they did in 2007, the Partnership’s derivative portfolio tends to decrease in value, resulting in unrealized loss positions.  Due to the continued volatility of commodity prices, large quarter to quarter fluctuations
in “Oil and gas price risk management 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.





- 30 -
 Index





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.





CollarsFloors


Ceilings


Swaps


Basis SwapsCommodity
Index/Area

Quantity (Gas-Mmbtu Oil-Bbls)


Weighted Average ContractPrice


Quantity (Gas-Mmbtu Oil-Bbls)


Weighted Average ContractPrice


Quantity (Gas-Mmbtu Oil-Bbls)


Weighted Average ContractPrice


Quantity (Gas-Mmbtu Oil-Bbls)


Weighted Average ContractPrice


Fair Value at December 31, 2008Natural GasCIGPiceance1Q 2009


-


$
-



-


$
-



123,967


$
8.08



-


$
-


$
484,8342Q 2009


120,525



5.75



120,525



8.90



-



-



-



-



248,1893Q 2009


120,525



5.75



120,525



8.90



-



-



-



-



200,6174Q 2009


83,202



6.65



83,202



10.19



30,253



9.20



-



-



343,7442010


92,250



6.67



92,250



10.81



45,379



9.20



270,332



1.88



433,0642011


41,564



4.75



41,564



9.45



-



-



309,607



1.88



45,5972012


-



-



-



-



-



-



317,706



1.88



(127,834
)2013


-



-



-



-



-



-



289,195



1.88



(193,605
)$
1,434,606Wattenberg Field1Q 2009


-


$
-



-


$
-



28,077


$
8.07



-


$
-


$
109,5652Q 2009


25,530



5.75



25,530



8.89



-



-



-



-



52,5733Q 2009


25,530



5.75



25,530



8.89



-



-



-



-



42,4934Q 2009


17,570



6.65



17,570



10.19



6,292



-



-



-



72,1412010


20,683



6.56



20,683



10.73



9,437



9.20



54,376



1.88



90,7132011


10,640



4.75



10,640



9.45



-



9.20



61,200



1.88



9,7292012


-



-



-



-



-



-



63,054



1.88



(25,369
)2013


-



-



-



-



-



-



56,577



1.88



(37,874
)$
313,971OilNYMEXWattenberg Field1Q 2009


-



-



-



-



6,301


$
90.52



-



-


$
262,6942Q 2009


-



-



-



-



6,371



90.52



-



-



234,0963Q 2009


-



-



-



-



6,441



90.52



-



-



216,2074Q 2009


-



-



-



-



6,441



90.52



-



-



198,4292010


-



-



-



-



21,208



92.96



-



-



588,676$
1,500,102TOTAL

































$
3,248,679





Production and Operating Costs





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.





2008


2007Prod Costs


Mcfes


per Mcfe


Prod Costs


Mcfes


per McfeJan-Mar

$
638,352



301,401


$
2.12


$
620,601



515,082


$
1.20Apr-Jun


690,307



323,837



2.13



507,452



444,207



1.14Jul-Sep


580,116



260,772



2.22



535,932



411,543



1.30Oct-Dec


481,760



263,785



1.83



480,793



298,113



1.61Total

$
2,390,535



1,149,795


$
2.08


$
2,144,778



1,668,945


$
1.29





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.





- 31 -
 Index





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.





During 2008, production and operating costs rose $0.2 million or 11% compared to the previous year, due primarily to variable costs, including production-related taxes and transport, related to oil and natural gas volume reductions of 31%, on an Mcfe or energy equivalency basis.  Increases in the cost of general oil field services,
however, especially during the first seven months of the year when high oil and natural gas commodity prices created strong demand for oil and gas industry expertise to support both drilling and operational activity, are reflected in the per Mcfe basis unit cost increases through the first three quarters.





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.  Direct costs increased during 2008 by $0.3 million primarily due to billings from the Partnership’s independent registered public accounting firms, PricewaterhouseCoopers
LLP ("PwC") and KPMG, LLP (“KPMG”) for professional services rendered by PwC and KPMG for the audit of the Partnership’s financial statements in its comprehensive Annual Report on Form 10-K for the years ended December 31, 2007 and 2006 (PwC) and the period from December 6, 2005 (date of inception) to December 31, 2005 (KPMG) which was filed with the SEC in April 2009.  Additional direct costs in the amount of approximately $37,000 were recorded in 2008 due to a 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





The Partnership recorded depreciation, depletion, and amortization (“DD&A”) expense in 2008 and 2007 as follows:





2008


2007DD&A


Mcfes


per Mcfe


DD&A


Mcfes


per McfeJan-Mar

$
865,347



301,401


$
2.87


$
1,302,364



515,082


$
2.53Apr-Jun


898,262



323,837



2.77



1,104,753



444,207



2.49Jul-Sep


728,746



260,772



2.79



1,027,301



411,543



2.50Oct-Dec


891,165



263,785



3.38



876,427



298,113



2.94Total

$
3,383,520



1,149,795


$
2.94


$
4,310,845



1,668,945


$
2.58





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 $0.9 million decrease in DD&A for the year 2008 compared to 2007 is primarily the result of a decrease due to a production level decrease of 31% offset by an increase per Mcf due to significantly lower reserves at December 31, 2008.  In the fourth quarter of 2008 and 2007, the DD&A unit cost per Mcfe increased due
to revised estimates of reserves from the annual reserve reports which indicated decreases in reserves from the respective prior period.  While both production and overall year-end reserves are expected to decline gradually year-to-year over the wells’ remaining life cycles, downward revisions to oil and natural gas reserves in the annual 2008 reserve report resulted in the larger DD&A unit cost increase during the fourth quarter of 2008 as compared to the fourth quarter 2007.





- 32 -
 Index





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





Exploratory Dry Hole Costs





The Partnership incurred exploratory dry hole costs of $105,320 and $77,911 for the years ended December 31, 2008 and 2007, respectively, resulting from one exploratory well in Wyoming that was evaluated to be commercially non-productive and declared to be a dry hole.  This well was plugged and abandoned in 2008.





Interest Income





Interest income decreased in 2008 as compared to 2007 due to the lower level of undistributed revenues held by the Managing General Partner during the year ended December 31, 2008, as well as a reduction in the interest rates applied to those undistributed revenue amounts.  Additionally, interest rates decreased on amounts held
in escrow by the Managing General Partner on behalf of the Partnership related to production tax obligation over-withholding during the years prior to 2007.  For more information on the production tax obligation over-withholding by the Managing General Partner, see Note 2, Summary of Significant Accounting Policies−Due from (to) Managing General Partner−Other, Net.





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 repay the borrowed funds plus interest, 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 84% of the Partnership’s expected oil production and 81% 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.  Oil and natural gas derivatives as of December 31, 2008, are detailed in Note 4, Derivative Financial Instruments to the accompanying financial statements.





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 Index





Working Capital





The following table sets forth the working capital position of the Partnership at the end of each respective period:





As ofQuarter ended March 31, 2008


Quarter ended June 30, 2008


Quarter ended September 30, 2008


Quarter ended December 31, 2008Working capital

$
1,783,470


$
(142,505
)

$
2,457,444


$
3,767,858As ofQuarter ended March 31, 2007


Quarter ended June 30, 2007


Quarter ended September 30, 2007


Quarter ended December 31, 2007Working capital

$
3,267,336


$
3,172,421


$
3,056,088


$
1,952,875





Investing and Financing Cash Flows





In 2008, the Partnership received a $124,555 refund from the State of Colorado for state sales taxes charged during 2005 and 2006 on well tubing and casing purchases during the Partnership’s drilling operations, which were subsequently determined to be tax-exempt utilization of this material.  The Partnership has from time-to-time,
invested in additional equipment which supports enhanced hydrocarbon recovery, treatment, delivery and measurement or environmental protection which totaled approximately $38,000 in 2008.





The Partnership initiated monthly cash distributions to investors in July 2006 and has distributed $28.9 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 years ended December 31, 2008 and 2007,
respectively.





Managing General Partner Distributions


Investor Partners Distributions


Total Distributions2008Jan-Mar

$
538,467


$
1,276,396


$
1,814,863Apr-Jun


667,646



1,557,841



2,225,487Jul-Sep


734,121



1,712,952



2,447,073Oct-Dec


542,028



1,264,733



1,806,761$
2,482,262


$
5,811,922


$
8,294,1842007Jan-Mar

$
1,178,783


$
2,750,498


$
3,929,281Apr-Jun


690,693



1,670,495



2,361,188Jul-Sep


623,868



1,532,367



2,156,235Oct-Dec


586,281



1,407,228



1,993,509$
3,079,625


$
7,360,588


$
10,440,213





Operating Cash Flows





Net cash provided by operating activities was $8.4 million in 2008 compared to $10.5 million for 2007, a decrease of $2.1 million.  The decrease in cash provided by operating activities was due primarily to the following:





·
A decrease in oil and gas sales revenues of 4.5%, a $0.4 million decrease in realized oil and gas price risk management gain (loss), net, an increase in production and operating costs of 11.5% and an increase in direct costs – general and administrative expenditures of $.3 million.





·
Decrease in the “Due from (to) Managing General Partner, net.”





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 Index





The following table presents the operating cash flows for the following periods:





2008Quarter ended March 31,


Quarter ended June 30,


Quarter ended September 30,


Quarter ended December 31,Cash flows from operating activities

$
1,827,634


$
2,130,007


$
2,463,921


$
1,942,8722007Quarter ended March 31,


Quarter ended June 30,


Quarter ended September 30,


Quarter ended December 31,Cash flows from operating activities

$
3,942,414


$
2,379,838


$
2,168,109


$
1,993,123





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.





Contractual Obligations and Contingent Commitments





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





Payments due by periodContractual Obligations and Contingent Commitments

Total


Less than 1 year


1-3 years


3-5 years


More than 5 yearsDecember 31, 2008Derivative contracts

$
146,177


$
-


$
-


$
146,177


$
-Asset Retirement Obligations


373,183



-



-



-



373,183$
519,360


$
-


$
-


$
146,177


$
373,183December 31, 2007Derivative contracts

$
380,187


$
380,187


$
-


$
-


$
-Asset Retirement Obligations


355,379



-



-



-



355,379$
735,566


$
380,187


$
-


$
-


$
355,379





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:





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 Index





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.





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





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 Index





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, upon delivery, 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.





- 37 -
 Index





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.





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 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.  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 net fair value of Partnership commodity based derivatives as of December 31, 2008, to be $3.2 million.





Non-Derivative Financial Assets and Liabilities.  The carrying values of the financial instruments comprising “Cash and cash equivalents,” “Accounts receivable,” “Accounts payable and accrued expenses” and “Due from (to) Managing
General Partner-other, net” 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 estimated lives of the related assets, 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.





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 Index





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.








Item 7A.
Quantitative and Qualitative Disclosure About Market Risk





Market-Sensitive Instruments and Risk Management





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





Commodity Price Risk





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





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





Valuation of a contract’s fair value is performed internally, and while the Managing General Partner uses common industry practices to develop the Partnership’s valuation techniques, changes in pricing methodologies or the underlying assumptions could result in different fair values.  While the Managing General Partner
believes these valuation methods are appropriate and consistent with those used by other market participants, the use of different methodologies, or assumptions, to determine the fair value of certain financial instruments could result in a different estimate of fair value.





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 contracts.  As of December 31, 2008, the Partnership’s
oil and natural gas derivative instruments were comprised of “swaps” and “collars” in addition to “basis protection swaps.”  These instruments generally consist of CIG-based contracts for Colorado gas production and NYMEX-based contracts for Colorado oil production.  In addition to the 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.





·
For “swap” instruments, if the market price is below the fixed contract price, PDC, as Managing General Partner, receives the market price from the purchaser and receives the difference between the market price and the fixed contract price from the counterparty.  If the market price is above the fixed contract price, PDC, as Managing General Partner, receives the market price from the purchaser
and pays the difference between the market price and the fixed contract price to the counterparty.





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 Index





·
“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 fixed call strike price, PDC, as Managing General Partner, receives the market price from the purchaser and pays the difference between the call strike price and market price to the counterparty.  If the market falls below the fixed put strike price, PDC, as Managing General Partner,
receives the market price from the purchaser and receives the difference between the put strike price and market price from the counterparty.  If the market price is between the call and the put strike price, no payments are due from either party.





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





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





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





Year Ended December 31,2008


2007Average Index Closing PriceNatural gas (per MMbtu)CIG

$
6.22


$
3.97Oil (per Barrel)NYMEX


104.42



69.79Average sales priceNatural gas (per Mcf)


6.74



4.95Oil (per Barrel)


87.03



57.15





As of December 31, 2008, the fair value of the Partnership’s derivative instruments was a net asset of $3.2 million compared to a net liability of $0.4 million as of December 31, 2007.  Based on a sensitivity analysis as of December 31, 2008, it was estimated that a 10% increase in oil and gas prices, inclusive of basis,
over the entire period for which the Partnership has derivatives currently in place would result in a decreased fair value of $0.2 million and a 10% decrease in oil and gas prices would result in an increase in fair value of $2.1 million.





See Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations, Results of Operations, Oil and Gas Price Risk Management Gain (Loss), Net for a detailed discussion of the Partnership’s open derivative positions related to the Partnership’s
oil and gas sales activities and a summary of the Partnership’s open derivative positions as of December 31, 2008.





Credit Risk





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





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





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 Index





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 years ended December 31, 2008 and 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.  Although the
Managing General Partner believes that its procedures are sufficient and customary, no amount of analysis can guarantee performance in these uncertain times.





Disclosure of Limitations





As the information above incorporates only those exposures which existed as of or prior to, December 31, 2008, it does not consider those exposures or positions which could arise after that date.  As a result, the Partnership's ultimate realized gain or loss with respect to commodity price fluctuations depends on the future exposures
that arise during the period, the Partnership's hedging strategies at the time and commodity prices at the time.








Item 8.
Financial Statements and Supplementary Data





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








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 weakness described below in Management’s
Report on Internal Control Over Financial Reporting included in this Item 9A(T).





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 Index





(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





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.





- 42 -
 Index





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





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





During the first quarter of 2008, the Managing General Partner implemented the general ledger, accounts receivable, cash receipts, revenue, financial reporting, and joint interest billing modules as part of a new broader financial system.  The Managing General Partner had planned to implement a Partnership distribution module
in 2008, however, the Managing General Partner currently expects this module to be in place during 2009.  The new financial system enhanced operating efficiencies and provided more effective management of Partnership business operations and processes.  The Managing General Partner believes the phased-in implementation approach it is taking reduces the risks associated with the new financial system implementation. The Managing General Partner has taken the necessary steps to monitor and maintain
appropriate internal controls during this period of change.  These steps include documenting all new business process changes related to the new financial system; testing all new business processes on the new financial system; and conducting training related to the new business processes and to the new financial system software.  The Managing General Partner expects the implementation of the new financial system will strengthen the overall systems of internal controls due to enhanced automation
and integration of related processes.  The Managing General Partner continues to modify the design and documentation of internal control processes and procedures related to the new financial system to supplement and complement existing internal controls over financial reporting.  The system changes were developed to integrate systems and consolidate information, and were not undertaken in response to any actual or perceived deficiencies in the Partnership's internal control over financial
reporting.  Testing of the controls related to these new systems was included in the scope of the Managing General Partner's assessment of the Partnership's internal control over financial reporting for 2008.





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, had been remediated as of December 31, 2008.





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 Index





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.





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.





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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 Index





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 ExpiresRichard W. McCullough

56

Chairman, Chief Executive Officer, President and Director

2007

2010Gysle R. Shellum

56

Chief Financial Officer

-

-Eric R. Stearns

50

Executive Vice President

-

-R. Scott Meyers

34

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

2009Vincent F. D'Annunzio

56

Director

1989

2010Jeffrey C. Swoveland

53

Director

1991

2011Kimberly Luff Wakim

50

Director

2003

2009David C. Parke

41

Director

2003

2011Anthony J. Crisafio

55

Director

2006

2009Joseph E. Casabona

64

Director

2007

2011Larry F. Mazza

47

Director

2007

2010





Richard W. McCullough was appointed Chief Executive Officer in June 2008 and Chairman of PDC's Board of Directors in November 2008.  From November 2006 until November 2008, he served as the Chief Financial Officer of PDC.  Prior to
joining PDC, Mr. McCullough served as an energy consultant from July 2005 to November 2006.  From January 2004 to July 2005, Mr. McCullough served as president and chief executive officer of Gasource, LLC, Dallas, Texas, a marketer of long-term, natural gas supplies.  From 2001 to 2003, Mr. McCullough served as an investment banker with J.P. Morgan Securities, Atlanta, Georgia, and served in the public finance utility group supporting bankers nationally in all natural gas matters.  Additionally,
Mr. McCullough has held senior positions with Progress Energy, Deloitte and Touche, and the Municipal Gas Authority of Georgia.  Mr. McCullough, a Certified Public Accountant, was a practicing certified public accountant for 8 years.





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 Index





Gysle R. Shellum was appointed Chief Financial Officer in November 2008.  He has 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.





R. Scott Meyerswas appointed Chief Accounting Officer in April 2009.  Previously, Mr. Meyers, a CPA, served as a Senior Manager with Schneider Downs Co., Inc., an accounting firm
based in Pittsburgh, Pennsylvania.  Mr. Meyers served in such capacity from April 2008 to March 2009.  Prior thereto, from November 2002 to March 2008, Mr. Meyers was employed by PricewaterhouseCoopers LLP, the last two and one-half years serving as Senior Manager.  Mr. Meyers has worked in public accounting for twelve years and holds a B.S. in Accounting from Grove City College, Pennsylvania.





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 PDC 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 served as president of Beverage Distributors, Inc. located in Clarksburg, West Virginia since 1985.





Jeffrey C. Swoveland is the Chief Operating Officer of Coventina Healthcare Enterprises, a medical device company specializing in therapeutic warming and multi-modal treatment systems used in the treatment, rehabilitation and management of pain since May
2007.  Previously, Mr. Swoveland served as Chief Financial Officer of Body Media, Inc., a life-science company specializing in the design and development of wearable body monitoring products and services, from September 2000 to May 2007.  Prior thereto, Mr. Swoveland held various positions, including Vice-President of Finance, Treasurer and interim Chief Financial Officer with Equitable Resources, Inc., a diversified natural gas company from 1997 to September 2000.  Mr. Swoveland
serves as a member of the Board of Directors of Linn Energy, LLC, a public, independent natural gas and oil company.





- 46 -
 Index





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





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





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





Joseph E. Casabona served as Executive Vice President and member of the Board of Directors of Denver based Energy Corporation of America, a natural gas exploration and development company, from 1985 to his retirement in May 2007.  Mr. Casabona's
responsibilities included strategic planning as well as executive oversight of the drilling operations in the continental United States and internationally.  In 2008, Mr. Casabona assumed the title of Chief Executive Officer of Paramax Resources Ltd., a junior public Canadian oil & gas company (PMXRF) engaged in the business of acquiring and exploration of oil and gas prospects, primarily  in Canada and Idaho.





Larry F. Mazzahas served as Chief Executive Officer of MVB Bank Harrison, Inc., in Bridgeport, West Virginia since March 2005.  Prior to the formation of MVB Bank Harrison, Mr. Mazza
served as Senior Vice President Retail Banking Manager for BB&T in West Virginia, where he was employed from June 1986 to March 2005.





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.  The management fee and other amounts  paid to the Managing
General Partner by the Partnership are not used to directly compensate or reimburse PDC’s officers or directors.  No management fee was paid to PDC in 2008 or 2007 as the Partnership is not required to pay a management fee other than a one time fee paid in the initial year of formation per the Agreement.  The Partnership pays a monthly fee for each producing well based upon competitive industry rates for operations and field supervision and $75 per well per month for Partnership-related
general and administrative expenses that include accounting, engineering and management of the Partnership by the MGP. 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.





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 Index





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





As of March 31, 2009, the Partnership had 1,786.78 units outstanding.  No director or officer of PDC owns any units.  As of March 31, 2008, PDC has not repurchased any units of Partnership interests from Investor Partners.








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





Compensation to the Managing General Partner and Affiliates





The Managing General Partner transacts all of the Partnership’s business on behalf of the Partnership.  See Note 3, Transactions with Managing General Partner and Affiliates to the accompanying financial statements, for information regarding compensation to and transactions
with the Managing General Partner and affiliates.





Related Party Transaction Policies and Approval





The Limited Partnership Agreement and the Drilling 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 0.15% 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.





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 Index





Item 14.
Principal Accountant Fees and Services





There were billings from the Partnership’s independent registered public accounting firm, PricewaterhouseCoopers LLP ("PwC"), of $0.3 million and $0.1 million for audit fees for the years ended December 31, 2008 and 2007, respectively.  Additionally, during 2008 there were billings from the Partnership’s former independent
registered public accounting firm, KPMG, LLP (“KPMG”), applicable to the period December 6, 2005 (date of inception) to December 31, 2005 of approximately $43,000.  These audit fees include amounts billed for professional services rendered by PwC and KPMG for the audit of the Partnership’s financial statements in its comprehensive Annual Report on Form 10-K for years ended December 31, 2007 and 2006 and the period from February 9, 2005 (date of inception) to December 31, 2005 as well
as unaudited interim condensed financial information for each applicable interim period in 2007, 2006 and 2005.  This comprehensive Annual Form 10-K was filed with the SEC on April 8, 2009.  For the years ended December 31, 2008 and 2007, there were tax billings from the Partnership’s independent registered public accounting firm, PwC, of approximately $18,000 and $20,000, respectively.





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 Index





Audit Committee Pre-Approval Policies and Procedures





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








Item 15.
Exhibits, Financial Statement Schedules





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





(b)
Exhibit Index.





Incorporated by ReferenceExhibit Number

Exhibit Description

Form

SEC File Number

Exhibit

Filing Date

Filed Herewith3.1

Limited Partnership Agreement

10-12G/A Amend 2

000-51959

3

10/04/20063.2

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

10-K

000-51959

3.2

04/08/200910.1

Form of assignment of leases to the Partnership

10-K

000-51959

10.1

04/08/200910.2

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

10-K

000-51959

10.2

04/08/200910.3

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



02/27/200910.4

Gas Purchase and Processing Agreement between Duke Energy Field Services, Inc.; United States Exploration, Inc.; and Petroleum Development Corporation, dated October 28, 1999 (filed by PDC as Managing General Partner for Rockies Region 2007 Limited Partnership)

10-12G/A Amend 3

000-53201

10.3

03/31/200910.5

Gas Purchase and Processing Agreement between Natural Gas Associates, a Colorado partnership, and Aceite Energy Corporation, Walker Exploratory Program 1982-A Limited and Cattle Creek Company, dated October 14, 1983 (filed by PDC as Managing General Partner for Rockies Region 2007 Limited Partnership)

10-12G/A Amend 3

000-53201

10.4

03/31/2009





- 50 -
 Index




Incorporated by ReferenceExhibit Number

Exhibit Description

Form

SEC File Number

Exhibit

Filing Date

Filed Herewith10.6

Gas Purchase and Processing Agreement between Natural Gas Associates, a Colorado partnership, and SHF Partnership, a Colorado general partnership, Trailblazer Oil and Gas, Inc., Alfa Resources, Inc., Pulsar Oil and Gas, Inc., Overthrust Oil Royalty Corporation, Corvette Petroleum Ltd., Robert Lanari, an individual, and Toby A Martinez, an
individual, dated September 21, 1983 (filed by PDC as Managing General Partner for Rockies Region 2007 Limited Partnership)

10-12G/A Amend 3

000-53201

10.5

03/31/200910.7

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

10-12G/A Amend 3

000-53201

10.6

03/31/200910.8

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

10-12G/A Amend 3

000-53201

10.7

03/31/200923.1

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









X31.1

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









X31.2

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









X





- 51 -
 Index




Incorporated by ReferenceExhibit Number

Exhibit Description

Form

SEC File Number

Exhibit

Filing Date

Filed Herewith32.1

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.









X32.2

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





- 52 -
 Index





SIGNATURES


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





Rockies Region Private Limited Partnership


By its Managing General Partner


Petroleum Development Corporation





By/s/ Richard W. McCullough


Richard W. McCullough


Chairman, Chief Executive Officer, and President


April 28, 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,
April 28, 2009Richard W. McCullough
Petroleum Development Corporation,Managing General Partner of the Registrant(Principal executive officer)/s/ Gysle R. Shellum
Chief Financial Officer
April 28, 2009Gysle R. Shellum
Petroleum Development Corporation,Managing General Partner of the Registrant(Principal financial officer)/s/ R. Scott Meyers
Chief Accounting Officer
April 28, 2009R. Scott Meyers
Petroleum Development Corporation,Managing General Partner of the Registrant(Principal accounting officer)/s/ Steven R. Williams
Director
April 28, 2009Steven R. Williams
Petroleum Development Corporation,Managing General Partner of the Registrant/s/ Anthony J. Crisafio
Director
April 28, 2009Anthony J. Crisafio
Petroleum Development Corporation,Managing General Partner of the Registrant/s/ Jeffrey C. Swoveland
Director
April 28, 2009Jeffrey C. Swoveland
Petroleum Development Corporation,Managing General Partner of the Registrant/s/ Joseph E. Casabona
Director
April 28, 2009Joseph E. Casabona
Petroleum Development Corporation,Managing General Partner of the Registrant





- 53 -
 Index





ROCKIES REGION PRIVATE  LIMITED PARTNERSHIP





Index to Financial Statements





Report of Independent Registered Public Accounting Firm
F-2Balance Sheets – December 31, 2008 and 2007
F-3Statements of Operations – For the Years Ended December 31, 2008 and 2007
F-4Statements of Partners' Equity –For the Years Ended December 31, 2008 and 2007
F-5Statements of Cash Flows – For the Years Ended December 31, 2008 and 2007
F-6Notes to Financial Statements
F-7Supplemental Oil and Gas Information - Unaudited
F-24Unaudited Condensed Quarterly Financial Statements:Balance Sheets - 2008
F-28Balance Sheets - 2007
F-29Statements of Operations - 2008
F-30Statements of Operations - 2007
F-31Statements of Cash Flows - 2008
F-32Statements of Cash Flows - 2007
F-33Notes to Unaudited Condensed Quarterly Financial Statements
F-34





F-1
 Index





REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM











To the Partners of the Rockies Region Private 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 Private Limited Partnership (the "Partnership") at December 31, 2008 and 2007, and the results of its operations and its cash flows for
each of the two years in the period ended December 31, 2008 in conformity with accounting principles generally accepted in the United States of America.  These financial statements are the responsibility of the Partnership's management.  Our responsibility is to express an opinion on these financial statements based on our audits.  We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States).  Those
standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.  An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation.  We believe that our audits provide a reasonable basis for our opinion.





As discussed in Note 3 to the financial statements, the Partnership has significant related party transactions with Petroleum Development Corporation and its subsidiaries.











/s/ PricewaterhouseCoopers, LLP


Pittsburgh, Pennsylvania


April 28, 2009





F-2
 Index









Balance Sheets


December 31, 2008 and 2007





Assets

2008


2007Current assets:Cash and cash equivalents

$
219,706


$
63,599Accounts receivable


397,959



899,341Oil inventory


30,405



-Due from Managing General Partner-derivatives, net


2,465,581



-Due from Managing General Partner-other, net


745,795



1,481,279Total current assets


3,859,446



2,444,219Oil and gas properties, successful efforts method


41,158,838



40,785,791Drilling advances to Managing General Partner


-



253,556Oil and gas properties, at cost


41,158,838



41,039,347Less:  Accumulated depreciation, depletion and amortization


(13,572,027
)


(10,188,507
)Oil and gas properties, net


27,586,811



30,850,840Due from Managing General Partner-derivatives, net


929,275



-Due from Managing General Partner-other, net


-



264,016Total noncurrent assets


28,516,086



31,114,856Total Assets

$
32,375,532


$
33,559,075Liabilities and Partners' EquityCurrent liabilities:Accounts payable and accrued expenses

$
91,588


$
111,157Due to Managing General Partner-derivatives, net


-



380,187Total current liabilities


91,588



491,344Due to Managing General Partner-derivatives


146,177



-Asset retirement obligations


373,183



355,379Total liabilities


610,948



846,723Commitments and contingenciesPartners' equity:Managing General Partner


7,965,201



8,243,538Limited Partners - 1,786.78 units issued and outstanding


23,799,383



24,468,814Total Partners' equity


31,764,584



32,712,352Total Liabilities and Partners' Equity

$
32,375,532


$
33,559,075





See accompanying notes to financial statements.





F-3
 Index










Statements of Operations


For the Years Ended December 31, 2008 and 2007





2008


2007Revenues:Oil and gas sales

$
9,885,786


$
10,350,973Oil and gas price risk management gain (loss), net


3,743,682



(899,196
)Total revenues


13,629,468



9,451,777Operating costs and expenses:Production and operating costs


2,390,535



2,144,778Direct costs - general and administrative


432,297



101,279Depreciation, depletion and amortization


3,383,520



4,310,845Exploratory dry hole costs


105,320



77,911Accretion of asset retirement obligations


17,804



16,620Total operating costs and expenses


6,329,476



6,651,433Income from operations


7,299,992



2,800,344Interest income


46,424



101,818Net income

$
7,346,416


$
2,902,162Net income  allocated to partners

$
7,346,416


$
2,902,162Less:  Managing General Partner interest in net income


2,203,925



870,649Net income allocated to Investor Partners

$
5,142,491


$
2,031,513Net income per Investor Partner unit

$
2,878


$
1,137Investor Partner units outstanding


1,786.78



1,786.78





See accompanying notes to financial statements.





F-4
 Index









Statements of Partners' Equity


For the Years Ended December 31, 2008 and 2007





Investor Partners


Managing General Partner


TotalBalance, December 31, 2006

$
29,797,889


$
10,452,514


$
40,250,403Distributions to partners


(7,360,588
)


(3,079,625
)


(10,440,213
)Net income


2,031,513



870,649



2,902,162Balance, December 31, 2007

$
24,468,814


$
8,243,538


$
32,712,352Distributions to partners


(5,811,922
)


(2,482,262
)


(8,294,184
)Net income


5,142,491



2,203,925



7,346,416Balance, December 31, 2008

$
23,799,383


$
7,965,201


$
31,764,584





See accompanying notes to financial statements.





F-5
 Index









Statements of Cash Flows


For the Years Ended December 31, 2008 and 2007





2008


2007Cash flows from operating activities:Net income

$
7,346,416


$
2,902,162Adjustments to reconcile net income to net cash provided by operating activities:Depreciation, depletion and amortization


3,383,520



4,310,845Accretion of asset retirement obligations


17,804



16,620Unrealized (gain) loss on derivative transactions


(3,628,866
)


1,404,267Exploratory dry hole costs


105,320



77,911Changes in operating assets and liabilities:Decrease in accounts receivable


501,382



2,242,286Increase in oil inventory


(30,405
)


-Decrease in accounts payable and accrued expenses


(19,569
)


(258,245
)Decrease (increase) in due from/to Managing General Partner, net


688,832



(212,362
)Net cash provided by operating activities


8,364,434



10,483,484Cash flows from investing activities:Capital expenditures for oil and gas properties


(38,698
)


-Proceeds from Colorado sales tax refund related to capital purchases


124,555



-Net cash provided by investing activities


85,857



-Cash flows from financing activities:Distributions to Partners


(8,294,184
)


(10,440,213
)Net cash used in financing activities


(8,294,184
)


(10,440,213
)Net increase in cash and cash equivalents


156,107



43,271Cash and cash equivalents, beginning of year


63,599



20,328Cash and cash equivalents, end of year

$
219,706


$
63,599Supplemental disclosure of non-cash activity:Asset retirement obligation, with corresponding increase to oil and gas properties

$
-


$
6,325Non-cash well costs - due to Managing General Partner

$
310,668


$
-





See accompanying notes to financial statements.





F-6
 Index











Note 1 − Organization





The Rockies Region Private Limited Partnership (the “Partnership” or the “Registrant”) was organized as a limited partnership on December 6, 2005, 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 41.5 units of limited partner interests and 1,745.28 units of additional general partner interests at $20,000 per unit.  As of March 31, 2009, there are 962 Investor Partners.  Petroleum Development Corporation has been designated the Managing General
Partner of the Partnership and has a 30% ownership in the Partnership. Throughout the term of the Partnership, revenues, costs, and cash distributions are allocated 70% to the limited and additional general partners (collectively, the “Investor Partners”), which are shared pro rata based upon the portion of units owned in the Partnership, and 30% to the Managing General Partner.  As of March 31, 2009, the Managing General Partner has not repurchased any of the total 1,786.78 outstanding
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 0.15% 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
 Index







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 years ended December 31, 2008 and 2007.





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





The Managing General Partner transacts business on behalf of the Partnership.  Other than 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) Managing General Partner – other, net” and are more fully described in Note 3, Transactions with Managing General Partner and Affiliates.  In addition, certain amounts recorded by the Partnership as assets in the account “Due from (to) Managing General Partner – other, net” include amounts that are being held as restricted cash by the Managing General Partner, on behalf of the Partnership and
other partnerships for which PDC serves as Managing General Partner.





Additionally, 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 represents unpaid royalties on Partnership production  through
2008 which will be deducted from future Partner distributions.  These amounts, which total approximately $111,000, including legal fees of approximately $8,000, 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.





Additionally, in 2008 the Partnership incurred additional drilling costs of $310,668 in excess of drilling advances paid to the Managing General Partner.  These costs were paid by PDC on behalf of the Partnership and have been recorded as a liability in the account “Due from (to) Managing General Partner – other,
net” and will be funded by a reduction in future distributions.





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.





F-8
 Index







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 new reserve reports from independent petroleum engineers annually as of December 31.  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, 2005.  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.”





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 depreciation, depletion 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, SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, the Partnership assesses its proved oil and gas properties for possible impairment, upon a triggering event, by comparing net capitalized
costs to estimated undiscounted future net cash flows on a field-by-field basis using estimated production based upon prices at which the Partnership reasonably estimates the commodity to be sold.  The estimates of future prices may differ from current market prices of oil and natural gas.  Downward revisions in estimates to the Partnership’s reserve quantities, expectations of falling commodity prices or rising operating costs could result in a triggering event and therefore a possible
impairment of the Partnership’s oil and natural gas properties.  If net capitalized costs exceed undiscounted future net cash flows, impairment is based on estimated fair value utilizing a future discounted cash flow analysis and is measured by the amount by which the net capitalized costs exceed their fair value.  Due to the significant reduction in oil and natural gas prices during the fourth quarter of 2008, the Partnership reviewed its proved oil and natural gas properties for impairment.  The
Partnership did not incur any impairment loss as a result of this review.




F-9
 Index




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.





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 15%, 40%, and 45%, respectively, of the Partnership’s total natural gas and oil sales for the year ended December
31, 2008.  These same three customers, DCP, Teppco and Williams, accounted for 16%, 42% and 42% 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 Obligationsand 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.





F-10
 Index







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 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.





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 the account “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 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 of Financial Instruments.





F-11
 Index







In October 2008, the FASB issued FSP FAS No. 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 FAS No. 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 became effective for the Partnership on January 1, 2008.  The Partnership has not and does not intend to measure additional financial assets and liabilities at fair value.





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.





In December 2007, the FASB issued FAS No. 141 (revised 2007), Business Combinations (“FAS No. 141(R)”).  FAS No. 141(R) requires an acquirer to recognize the assets acquired, the liabilities assumed and any noncontrolling interest in the acquiree at their acquisition-date
fair values.  FAS No. 141(R) 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, FAS No. 141(R) requires that acquisition-related costs be expensed as incurred.  The provisions of FAS No. 141(R) will become effective for acquisitions completed on or after January 1, 2009; however, the income tax provisions of FAS No. 141(R) will become effective as
of that date for all acquisitions, regardless of the acquisition date.  FAS No. 141(R) amends FAS 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.  FAS No. 141(R) further amends
FAS 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 April 2009, the FASB issued
FSP FAS No. 141(R)-1, Accounting for Assets Acquired and Liabilities Assumed in a Business Combination That Arise from Contingencies (“FSP 141(R)-1”), amending the guidance of FAS No. 141(R) to require that assets acquired and liabilities assumed in a business combination that arise from contingencies be recognized at fair value if fair value can be reasonably estimated and if not, the asset and liability would generally be recognized in accordance
with FAS No. 5, Accounting for Contingencies, and FASB Interpretation No. 14, Reasonable Estimation of the Amount of a Loss.  Further, FSP 141(R)-1 requires that certain acquired contingencies be treated as contingent consideration and measured both initially and subsequently at fair value.  The Partnership adopted the provisions of FAS No. 141(R) and FSP 141(R)-1 effective January
1, 2009, for which the provisions will be applied prospectively in the Partnership’s accounting for future acquisitions, if any.





F-12
 Index







In December 2007, the FASB issued FAS No. 160, Noncontrolling Interests in Consolidated Financial Statements—An Amendment of ARB No. 51.  FAS 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.  The Partnership adopted the provisions of FAS No. 160 effective January 1, 2009.  The adoption of FAS No. 160 did not have a material impact on the Partnership’s financial statements.





In February 2008, the FASB issued FSP No. 157-2, Effective Date of FASB Statement No. 157 (“FAS No. 157”) (“FSP 157-2”), which delayed the effective date of FAS No. 157, Fair Value Measurements, 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).  Effective January 1, 2009, the Partnership adopted the provisions of FAS No. 157 delayed by FSP 157-2.  The adoptions of FSP 157-2 did not have a material impact on the Partnership’s financial statements.  See Note 5, Fair Value
of Financial Instruments.





In March 2008, the FASB issued FAS 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.  The Partnership adopted the provisions of FAS No. 161 effective January 1, 2009.  The adoption of FAS No. 161 did not have a material
impact on the Partnership’s financial statements.  See Note 4, Derivative Financial Instruments.





Recently Issued Accounting Standards





On April 9, 2009, the FASB issued the following amendments to the fair value measurement and disclosure standards:





·
FSP No. FAS 157-4, Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly (“FSP 157-4”)





·
FSP No. FAS 107-1 and APB 28-1, Interim Disclosures about Fair Value of Financial Instruments (“FSP 107-1/APB 28-1”)





FSP 157-4 affirms that the objective of fair value when the market for an asset is not active is the price that would be received to sell the asset in an orderly transaction; clarifies and includes additional factors for determining whether there has been a significant decrease in market activity for an asset when the market for that
asset is not active; eliminates the proposed presumption that all transactions are distressed (not orderly) unless proven otherwise and instead requires an entity to base its conclusion about whether a transaction was not orderly on the weight of the evidence; requires an entity to disclose a change in valuation technique (and the related inputs) resulting from the application of the FSP and to quantify its effects, if practicable; and applies to all fair value measurements when appropriate.





FSP 107-1/APB 28-1 amends FAS No. 107, Disclosures about Fair Value of Financial Instruments, to require an entity to provide disclosures about fair value of financial instruments in interim financial information.  This FSP also amends Accounting Principles Board (“APB”)
Opinion No. 28, Interim Financial Reporting, to require those disclosures in summarized financial information at interim reporting periods.  Pursuant to this FSP, a reporting entity shall include disclosures about the fair value of its financial instruments whenever it issues summarized financial information for interim reporting periods.  In addition, an entity shall disclose in the body or in the accompanying notes of its summarized
financial information for interim reporting periods and in its financial statements for annual reporting periods the fair value of all financial instruments for which it is practicable to estimate that value, whether recognized or not recognized in the statement of financial position, as required by SFAS No. 107.





F-13
 Index







Both FSP 157-4 and FSP 107-1/APB 28-1 are effective for interim and annual reporting periods ending after June 15, 2009, with early adoption permitted for periods ending after March 15, 2009.  However, early adoption is allowed only if certain FSPs are early adopted together: an entity early adopting FSP 157-4 must also early
adopt FSP FAS 115-2 and FAS 124-2, Recognition and Presentation of Other-Than-Temporary Impairments (“FSP 115-2/124-2”) and an entity early adopting FSP 107-1/APB 28-1 must also elect to early adopt FSP 157-4 and FSP 115-2/124-4.  The Partnership does expect these FSPs to have a significant impact on the Partnership’s financial statements when adopted on April 1, 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.





Reclassifications





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.





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.  The fair value of
the Partnership’s portion of unexpired derivative instruments is recorded on the balance sheet under the captions “Due from Managing General Partner – derivatives” in the case of net unrealized gains or “Due to Managing General Partner – derivatives” in the case of net unrealized losses.  Undistributed oil and natural gas revenues collected by the MGP from the Partnership’s customers of $894,254 and $1,244,972 as of December 31, 2008 and 2007, respectively,
are included in the balance sheet caption “Due from Managing General Partner-other, net.”  The $1,244,972 of undistributed oil and natural gas revenues at December 31, 2007 has been reclassified from “Accounts Receivable” to “Due from Managing General Partner – other, net” to conform to current year presentation.  Realized gains or losses that have not yet been distributed to the Partnership are included in the balance sheet captions “Due from
Managing General Partner-other, net” or “Due to Managing General Partner-other, net,” respectively.  Undistributed realized gains amounted to $854,151 and $135,056 as of December 31, 2008 and 2007, respectively.  All other unsettled transactions between the Partnership and the Managing General Partner are recorded net on the balance sheet under the caption “Due from (to) Managing General Partner – other, net.”





F-14
 Index







The following table presents transactions with the Managing General Partner and its affiliates for years ended December 31, 2008 and 2007.





Year Ended December 31,2008


2007Well charges (1) (2)

$
318,506


$
318,688Supplies and equipment (3)


983,313



639,968Gathering, compression and processing fees (4)


243,659



297,115Direct costs - general and administrative (5)


432,297



101,279Cash distributions (6)


2,482,262



3,079,625





(1)
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 and maintenance of access roads.





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





(2)
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.





F-15
 Index







(3)
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.





(4)
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.





(5)
The Agreement provides for the allocation of cash distributions 70% to the Investor Partners and 30% 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 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 leases is acceptable for purposes of the Partnership.





The following table presents the usage of the drilling advances to the Managing General Partner based on the drilling activities of the Managing General Partner.





Year Ended December 31, 2008


Year Ended December 31, 2007Purchases of leases

$
-


$
3,119Drilling costs


494,934



1,492,591Drilling compensation


69,291



209,399Drilling advances to Managing General Partner


(253,556
)


(1,705,109
)





In 2008, the Partnership incurred $310,668 of additional drilling costs in excess of drilling advances paid to the Managing General Partner.  These costs were paid by PDC on behalf of the Partnership and have been recorded as a liability in the account “Due from (to) Managing General Partner – other, net” and
will be funded by a reduction in future distributions to 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.





F-16
 Index







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 years ended December 31, 2008 and 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 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.





·
For swap instruments, if the market price is below the fixed contract price, PDC, as Managing General Partner, receives the market price from the purchaser and receives the difference between the market price and the fixed contract price from the counterparty.  If the market price is above the fixed contract price, PDC, as Managing General Partner, receives the market price from the purchaser and pays the
difference between the market price and the fixed contract price to the counterparty.





·
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 fixed call strike price, PDC, as Managing General Partner, receives the market price from the purchaser and pays the difference between the call strike price and market price to the counterparty.  If the market falls below the fixed put strike price, PDC, as Managing General Partner, receives the
market price from the purchaser and receives the difference between the put strike price and market price from the counterparty.  If the market price is between the call and the put strike price, no payments are due from either party.





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





The Managing General Partner enters into derivative instruments for Partnership production to reduce the impact of price declines in future periods.  While these derivatives are structured to reduce 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.





F-17
 Index







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


2007Derivative net assets (liabilities)Oil and gas sales activities:Fixed-price natural gas swaps

$
928,735


$
-Oil collars


-



71,282Natural gas collars


966,019



-Natural gas basis protection swaps


(146,176
)


1,309Fixed-price oil swaps


1,500,101



(452,778
)Estimated net fair value of derivative instruments

$
3,248,679


$
(380,187
)





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


2007Classification in the Balance SheetsFair value of current assetsDue from Managing General Partner-derivatives, net

$
2,465,581


$
-Fair value of other assets-long termDue from Managing General Partner-derivative, net


929,275



-3,394,856



-Fair value of current liabilitiesDue to Managing General Partner-derivatives, net


-



(380,187
)Fair value of other liabilities-long termDue to Managing General Partner-derivatives


(146,177
)


-Net fair value of commodity based derivatives- asset (liability)

$
3,248,679


$
(380,187
)





F-18
 Index







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 312008


2007Realized gains (losses)Oil

$
(142,973
)

$
(24,151
)Natural Gas


257,789



529,222Total realized gain, net


114,816



505,071Unrealized gain (loss)


3,628,866



(1,404,267
)Oil and gas price risk management, gain (loss), net

$
3,743,682


$
(899,196
)





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.





F-19
 Index







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 the Partnership’s assets and liabilities for each hierarchy level, 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


TotalAssets:Commodity based derivatives

$
-


$
-


$
3,248,679


$
3,248,679Net fair value of commodity based derivatives

$
-


$
-


$
3,248,679


$
3,248,679





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





Year Ended December 31, 2008Fair value, net asset (liability), beginning of period

$
(380,187
)Realized and unrealized gains (losses) included in oil and gas price risk management gain (loss), net


3,743,682Purchases, sales, issuances and settlements, net


(114,816
)Fair value, net asset, end of period

$
3,248,679





Non-Derivative Financial Instruments





The carrying values of the financial instruments comprising “Cash and cash equivalents,” “Accounts receivable,” “Accounts payable and accrued expenses” and “Due to (from) Managing General Partner-other, net” 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.





F-20
 Index







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.





Investor Partners


Managing General PartnerPartnership Revenue:Oil and gas sales


70
%


30
%Oil and gas price risk management gain (loss)


70
%


30
%Sale of productive properties


70
%


30
%Sale of equipment


70
%


30
%Sale of undeveloped leases


70
%


30
%Interest income


70
%


30
%Partnership Costs:Organization 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
%Other costs and expenses:Management fee (c)


100
%


0
%Production and operating costs (d)


70
%


30
%Depreciation, depletion and amortization expense


70
%


30
%Accretion of asset retirement obligations


70
%


30
%Direct costs - general and administrative (e)


70
%


30
%





(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)
These 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.





F-21
 Index







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





Year Ended December 31,2008


2007Net income allocated to Investor Partners:70% of Net Income allocable to the Investor Partners

$
5,142,491


$
2,031,513Net income allocated to Managing General Partner:30% of Net Income allocable to the Managing General Partner


2,203,925



870,649Net income allocated to partners

$
7,346,416


$
2,902,162





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 70% to the Investor Partners and 30% to the Managing General Partner throughout the term of the Partnership.  The Partnership has paid cash distributions each month since July 2006.  Distributions for the years ended December 31, 2008 and 2007 were $8,294,184 and $10,440,213, respectively.





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 December 30, 2005 with payments made for all planned drilling and completion costs for the Partnership in 2005.  Costs capitalized for these activities
at December 31, 2008 and 2007 are as follows:





2008


2007Leasehold costs

$
459,554


$
459,554Development costs


40,699,284



40,326,237Oil and gas properties, successful efforts method


41,158,838



40,785,791Drilling advances to Managing General Partner


-



253,556Oil and gas properties at cost


41,158,838



41,039,347Less:  Accumulated depreciation, depletion and amortization


(13,572,027
)


(10,188,507
)Oil and gas properties, net

$
27,586,811


$
30,850,840





“Drilling advances to Managing General Partner” represent unused prepayments to the Managing General Partner for the development of oil and gas properties which will be used for future capital costs.  Development costs include the Partnership’s asset retirement obligations.





F-22
 Index







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


2007Balance at beginning of period

$
355,379


$
332,434Obligations assumed with developmental activities


-



6,325Accretion expense


17,804



16,620Balance at end of period

$
373,183


$
355,379





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.  Obligations assumed with developmental activities are due to drilling activity which occurred during 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.





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.  Based on the mediation held on May 28, 2008, and subsequent negotiations, $74,412 was accrued by the Partnership for this litigation for the year ended December 31, 2007.  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 38 wells in the Wattenberg field.





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 approximately $111,000 which includes legal fees of approximately $8,000.  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.  The final settlement was approved by the court at a hearing on April 7, 2009.





F-23
 Index







Costs Incurred in Oil and Gas Property Development Activities





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





2008


2007Leasehold costs

$
-


$
6,385Development costs


497,603



3,597,081Colorado sales tax refund


(124,556
)


-Total costs incurred

$
373,047


$
3,603,466





Development costs include costs incurred to gain access to and prepare development well locations for drilling, to recomplete wells, and to provide facilities to extract, treat, gather and store oil and gas.





During 2008, the Partnership received a $124,555 refund from the State of Colorado for state sales taxes charged during 2005 and 2006 on well tubing and casing purchases during the Partnership’s drilling operations, which have subsequently been determined to be tax-exempt.  The refund has been accounted for as a reduction
of the costs of oil and gas properties previously capitalized.  The Partnership periodically invests in equipment which supports enhanced hydrocarbon recovery, treatment, delivery and measurement or environmental protection which totaled approximately $38,000 in 2008.





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 all of which are located in the United States.  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.





F-24
 Index







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





Oil (MBbl)2008


2007Proved reserves:Beginning of year


762



493Revisions of previous estimates


(78
)


345Production


(46
)


(76
)End of Year, December 31


638



762Gas (MMcf)2008


2007Proved reserves:Beginning of year


9,791



12,671Revisions of previous estimates


601



(1,667
)Production


(874
)


(1,213
)End of Year, December 31


9,518



9,791December 31,Proved Developed Reserves

2008


2007Oil (MBbl)


188



364Natural Gas (MMcf)


7,099



8,125





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





At December 31, 2008, the Partnership’s estimated proved oil and natural gas reserves experienced a net downward revision of previous estimates of 78 MBbls of oil and an upward revision of 601 MMcfs of natural gas, respectively.  This net revision is the result of a downward revision of proved developed producing reserves
amounting to approximately 130 MBbls of oil and 152 MMcfs of natural gas, partially offset by an upward revision of proved undeveloped reserves amounting to approximately 52 MBbls of oil and 753 MMcfs of natural gas.  The downward revision to proved developed producing reserves was primarily due to reduced economics resulting from significantly lower year-end oil and natural gas prices and higher per-well operating costs at December 31, 2008. The upward revision to proved undeveloped reserves was due
primarily to an increase in the production curve based upon a detailed analysis of the results of the Codell zone refractures in the Wattenberg Field performed by PDC, the Managing General Partner, over the last several years.





F-25
 Index







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.





As of December 31,2008


2007(in thousands)Future estimated revenues

$
69,600


$
128,592Future estimated production costs


(25,212
)


(30,514
)Future estimated development costs


(7,185
)


(7,147
)Future net cash flows


37,203



90,93110% annual discount for estimated timing of cash flows


(19,191
)


(45,025
)Standardized measure of discounted future estimated net cash flows

$
18,012


$
45,906





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:





For the year ended December 31,2008


2007(in thousands)Sales of oil and gas production, net of production costs

$
(7,495
)

$
(8,206
)Net changes in prices and production costs


(22,194
)


15,028Revisions of previous quantity estimates


(190
)


7,721Accretion of discount


4,151



2,647Timing and other


(2,167
)


(3,037
)Net change

$
(27,895
)

$
14,153





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.





F-26
 Index







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 PriceAs of December 31,

Oil(per Bbl)


Gas(per Mcf)2008

$
38.46


$
4.732007


80.20



6.89





F-27
 Index










BALANCE SHEETS

As ofAssets

March 31, 2008


June 30, 2008


September 30, 2008


December 31, 2008Current assets:Cash and cash equivalents

$
72,373


$
79,555


$
91,081


$
219,706Accounts receivable


1,021,894



1,368,722



590,986



397,959Accounts receivable - other


-



124,555



124,555



-Oil inventory


34,168



38,735



40,660



30,405Due from Managing General Partner-derivatives, net


32,677



-



1,135,360



2,465,581Due from Managing General Partner-other, net


1,813,694



1,088,250



1,007,773



745,795Total current assets


2,974,806



2,699,817



2,990,415



3,859,446Oil and gas properties, successful efforts method


40,801,867



41,082,842



41,090,530



41,158,838Drilling advances to Managing General Partner


222,038



-



-



-Oil and gas properties, at cost


41,023,905



41,082,842



41,090,530



41,158,838Less:  Accumulated depreciation, depletion and amortization


(11,053,854
)


(11,952,116
)


(12,680,862
)


(13,572,027
)Oil and gas properties, net


29,970,051



29,130,726



28,409,668



27,586,811Due from Managing General Partner-derivatives, net


48,057



-



489,821



929,275Total noncurrent assets


30,018,108



29,130,726



28,899,489



28,516,086Total Assets

$
32,992,914


$
31,830,543


$
31,889,904


$
32,375,532Liabilities and Partners' EquityCurrent liabilities:Accounts payable and accrued expenses

$
232,449


$
309,854


$
211,166


$
91,588Due to Managing General Partner-derivatives, net


958,887



2,532,468



321,805



-Total current liabilities


1,191,336



2,842,322



532,971



91,588Due to Managing General Partner-derivatives, net


252,352



1,023,970



317,507



146,177Asset retirement obligations


359,830



364,281



368,732



373,183Total liabilities


1,803,518



4,230,573



1,219,210



610,948Partners' equity:Managing General Partner


7,792,643



6,715,815



7,637,033



7,965,201Limited Partners - 1,786.78 units issued and outstanding


23,396,753



20,884,155



23,033,661



23,799,383Total Partners' equity


31,189,396



27,599,970



30,670,694



31,764,584Total Liabilities and Partners' Equity

$
32,992,914


$
31,830,543


$
31,889,904


$
32,375,532





See accompanying notes to unaudited condensed quarterly financial statements.





F-28
 Index







BALANCE SHEETS

As ofAssets

March 31, 2007


June 30, 2007


September 30, 2007


December 31, 2007Current assets:Cash and cash equivalents

$
33,461


$
52,111


$
63,984


$
63,599Accounts receivable


1,327,848



1,052,567



905,866



899,341Due from Managing General Partner-derivatives, net


393,949



506,410



519,895



-Due from Managing General Partner-other, net


1,786,173



1,794,523



1,767,924



1,481,279Total current assets


3,541,431



3,405,611



3,257,669



2,444,219Oil and gas properties, successful efforts method


37,382,032



39,947,543



40,030,883



40,785,791Wells in progress


2,711,435



-



-



-Drilling advances to Managing General Partner


1,022,892



1,141,323



1,001,500



253,556Oil and gas properties, at cost


41,116,359



41,088,866



41,032,383



41,039,347Less:  Accumulated depreciation, depletion and amortization


(7,180,026
)


(8,284,779
)


(9,312,080
)


(10,188,507
)Oil and gas properties, net


33,936,333



32,804,087



31,720,303



30,850,840Due from Managing General Partner-derivatives, net


-



82,958



28,644



-Due from Managing General Partner-other, net


102,242



188,161



264,016



264,016Total noncurrent assets


34,038,575



33,075,206



32,012,963



31,114,856Total Assets

$
37,580,006


$
36,480,817


$
35,270,632


$
33,559,075Liabilities and Partners' EquityCurrent liabilities:Accounts payable and accrued expenses

$
274,095


$
233,190


$
201,581


$
111,157Due to Managing General Partner-derivatives, net


-



-



-



380,187Due to Managing General Partner-other, net


-



-



-



-Total current liabilities


274,095



233,190



201,581



491,344Asset retirement obligations


342,914



347,069



351,224



355,379Total liabilities


617,009



580,259



552,805



846,723Partners' equity:Managing General Partner


9,466,293



9,165,225



8,833,407



8,243,538Limited Partners - 1,786.78 units issued and outstanding


27,496,704



26,735,333



25,884,420



24,468,814Total Partners' equity


36,962,997



35,900,558



34,717,827



32,712,352Total Liabilities and Partners' Equity

$
37,580,006


$
36,480,817


$
35,270,632


$
33,559,075





See accompanying notes to unaudited condensed quarterly financial statements.





F-29
 Index










Quarter EndedSTATEMENTS OF OPERATIONS

March 31, 2008


June 30, 2008


September 30, 2008


December 31, 2008Revenues:Oil and gas sales

$
2,708,743


$
3,482,921


$
2,401,908


$
1,292,214Oil and gas price risk management (loss) gain, net


(864,936
)


(3,075,778
)


4,567,436



3,116,960Total revenues


1,843,807



407,143



6,969,344



4,409,174Operating costs and expenses:Production and operating costs


638,352



690,307



580,116



481,760Direct costs - general and administrative


38,691



173,687



112,655



107,264Depreciation, depletion and amortization


865,347



898,262



728,746



891,165Exploratory dry hole costs


19,440



16,064



35,603



34,213Accretion of asset retirement obligations


4,451



4,451



4,451



4,451Total operating costs and expenses


1,566,281



1,782,771



1,461,571



1,518,853Income (loss) from operations


277,526



(1,375,628
)


5,507,773



2,890,321Interest income


14,380



11,689



10,024



10,331Net income (loss)

$
291,906


$
(1,363,939
)

$
5,517,797


$
2,900,652Net income (loss) allocated to partners

$
291,906


$
(1,363,939
)

$
5,517,797


$
2,900,652Less:  Managing General Partner interest in net income (loss)


87,572



(409,182
)


1,655,339



870,196Net income (loss) allocated to Investor Partners

$
204,334


$
(954,757
)

$
3,862,458


$
2,030,456Net income (loss) per Investor Partner unit

$
114


$
(534
)

$
2,162


$
1,136Investor Partner units outstanding


1,786.78



1,786.78



1,786.78



1,786.78





See accompanying notes to unaudited condensed quarterly financial statements.





F-30
 Index







Quarter EndedSTATEMENTS OF OPERATIONS

March 31, 2007


June 30, 2007


September 30, 2007


December 31, 2007Revenues:Oil and gas sales

$
3,178,054


$
2,670,716


$
2,357,890


$
2,144,313Oil and gas price risk management (loss) gain, net


(647,790
)


321,150



221,114



(793,670
)Total revenues


2,530,264



2,991,866



2,579,004



1,350,643Operating costs and expenses:Production and operating costs


620,601



507,452



535,932



480,793Direct costs - general and administrative


403



75,178



430



25,268Depreciation, depletion and amortization


1,302,364



1,104,753



1,027,301



876,427Exploratory dry hole costs


900



27,492



56,483



(6,964
)Accretion of asset retirement obligations


4,155



4,155



4,155



4,155Total operating costs and expenses


1,928,423



1,719,030



1,624,301



1,379,679Income (loss) from operations


601,841



1,272,836



954,703



(29,036
)Interest income


40,034



25,914



18,801



17,069Net income (loss)

$
641,875


$
1,298,750


$
973,504


$
(11,967
)Net income (loss) allocated to partners

$
641,875


$
1,298,750


$
973,504


$
(11,967
)Less:  Managing General Partner interest in net income (loss)


192,563



389,624



292,051



(3,590
)Net income (loss) allocated to Investor Partners

$
449,312


$
909,126


$
681,453


$
(8,377
)Net income (loss) per Investor Partner unit

$
251


$
509


$
381


$
(5
)Investor Partner units outstanding


1,786.78



1,786.78



1,786.78



1,786.78





See accompanying notes to unaudited condensed quarterly financial statements.





F-31
 Index










Statements of Cash Flows

Three Months Ended March 31, 2008


Six Months Ended June 30, 2008


Nine Months Ended September 30, 2008Cash flows from operating activities:Net income (loss)

$
291,906


$
(1,072,033
)

$
4,445,764Adjustments to reconcile net income (loss) to net cash provided by operating activities:Depreciation, depletion and amortization


865,347



1,763,609



2,492,355Accretion of asset retirement obligations


4,451



8,902



13,353Unrealized loss (gain) on derivative transactions


750,318



3,176,251



(1,366,056
)Exploratory dry hole costs


19,440



35,504



71,107Changes in operating assets and liabilities:Increase in accounts receivable


(122,553
)


(469,381
)


308,355Increase in accounts receivable - other


-



(124,555
)


(124,555
)Increase in oil inventory


(34,168
)


(38,735
)


(40,660
)Increase in accounts payable and accrued expenses


121,292



198,697



100,009(Increase) decrease in due from/to Managing General Partner, net


(68,399
)


479,382



521,890Net cash provided by operating activities


1,827,634



3,957,641



6,421,562Cash flows from investing activities:Capital expenditures for oil and gas properties


(3,998
)


(25,891
)


(31,213
)Proceeds from Colorado sales tax refund related to capital purchases


-



124,555



124,555Net cash (used in) provided by investing activities


(3,998
)


98,664



93,342Cash flows from financing activities:Distributions to Partners


(1,814,862
)


(4,040,349
)


(6,487,422
)Net cash used in financing activities


(1,814,862
)


(4,040,349
)


(6,487,422
)Net increase in cash and cash equivalents


8,774



15,956



27,482Cash and cash equivalents, beginning of period


63,599



63,599



63,599Cash and cash equivalents, end of period

$
72,373


$
79,555


$
91,081Supplemental disclosure of non-cash activity:Non-cash well costs - due to Managing General Partner

$
-


$
177,663


$
215,632





See accompanying notes to unaudited condensed quarterly financial statements.





F-32
 Index










Statements of Cash Flows

Three Months Ended March 31, 2007


Six Months Ended June 30, 2007


Nine Months Ended September 30, 2007Cash flows from operating activities:Net income

$
641,875


$
1,940,625


$
2,914,129Adjustments to reconcile net income to net cash provided by operating activities:Depreciation, depletion and amortization


1,302,364



2,407,117



3,434,418Accretion of asset retirement obligations


4,155



8,310



12,465Unrealized loss on derivative transactions


630,130



434,712



475,541Exploratory dry hole costs


900



28,392



84,875Changes in operating assets and liabilities:Decrease in accounts receivable


1,813,779



2,089,060



2,235,761Decrease in accounts payable and accrued expenses


(95,307
)


(136,212
)


(167,821
)Decrease in due from/to Managing General Partner, net


(355,482
)


(449,751
)


(499,007
)Net cash provided by operating activities


3,942,414



6,322,253



8,490,361Cash flows from financing activities:Distributions to Partners


(3,929,281
)


(6,290,470
)


(8,446,705
)Net cash used in financing activities


(3,929,281
)


(6,290,470
)


(8,446,705
)Net increase in cash and cash equivalents


13,133



31,783



43,656Cash and cash equivalents, beginning of period


20,328



20,328



20,328Cash and cash equivalents, end of period

$
33,461


$
52,111


$
63,984Supplemental disclosure of non-cash activity:Asset retirement obligation, with corresponding increase to oil and gas properties

$
6,325


$
6,325


$
6,325





See accompanying notes to unaudited condensed quarterly financial statements.





F-33
 Index







Note 1 - Basis of Presentation





The Rockies Region Private Limited Partnership (the “Partnership” or the “Registrant”) was organized as a limited partnership on December 6, 2005 (date of inception), 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.





The accompanying interim financial statements have been prepared without audit in accordance with accounting principles generally accepted in the Unites States of America for interim financial information and the instructions to Form 10-Q and Regulation S-X, Rule 8-03(a) and (b) of the Securities and Exchange Commission (“SEC”).  Accordingly,
pursuant to certain rules and regulations, certain notes and other financial information included in the accompanying audited financial statements have been condensed or omitted.  In the Partnership’s opinion, the accompanying interim financial statements contain all adjustments (consisting of only normal recurring adjustments) necessary to fairly state the Partnership's financial position and results of operations for the periods presented.  Results of operations for the three months
ended March 31, June 30, September 30, and December 31, 2008 and 2007, respectively, are also not necessarily indicative of the results to be expected for the full year or any other future period.





Note 2 - 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.  The fair value of
the Partnership’s portion of unexpired derivative instruments is recorded on the balance sheet under the captions “Due from Managing General Partner–derivatives” in the case of net unrealized gains or “Due to Managing General Partner–derivatives” in the case of net unrealized losses.  Undistributed oil and natural gas revenues collected by the Managing General Partner from the Partnership’s customers of $1,798,082, $1,618,149, $1,452,023 and $1,244,972
as of March 31, 2007, June 30, 2007, September 30, 2007 and December 31, 2007, respectively, and $1,686,848, $2,114,200, $1,810,922 and $894,254 at March 31, 2008, June 30, 2008, September 30, 2008 and December 31, 2008, respectively, are included in the balance sheet caption “Due from Managing General Partner – other, net.”  The undistributed oil and natural gas revenues at March 31, 2007, June 30, 2007, September 30, 2007 and December 31, 2007 have been reclassified from “Accounts
Receivable” to “Due from Managing General Partner – other, net,” to conform to current year presentation.   Realized gains or losses that have not yet been distributed to the Partnership are included in the balance sheet caption “Due from Managing General Partner-other, net” or “Due to Managing General Partner-other, net,” respectively.  All other unsettled transactions between the Partnership and the Managing General Partner are also recorded
net on the balance sheet under the caption “Due from (to) Managing General Partner – other, net.”





The following table presents transactions with the Managing General Partner and its affiliates during the quarters ended March 31, June 30, September 30 and December 31, for the years 2008 and 2007:





Quarter EndedMarch 31, 2008


June 30, 2008


September 30, 2008


December 31, 2008TransactionWell charges

$
80,001


$
78,503


$
79,502


$
80,500Supplies and equipment


271,061



226,363



229,982



255,907Gathering, compression and processing fees


54,841



75,587



59,466



53,765Direct costs- general and administrative


38,691



173,687



112,655



107,264Cash distributions*


538,467



667,646



734,121



542,028Quarter EndedMarch 31, 2007


June 30, 2007


September 30, 2007


December 31, 2007TransactionWell charges

$
77,987


$
78,104


$
77,604


$
84,993Supplies and equipment


163,498



199,601



125,948



150,921Gathering, compression and processing fees


97,985



77,695



74,752



46,683Direct costs- general and administrative


403



75,178



430



25,268Cash distributions*


1,178,783



690,693



623,868



586,281





*Distributions commenced in July 2006.





F-34
 Index







Note 3 - Derivative Financial Instruments





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, 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.





·
For swap instruments, if the market price is below the fixed contract price, PDC, as Managing General Partner, receives the market price from the purchaser and receives the difference between the market price and the fixed contract price from the counterparty.  If the market price is above the fixed contract price, PDC, as Managing General Partner, receives the market price from the purchaser and pays the
difference between the market price and the fixed contract price to the counterparty.





·
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 fixed call strike price, PDC, as Managing General Partner, receives the market price from the purchaser and pays the difference between the call strike price and market price to the counterparty.  If the market falls below the fixed put strike price, PDC, as Managing General Partner, receives the
market price from the purchaser and receives the difference between the put strike price and market price from the counterparty.  If the market price is between the call and the put strike price, no payments are due from either party.





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





The Managing General Partner enters into derivative instruments for Partnership production to reduce the impact of price declines in future periods.  While these derivatives are structured to reduce 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.





F-35
 Index







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.  During 2008 and 2007,
at the end of the three month periods noted below, 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.





As ofMarch 31, 2008


June 30, 2008


September 30, 2008


December 31, 2008Derivative net assets (liabilities)Oil and gas sales activities:Fixed-price natural gas swaps

$
(586,753
)

$
(1,526,466
)

$
998,337


$
928,735Oil collars


(112,983
)


-



-



-Natural gas collars


(64,357
)


(77,037
)


545,005



966,019Natural gas basis protection swaps


-



-



-



(146,176
)Fixed-price oil swaps


(366,412
)


(1,952,935
)


(557,472
)


1,500,101Estimated net fair value of derivative instruments

$
(1,130,505
)

$
(3,556,438
)

$
985,870


$
3,248,679As ofMarch 31, 2007


June 30, 2007


September 30, 2007


December 31, 2007Derivative net assets (liabilities)Oil and gas sales activities:Natural gas collars

$
(92,159
)

$
492,364


$
403,427


$
71,282Natural gas floors


481,671



96,469



145,076



1,309Oil floors


4,437



535



36



-Fixed-price oil swaps


-



-



-



(452,778
)Estimated net fair value of derivative instruments

$
393,949


$
589,368


$
548,539


$
(380,187
)





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





F-36
 Index







The following table identifies the fair value of commodity based derivatives as classified in the Partnership’s balance sheets at March 31, June 30, September 30 and December 31, 2008 and 2007 respectively:





As ofMarch 31, 2008


June 30, 2008


September 30, 2008


December 31, 2008Classification in the Balance SheetsFair value of current assetsDue from Managing General Partner-derivatives, net

$
32,677


$
-


$
1,135,360


$
2,465,581Fair value of other assets-long termDue from Managing General Partner-derivative, net


48,057



-



489,821



929,27580,734



-



1,625,181



3,394,856Fair value of current liabilitiesDue to Managing General Partner-derivatives, net


(958,887
)


(2,532,468
)


(321,805
)


-Fair value of other liabilities-long termDue to Managing General Partner-derivatives, net


(252,352
)


(1,023,970
)


(317,507
)


(146,177
)(1,211,239
)


(3,556,438
)


(639,312
)


(146,177
)Net fair value of commodity based derivatives- asset (liability)

$
(1,130,505
)

$
(3,556,438
)

$
985,869


$
3,248,679As ofMarch 31, 2007


June 30, 2007


September 30, 2007


December 31, 2007Classification in the Balance SheetsFair value of current assetsDue from Managing General Partner-derivatives, net

$
393,949


$
506,410


$
519,895


$
-Fair value of other assets-long termDue from Managing General Partner-derivatives, net


-



82,958



28,644



-393,949



589,368



548,539



-Fair value of current liabilitiesDue to Managing General Partner-derivatives, net


-



-



-



(380,187
)-



-



-



(380,187
)Net fair value of commodity based derivatives- asset (liability)

$
393,949


$
589,368


$
548,539


$
(380,187
)





The following table identifies the changes in the fair value of commodity based derivatives as reflected in the Partnership’s statements of operations for the three-months ended March 31, June 30, September 30 and December 31 for the years indicated:





Quarter EndedMarch 31, 2008


June 30, 2008


September 30, 2008


December 31, 2008Realized gains (losses)Oil

$
(72,794
)

$
(175,769
)

$
(126,619
)

$
232,209Natural gas


(41,824
)


(474,076
)


151,747



621,942Total realized gain (loss), net


(114,618
)


(649,845
)


25,128



854,151Unrealized gain (loss)


(750,318
)


(2,425,933
)


4,542,308



2,262,809Oil and gas price risk management gain (loss), net

$
(864,936
)

$
(3,075,778
)

$
4,567,436


$
3,116,960Quarter EndedMarch 31, 2007


June 30, 2007


September 30, 2007


December 31, 2007Realized gains (losses)Oil

$
(9,851
)

$
(8,483
)

$
(2,868
)

$
(2,949
)Natural gas


(7,808
)


134,214



264,811



138,005Total realized gain (loss), net


(17,659
)


125,731



261,943



135,056Unrealized gain (loss)


(630,131
)


195,419



(40,829
)


(928,726
)Oil and gas price risk management gain (loss), net

$
(647,790
)

$
321,150


$
221,114


$
(793,670
)





F-37
 Index







Note 4 - Fair Value of Financial Instruments





Derivative Financial Instruments





The Partnership adopted the provisions 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.





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.





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.  Fair value Level 3 inputs areunobservable 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 following table presents the Partnership’s assets and liabilities including both current and non-current portions, measured at fair value on a recurring basis for the three months ended March 31, June 30, September 30 and December 31, 2008:





Level 3Quarter endedMarch 31, 2008


June 30, 2008


September 30, 2008


December 31, 2008Assets:Commodity based derivatives

$
80,734


$
-


$
1,625,181


$
3,394,856Liabilities:Commodity based derivatives


(1,211,239
)


(3,556,438
)


(639,312
)


(146,177
)Net fair value of commodity based derivatives

$
(1,130,505
)

$
(3,556,438
)

$
985,869


$
3,248,679





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 3 for additional disclosure related to the Partnership’s derivative financial instruments.





Three months EndedMarch 31, 2008


June 30, 2008


September 30, 2008


December 31, 2008Fair value, net (liability) asset, beginning of period

$
(380,187
)

$
(1,130,505
)

$
(3,556,438
)

$
985,869Realized and unrealized losses included in oil and gas price risk management gain (loss), net


(864,936
)


(3,075,778
)


4,567,436



3,116,960Purchases, sales, issuances and settlements, net


114,618



649,845



(25,129
)


(854,150
)Fair value, net (liability) asset, end of period

$
(1,130,505
)

$
(3,556,438
)

$
985,869


$
3,248,679





The Managing General Partner’s valuation determination also gives consideration to the nonperformance risk on Partnership liabilities.  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.





F-38
 Index







Note 5 - Capitalized Costs Relating to Oil and Gas Activities





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 December 30, 2005 with payments made for all planned drilling and completion costs for the Partnership made in December 2005.  Costs capitalized
for these activities are as follows:





As ofMarch 31, 2008


June 30, 2008


September 30, 2008


December 31, 2008Leasehold costs

$
459,554


$
459,554


$
459,554


$
459,554Development costs


40,342,313



40,623,288



40,630,976



40,699,284Oil and gas properties, successful efforts method


40,801,867



41,082,842



41,090,530



41,158,838Drilling advances to Managing General Partner


222,038



-



-



-Oil and gas properties, at cost


41,023,905



41,082,842



41,090,530



41,158,838Less:  Accumulated depreciation, depletion and amortization


(11,053,854
)


(11,952,116
)


(12,680,862
)


(13,572,027
)Oil and gas properties, net

$
29,970,051


$
29,130,726


$
28,409,668


$
27,586,811As ofMarch 31, 2007


June 30, 2007


September 30, 2007


December 31, 2007Leasehold costs

$
454,873


$
459,380


$
459,398


$
459,554Development costs


36,927,159



39,488,163



39,571,485



40,326,237Oil and gas properties, successful efforts method


37,382,032



39,947,543



40,030,883



40,785,791Wells in progress


2,711,435



-



-



-Drilling advances to Managing General Partner


1,022,892



1,141,323



1,001,500



253,556Oil and gas properties, at cost


41,116,359



41,088,866



41,032,383



41,039,347Less:  Accumulated depreciation, depletion and amortization


(7,180,026
)


(8,284,779
)


(9,312,080
)


(10,188,507
)Oil and gas properties, net

$
33,936,333


$
32,804,087


$
31,720,303


$
30,850,840





“Drilling advances to Managing General Partner” represent unused prepayments to the Managing General Partner for the development of oil and gas properties which will be used for future capital costs.  Development costs include the Partnership’s asset retirement obligations.





Note 6 - 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.





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.  Based on the mediation held on May 28, 2008, and subsequent negotiations, $74,412 was accrued by the Partnership for this litigation for the year ended December 31, 2007.  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 38 wells in the Wattenberg field.





F-39
 Index







On October 10, 2008, the court issued preliminary approval of the settlement agreement.  The portion of the proposed settlement plus legal fees related to the Partnership’s wells at June 30, 2007, September 30, 2007, December 31, 2007, March 31, 2008, June 30, 2008, September 30, 2008 and December 31, 2008 was $74,412,
$74,412, $74,412, $82,806, $89,521, $99,304 and $110,932, respectively.  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 was approved by the court at a hearing on April 7, 2009.






F-40