Attached files

file filename
EX-23.1 - EXHIBIT 23.1 - PDC 2004-B Limited Partnershipex23_1.htm
EX-32.1 - EXHIBIT 32.1 - PDC 2004-B Limited Partnershipex32_1.htm
EX-31.1 - EXHIBIT 31.1 - PDC 2004-B Limited Partnershipex31_1.htm
EX-31.2 - EXHIBIT 31.2 - PDC 2004-B Limited Partnershipex31_2.htm


UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, DC 20549
 
FORM 10-K

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

For the fiscal year ended December 31, 2008
 or
o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission File Number  000-51219
PDC 2004-B Limited Partnership
(Exact name of registrant as specified in its charter)
   
West Virginia
20-0547318
(State or other jurisdiction of incorporation or organization)
(I.R.S. Employer Identification No.)
   
1775 Sherman Street, Suite 3000, Denver, Colorado  80203
(Address of principal executive offices)     (Zip code)

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

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

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

Title of Each Class
Limited Partnership Interests

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

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

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 229.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes o  No o

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

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

Large accelerated filer     o
Accelerated filer     o
   
Non-accelerated filer     o
Smaller reporting company     x

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

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

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

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


 
 

 

PDC 2004-B LIMITED PARTNERSHIP
INDEX TO REPORT ON FORM 10-K
 
   
Page
 
PART I
 
     
 
1
Item 1
2
Item 1A
13
Item 1B
21
Item 2
21
Item 3
22
Item 4
23
     
 
PART II
 
     
Item 5
23
Item 6
24
Item 7
24
Item 7A
38
Item 8
40
Item 9
40
Item 9A(T)
40
Item 9B
43
     
 
PART III
 
     
Item 10
44
Item 11
47
Item 12
48
Item 13
48
Item 14
49
     
 
PART IV
 
     
Item 15
49
   
51
   
F-1
 
 

Explanatory Note to Comprehensive Annual Report

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

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

Special Note Regarding Forward Looking Statements

This Annual Report contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 (the “Securities Act”) and Section 21E of the Securities Exchange Act of 1934 (the “Exchange Act”) regarding PDC 2004-B Limited Partnership’s (the “Partnership’s” or the “Registrant’s”) business, financial condition, 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’s Petroleum Development Corporation’s (“MGP’s” or “PDC’s”) strategies, plans and objectives.  However, these are not the exclusive means of identifying forward-looking statements herein.  Although forward-looking statements contained in this report reflect the Managing General Partner's good faith judgment, such statements can only be based on facts and factors currently known to them.  Consequently, forward-looking statements are inherently subject to risks and uncertainties, including risks and uncertainties incidental to the development, production and marketing of natural gas and oil, and actual outcomes may differ materially from the results and outcomes discussed in the forward-looking statements. Important factors that could cause actual results to differ materially from the forward looking statements include, but are not limited to:

 
·
changes in production volumes, worldwide demand, and commodity prices for oil and natural gas;
 
·
risks incident to the operation of natural gas and oil wells;
 
·
future production and development costs;
 
·
the availability of sufficient pipeline and other transportation facilities to carry Partnership production and the impact of these facilities on price;
 
·
the effect of existing and future laws, governmental regulations and the political and economic climate of the United States of America (“U.S.”) and the impact of the global economy;
 
·
the effect of natural gas and oil derivatives activities;
 
·
availability and cost of capital and conditions in the capital markets; and
 
·
losses possible from pending and/or future litigation and the costs incident thereto.

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

- 1 -


Business
 
General

The Partnership was organized as a limited partnership on July 28, 2004 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 its public sale of its Partnership units on July 28, 2004, the Partnership was funded and commenced its business operations. The Partnership was funded with initial contributions of $18.0 million from 670 limited and additional general partners (collectively, the “Investor Partners”) and a cash contribution of $4.0 million from the Managing General Partner for its interest.  After payment of syndication costs of $1.8 million and a one-time management fee to the Managing General Partner of $0.3 million, the Partnership had available cash of $19.9 million to commence Partnership activities.  Upon funding, the Partnership entered into a Drilling and Operating Agreement (“D&O Agreement”) with the Managing General Partner which governs the drilling and operational aspects of the Partnership.  The Partnership owns an undivided working interest in natural gas and oil wells located in Colorado from which the Partnership produces and sells natural 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 July 28, 2004.  Drilling operations were completed in March 2005 when the last of the Partnership’s 23 development wells were connected to sales and gathering pipeline.  The Partnership’s 23 gross wells represent 20.9 net wells, or the number of gross wells multiplied by the working interest in the wells owned by the Partnership.  All of the drilled wells are located in Colorado and all wells drilled are completed and producing as of December 31, 2008.  The Partnership’s wells are considered developmental wells. Therefore, no exploratory drilling activity was conducted on behalf of the Partnership.

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

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

 
a)
The cost of the prospect; and

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

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

Business Segments

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

- 2 -


Plan of Operations

With regard to the Partnership’s developmental wells drilled in Colorado, 16 wells were drilled in the Wattenberg Field and seven wells were drilled in the Grand Valley Field.

The 16 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 located within the Denver-Julesburg (DJ) Basin.  Wells in the DJ 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 formation, which produces a combination of natural gas and oil.

The seven 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 into 10 to 15 different zones.  The production zones are separated by layers of nonproductive shale resulting in a total production 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 displays 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.

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

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 D&O Agreement.  Upon completion of the drilling of all of the Partnership wells, these assignments are recorded in the applicable county.  Investor Partners rely on PDC to use its best judgment to obtain appropriate title to these working interests.  Provisions of the Limited Partnership Agreement (the “Agreement”), generally relieve PDC from errors in judgment with respect to the waiver of title defects.  PDC takes those steps it deems necessary to assure that title to the working interests is acceptable for purposes of the Partnership.  For additional information, see Item 2, Properties – Title to Properties.

- 3 -


Well Operations

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

PDC, may in certain circumstances, provide equipment and supplies, and perform 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.  The transmission and gathering lines, which are owned either by PDC or other third parties and which transport the Partnership's natural gas production, are subject to seasonal curtailment and occasional limitations due to repairs, improvements or as a result of priority transportation agreements with other natural gas transporters.  Seasonal curtailment typically occurs during July and August as a result of high atmospheric temperatures which reduce compressor capacity.  This reduction in production typically amounts to less than five percent of normal monthly production.  The cost, timing and availability of gathering pipeline connections and service varies from area to area, well to well, and over time.  When a significant amount of development work is being done in an area, production can temporarily exceed the available markets and pipeline capacity to move natural gas to more distant markets.  This excess supply can lead to lower natural gas prices relative to other areas as the producers compete for the available markets by reducing prices.  This excess supply can also lead to curtailments of production and periods when wells are shut-in due to lack of market.

Sale of Production.  In accordance with the D&O Agreement, PDC markets the oil and natural gas produced from the Partnership’s wells on a competitive basis, at what it believes to be, the best available terms and prices generally, under contracts with indexed monthly pricing provisions.  PDC does not enter into any commitment of future production that does not directly 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 multi-year contracts requiring the dedication of the natural gas produced from a well for a period ranging up to the life of the well.

The gas is sold at negotiated prices based upon a number of factors, including the quality of the gas, well pressure, estimated remaining reserves, prevailing supply conditions and any applicable price regulations promulgated by the Federal Energy Regulatory Commission, or FERC.  The Partnership sells oil produced by its wells 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 oil and natural gas from the Partnership’s wells without significant curtailment and at locally competitive prices.  The Partnership does experience limited curtailments from time to time due to pipeline maintenance and operating issues as discussed above.  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.

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

- 4 -


The sale of the Partnership’s production is subject to market 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.  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 June 30, 2009, the Partnership has oil and natural gas derivatives in place covering 71% of its expected oil production and 79% of its expected natural gas production for the remainder of 2009.

The Partnership utilizes 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 recorded 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, 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 the market price from the purchaser and the difference between the market price and floor price from the counterparty if the commodity market price falls below the floor strike price, but receives no payment when the commodity market price exceeds the floor price.  For “swap” instruments, if the market price is below the fixed contract price, PDC, as Managing General Partner, receives the market price from the purchaser and receives the difference between the market price and the fixed contract price from the counterparty.  If the market price is above the fixed contract price, PDC, as Managing General Partner, receives the market price from the purchaser and pays the difference between the market price and the fixed contract price to the counterparty.  “Collars” contain a fixed floor price (put) and ceiling price (call).  If the market falls below the fixed put strike price, PDC, as Managing General Partner, receives the market price from the purchaser and receives the difference between the put strike price and market price from the counterparty.  If the market price exceeds the fixed call strike price, PDC, as Managing General Partner, receives the market price from the purchaser and pays the difference between the call strike price and market price to the counterparty.  If the market price is between the call and put strike price, no payments are due to or from the counterparty.  Finally, “basis protection swaps” are arrangements that guarantee a price differential for natural gas valued at a specified pricing point, or hub.  For Partnership CIG basis protection swaps that have a negative pricing differential to NYMEX, PDC as Managing General Partner receives a payment from the counterparty if the price differential is greater than the stated terms of the contract and pays the counterparty if the price differential is less than the stated terms of the contract.  See Item 1A, Risk Factors - The Partnership's derivative activities could result in reduced future revenue and cash flows compared to the level the Partnership might experience if no derivative instruments were in place.

The Partnership participates on a pro-rata basis, in all derivative transactions entered into by the Managing General Partner in a given area.  The Partnership’s allocation of derivative positions is based on the Partnership’s percentage of estimated production to total estimated production from a given area on a monthly basis.  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 this Partnership, changed on a pro-rata basis.  As of September 30, 2008, the allocation of derivative positions was fixed, based on the estimated future production at this date, between the Managing General Partner’s corporate interests and each sponsored drilling partnership.  For positions entered into subsequent to September 30, 2008, specific designations of the quantities between the Managing General Partner’s corporate interests and each sponsored drilling partnership, including this Partnership, are allocated and fixed at the time the positions are entered into based on estimated future production.  The Partnership believes that in a rapidly changing price environment, derivative positions are desirable to obtain more predictable cash flows and to reduce the impact of possible future price declines.

- 5 -


D&O Agreement.  The Partnership has entered into the D&O Agreement with PDC.  The D&O 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.  Generally, an operator has limited 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 D&O Agreement, PDC may subcontract certain functions 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 receives 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.

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

Under the D&O Agreement 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.  In accordance with the D&O Agreement, the Partnership designated PDC as its agent to market its production and authorized the operator to enter into and bind the Partnership in those agreements as it deems in the best interest of the Partnership for the sale of its oil and/or natural gas.  Where pipelines owned by PDC are used in the delivery of natural gas to market, PDC charges a market rate gathering fee not to exceed that which would be charged by a non-affiliated third party for a similar service.

The D&O Agreement remains in force as long as any well or wells produce, or are capable of economic production, and for an additional period of 180 days from cessation of all production, or until PDC is replaced as Managing General Partner as provided for in the D&O Agreement.

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 currently being conducted with regard to each of the 23 productive wells.

PDC markets the Partnership’s natural gas to commercial end users, interstate or intrastate pipelines or local utilities, primarily under market sensitive contracts in which the price of natural gas sold varies as a result of market forces.  Some leases, and thus the natural gas derived from wells drilled on those leases, may have been dedicated to particular markets at the time the Partnership drilled wells on such leases, or subsequent to, as part of the natural gas marketing arrangements.  In general, the Partnership has been, and expects to continue to be able to, produce and sell natural gas from Partnership wells without significant curtailment and at competitive prices.  The Partnership does experience limited curtailments from time to time due to pipeline maintenance and operating issues of the pipeline operators.  For instance, the Partnership experienced an approximate 10% to 15% curtailment of production volumes in the Piceance Basin due to limited compression and pipeline capacity throughout most of the fourth quarter in 2008.  This interruption, due to third party infrastructure, was corrected in early 2009.

The majority of the Partnership’s wells in the Wattenberg Field in Colorado produce oil in addition to natural gas.  The Managing General Partner is currently able to sell all the oil that the Partnership can produce under existing sales contracts with petroleum refiners and marketers.  The Partnership does not refine any of its oil production.  The Partnership’s crude oil production is sold to purchasers at or near the Partnership’s wells under both short and long-term purchase contracts with monthly pricing provisions.

- 6 -


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

Seasonal factors, such as effects of weather on prices received and costs incurred, and availability of pipeline capacity, may impact the Partnership's results of operations.  In addition, both sales volumes and prices are subject to demand factors with a 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.

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 insufficient to render full payment and a liability is recorded by the Partnership.

- 7 -


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

Definitions used throughout Item 1, Business:
 
·
Bbl – One barrel or 42 U.S. gallons liquid volume
 
·
MBbl – One thousand barrels
 
·
Mcf – One thousand cubic feet
 
·
Mcfe – One thousand cubic feet of natural gas equivalents, based on a ratio of 6 Mcf for each barrel of oil, which reflect the relative energy content
 
·
MMcf – One million cubic feet
 
·
MMcfe – One million cubic feet of natural gas equivalents

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

The Partnership utilizes commodity based derivative instruments to manage a portion of its exposure to commodity 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 OperationsProduction and Operating Costs.

- 8 -


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 Company, L.P.  Reserves cannot be measured exactly, because reserve estimates involve subjective judgment.  The estimates are reviewed periodically and adjusted to reflect additional information gained from reservoir performance data, new geological and geophysical data and economic changes.  Neither the present value of estimated future net cash flows nor the standardized measure is intended to represent the current market value of the estimated oil and natural gas reserves which the Partnership owns.  The Partnership’s estimated proved undeveloped reserves represent the reserves attributable to the planned future recompletion of the Codell formation in the 16 Wattenberg Field wells.

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

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

Estimated future net cash flows represent the estimated future gross revenues expected 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 $38.33 per barrel of oil and $4.70 per Mcf of natural gas.  These prices should not be interpreted as a prediction of future prices, nor do they reflect the value of the Partnership’s commodity hedges in place at December 31, 2008.  The amounts shown do not give effect to non-property related expenses, such as direct costs - general and administrative expenses, or to depreciation, depletion and amortization.

The standardized measure of discounted future net cash flows is calculated in accordance with Statement of Financial Accounting Standards, or 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.

- 9 -


Insurance

PDC, in its capacity as operator, has purchased well pollution, public liability and worker’s compensation insurance policies for its own benefit as well as the benefit of the Partnership, however insurance may not be sufficient to cover all potential liabilities.  Each partner who chose to participate as an additional general partner had potential unlimited liability for unforeseen events such as blowouts, lost circulation, and stuck drill pipe, occurring prior to converting to limited partners, which could result in unanticipated additional liability materially in excess of the per unit subscription amount.  However, upon conversion to limited partners on February 8, 2005, all investor partners’ liability became limited.  The remaining general partner is PDC, also the Managing General Partner.
 
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 named 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 the subcontractors’ activities.  In the event of a loss due to the subcontractors’ performance, the insurance policies of the particular subcontractor at risk may 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 PDC owned or leased 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, recompletions and reworks.  PDC has maintained liability insurance, including umbrella liability insurance, of at least two times the Partnership’s capitalization, up to a maximum of $50 million, but in no event less than $10 million during drilling or recompletion operations.

Competition and Markets

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

The marketing of any oil and natural gas produced by the Partnership is affected by a number of factors which are beyond the Partnership's control and the exact effect of which cannot be accurately predicted.  These factors include the volume and prices of crude oil imports, the availability and cost of adequate pipeline and other transportation facilities, the marketing of competitive fuels, such as coal and nuclear energy, and other matters affecting the availability of a ready market, such as fluctuating supply and demand.  Among other factors, the supply and demand balance of crude oil and natural gas in world markets may have caused significant variations in the prices of these products over recent years.

- 10 -


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 increased the demand for natural gas.

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

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”), 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 Williams or other pipelines.  As a result of FERC regulations that require interstate gas pipeline companies to separate their merchant activities from their transportation activities and require these companies to release available capacity on both a short and a long-term basis, local distribution companies have taken an increasingly active role in acquiring their own natural gas supplies.  Consequently, pipelines and local distribution companies (utilities) are buying natural gas directly from natural gas producers and marketers, and retail unbundling efforts are causing many end-users to buy their own reserves.  Activity by state regulatory commissions to review local distribution company procurement practices more carefully and to unbundle retail sales from transportation has caused natural gas purchasers to minimize their risks in acquiring and attaching natural gas supply and has increased competition in the natural gas marketplace.

Natural Gas and Oil Pricing

PDC markets the natural gas and oil from Partnership wells in Colorado subject to market sensitive contracts, the price of which increases or decreases with market forces beyond control of the Partnership.  Currently, PDC sells Partnership gas in the Piceance Basin to Williams, which has an extensive gathering and transportation system in the field.  In the Wattenberg Field, the gas is sold primarily to DCP, which gathers and processes the gas and liquefiable hydrocarbons produced.  Natural gas produced in Colorado may be impacted by changes in market prices on a national level, as well as changes in the market for natural gas within the Rocky Mountain Region.  Sales may be affected by capacity interruptions on pipelines transporting natural gas out of the region.

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

- 11 -


Governmental Regulation

While the prices of oil and natural gas are set by the market, other aspects of the Partnership's business and the oil and natural gas industry in general are heavily regulated.  The availability of a ready market for oil and natural gas production depends on several factors beyond the Partnership's control.  These factors include regulation of production, federal and state regulations governing environmental quality and pollution control, the amount of oil and natural gas available for sale, the availability of adequate pipeline and other transportation and processing facilities and the marketing of competitive fuels.  State and federal regulations generally are intended to protect consumers from unfair treatment and oppressive control, to reduce the risk to the public and workers from the drilling, completion, production and transportation of oil and natural gas, to prevent waste of oil and natural gas, to protect rights of owners in a common reservoir and to control contamination of the environment.  Pipelines are subject to the jurisdiction of various federal, state and local agencies.  PDC management, as Managing General Partner, believes that the Partnership is in compliance with such statutes, rules, regulations and governmental orders, although there can be no assurance that this is or will remain the case.  The following summary discussion of the regulation of the United States oil and natural gas industry is not intended to constitute a complete discussion of the various statutes, rules, regulations and environmental orders to which the Partnership's operations may be subject.

Environmental Regulation

The Partnership’s operations are subject to numerous laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection.  Public interest in the protection of the environment has increased dramatically in recent years.  The trend of more expansive and tougher environmental legislation and regulations could continue.  To the extent laws are enacted or other governmental action is taken that restricts drilling or imposes environmental protection requirements that result in increased costs and reduced access to the natural gas industry in general, our business and prospects could be adversely affected.  In December 2008, the State of Colorado’s Oil and Gas Conservation Commission finalized new broad-based wildlife protection and environmental regulations for the oil and natural gas industry which are expected to increase the Partnership’s well recompletion costs and ongoing level of production and operating costs.  Partnership expenses relating to preserving the environment have risen over the past two years and are expected to continue in 2009 and beyond.  While environmental regulations have had no materially adverse effect on its operations to date, no assurance can be given that environmental regulations or interpretations of such regulations will not in the future, result in a curtailment of production or otherwise have a materially adverse effect on Partnership operations.

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

Proposed Regulation

Various legislative proposals and proceedings that might affect the petroleum and natural gas industries occur frequently in Congress, FERC, state commissions, state legislatures, and the courts.  These proposals involve, among other things, imposition of direct or indirect price limitations on natural gas production, expansion of drilling opportunities in areas that would compete with Partnership production, imposition of land use controls, landowners' "rights" legislation, alternative fuel use requirements and/or tax incentives and other measures.  The petroleum and natural gas industries historically has been very heavily regulated; therefore, there is no assurance that the less stringent regulatory approach recently pursued by FERC and Congress will continue.  The Partnership cannot determine to what extent its future operations and earnings will be affected by new legislation, new regulations, or changes in existing regulation, at federal, state or local levels.

- 12 -


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 the Partnership 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, criminal proceedings 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.

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, which the Partnership electronically files with the SEC.  The address of that site is http://www.sec.gov.  The Central Index Key, or CIK, for the Partnership is 0001306758.  You can read and copy any materials the Partnership files with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Room 1850, Washington, D.C.  20549.  You may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330.

Risk Factors

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

Risks Related to the Global Economic Crisis

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

- 13 -


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.  Any of the above factors could adversely affect the Partnership’s operating results and reduce cash distributions to the Investor Partners.  For more information regarding the Wattenberg Field recompletion plan, see Item 1 BusinessPlan of Operation.

Risks Pertaining to Natural Gas and Oil Investments

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

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

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

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

- 14 -


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

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

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

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

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

- 15 -


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

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

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

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

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

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

- 16 -


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

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

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

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

- 17 -


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

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

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

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

- 18 -


Special Risks of an Investment in the Partnership

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

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

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

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

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

- 19 -


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

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

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

The Managing General Partner, with respect to its own corporate interests, the Partnership and various other limited partnerships sponsored by the Managing General Partner, have been delinquent in filing periodic reports with the SEC.  Consequently, Investor Partners are unable to review the delinquent partnerships’ respective financial statements as a source of information for evaluating their investment in the Partnership.  PDC, as an actively operating corporation, and various limited partnerships which PDC has sponsored and for which PDC serves as the Managing General Partner are subject to reporting requirements of the Exchange Act and are obligated to file annual and quarterly reports with the SEC in accordance with the rules of the SEC.  In the course of preparing corporate financial statements for the quarter ended June 30, 2005, PDC identified accounting errors in its prior period financial statements.  As a result, on October 17, 2005, PDC’s Board of Directors, Audit Committee and management concluded that PDC’s previously issued financial statements could not be relied upon and would be restated.  PDC, as Managing General Partner, made similar determinations regarding the financial statements of certain of the limited partnerships which are subject to the Exchange Act reporting obligations.
 
Since June 2007, PDC has become compliant with its corporate Exchange Act filing and reporting obligations. Additionally, Rockies Region 2007 Limited Partnership, Rockies Region 2006 Limited Partnership, PDC 2005-A Limited Partnership, PDC 2005-B Limited Partnership, Rockies Region Private Limited Partnership, PDC 2004-A Limited Partnership and PDC 2004-D Limited Partnership have completed all required SEC filings through June 30, 2009.  PDC 2004-B Limited Partnership (with this filing) has completed all required SEC filings through December 31, 2008, but is delinquent on all subsequent quarterly filing requirements.  PDC 2004-C Limited Partnership has completed all required SEC filings through December 31, 2007, but is delinquent on all subsequent quarterly and annual filing requirements.  All remaining limited partnerships sponsored by PDC which are subject to the Exchange Act have been, and continue to be, delinquent in filing their respective periodic reports in accordance with the requirements of the Exchange Act.  Until these partnerships file their delinquent periodic reports, investors will be unable to review the financial statements of the various limited partnerships as an additional source of information they can use in their evaluation of their investment in the Partnership.  Currently the Managing General Partner has in place a compliance effort addressing the delinquent reports of the various limited partnerships.  However, due to the amount of effort, time and financial resources required to bring the limited partnerships into compliance with Exchange Act periodic reporting requirements, the Partnership and the various limited partnerships may be unable to bring their delinquent reports current and may be unable in the future to file their required periodic reports with the Securities and Exchange Commission in a timely manner.

- 20 -


Unresolved Staff Comments

None

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 23 wells drilled by the Partnership.  The acreage associated with the spacing units is designated by state rules and regulations in conjunction with local practice.  See the section titled Item 1, Business Drilling Activities and Plan of Operations for additional information on the Partnership’s properties.

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

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

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

Production

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

- 21 -


Oil and Natural Gas Reserves

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

Title to Properties

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

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

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

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.

- 22 -


Submission of Matters to a Vote of Security Holders

None

PART II

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

At September 30, 2009, the Partnership had 664 Investor Partners holding 899.94 units and one Managing General Partner.  The investments held by the Investor Partners are in the form of limited partnership interests.  Investor Partners' interests are transferable; however, no assignee of units in the Partnership can become a substituted partner without the written consent of the transferor and the Managing General Partner.  As of June 30, 2009, the Managing General Partner has repurchased 17.02 units of Partnership interests from Investor Partners.

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

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

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

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

- 23 -


Unit Repurchase Program.  Beginning with the third anniversary of the date of the first cash distribution of the Partnership, Investor Partners of the Partnership may request the Managing General Partner to repurchase their units. The Partnership initiated monthly cash distributions to Investor Partners in February 2005.  If requested by individual investor partners, the Managing General Partner is conditionally obligated to purchase in any calendar year units which aggregate up to 10% of the initial subscriptions.  Repurchase of units is subject to PDC’s financial ability to purchase the units.  The purchase price will not be less than four times the most recent twelve months’ cash distributions from production of the Partnership.
 
In the first quarter of 2008, the Managing General Partner repurchased a total of 0.5 units during February 2008, the first month unit repurchases were eligible under the program, at an average price of $9,230 per unit and 0.25 units during March 2008 at an average price of $7,340 per unit.  Second quarter unit repurchases included the April 2008 repurchase of 0.5 units at an average price per unit of $7,330 and May 2008 repurchases of 0.25 units at an average price per unit of $7,520.  Remaining 2008 repurchases were comprised of fourth quarter repurchases of 1.0 unit at an average price of $9,295 per unit in October and 2.5 units at an average price of $9,748 per unit in December.  First quarter 2009 unit repurchases include 1.0 unit repurchased at an average price of $10,345 per unit during February and 0.5 units repurchased at an average price of $10,670 per unit during March.  Second quarter repurchases in April 2009, were 4.25 units repurchased at an average price of $10,794 per unit.  There have been no third quarter unit repurchases through July 2009.
 
In addition to the above repurchase program, individual investor partners periodically offer and PDC repurchases units on a negotiated basis before the third anniversary of the date of the first cash distribution.

Selected Financial Data

Not applicable

Management’s Discussion and Analysis of Financial Condition and Results of Operations

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

Overview

The Partnership was funded on July 2, 2004 with initial contributions of $18.0 million from the Investor Partners and a cash contribution of $4.0 million from the Managing General Partner.  After payment of syndication costs of $1.8 million and a one-time management fee to PDC of $0.3 million, the Partnership had available cash of $19.9 million to commence Partnership oil and natural gas well drilling activities.

The Partnership began exploration and development activities immediately after funding.  In July 2004, PDC commenced drilling on behalf of the Partnership.  As of December 31, 2008, a total of 23 wells have been drilled in Colorado, all of which are producing.  These 23 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 fourth quarter of 2004 as wells were connected to pipelines.  Production and sales increased through the first two quarters of 2005 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 generally, 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 and the availability of additional geological data and technology.  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.

- 24 -


2008 Overview

The year 2008 was a year of significant events: oil and natural gas prices reached to 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 decreased approximately 50%.  While the Partnership 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 price impacts while capitalizing on the positive impacts of price risk management using derivatives.  The Partnership’s derivative position eased the impact of the fall in oil and natural gas prices.  During 2008, the Partnership recorded $0.1 million in net realized derivative gains.  Further, the Partnership estimates the net fair value of its derivative positions as of December 31, 2008 to be $1.2 million.

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

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

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

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

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

- 25 -


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, production and operating costs, depreciation, depletion and amortization costs, other operating income and expenses for the years ended December 31, 2008 and 2007.

   
Year Ended
   
Year Ended
       
   
December 31, 2008
   
December 31, 2007
   
Change
 
Number of producing wells (end of period)
    23       23       -  
                         
Production:  (1)
                       
Oil (Bbl)
    9,672       12,961       -25 %
Natural gas (Mcf)
    446,018       463,307       -4 %
Natural gas equivalents (Mcfe)  (2)
    504,050       541,073       -7 %
                         
Average Selling Price (excluding realized gain (loss) on derivatives)
                       
Oil (per Bbl)
  $ 89.15     $ 58.04       54 %
Natural gas (per Mcf)
    6.51       4.89       33 %
Natural gas equivalents (per Mcfe)
    7.47       5.58       34 %
                         
Realized Gain (Loss) on Derivatives, net
                       
Oil derivatives - realized loss
  $ (45,042 )   $ (3,604 )     *  
Natural gas derivatives - realized gain
    115,356       175,512       -34 %
Total realized gain on derivatives, net
  $ 70,314     $ 171,908       -59 %
                         
Average Selling Price (including realized gain (loss) on derivatives)
                       
Oil (per Bbl)
  $ 84.49     $ 57.76       46 %
Natural gas (per Mcf)
    6.76       5.27       28 %
Natural gas equivalents (per Mcfe)
    7.61       5.90       29 %
                         
Average cost per Mcfe
                       
Production and operating costs  (3)
  $ 1.79     $ 1.44       24 %
Depreciation, depletion and amortization
    2.77       2.57       8 %
                         
Revenues:
                       
Oil and gas sales
  $ 3,763,882     $ 3,019,510       25 %
Oil and gas price risk management, net
    1,324,026       (171,459 )     *  
Total revenues
  $ 5,087,908     $ 2,848,051       79 %
                         
Operating costs and expenses:
                       
Production and operating costs
  $ 901,832     $ 776,600       16 %
Direct costs - general and administrative
    102,909       49,037       110 %
Depreciation, depletion and amortization
    1,397,701       1,388,803       1 %
Accretion of asset retirement obligations
    8,780       8,304       6 %
Total operating costs and expenses
  $ 2,411,222     $ 2,222,744       8 %
                         
Income from operations
  $ 2,676,686     $ 625,307       328 %
                         
Interest income
    38,335       49,440       -22 %
                         
Net income
  $ 2,715,021     $ 674,747       302 %
                         
Cash distributions
  $ 2,972,261     $ 2,395,447       24 %
 
* Percentage change not meaningful, equal to or greater than 250% or not calculable.
- 26 -

 
 
(1)
Production is determined by multiplying the gross production volume of properties in which we have an interest by the average percentage of the leasehold or other property interest the Partnership owns.
 
(2)
A ratio of energy content of natural gas and oil (six Mcf of natural gas equals one Bbl of oil) was used to obtain a conversion factor to convert oil production into equivalent Mcf of natural gas.
 
(3)
Production costs represent oil and gas operating expenses which include production taxes.

Definitions used throughout Management’s Discussion and Analysis of Financial Condition and Results of Operations.
 
·
Bbl – One barrel or 42 U.S. gallons liquid volume
 
·
MBbl – One thousand barrels
 
·
Mcf – One thousand cubic feet
 
·
MMcf – One million cubic feet
 
·
Mcfe – One thousand cubic feet of natural gas equivalents, based on a ratio of 6 Mcf for each barrel of oil, which reflects the relative energy content
 
·
MMcfe – One million cubic feet of natural gas equivalents
 
·
MMbtu – One million British Thermal Units

Oil and Natural Gas Sales

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

   
2008
   
2007
 
   
Sales
               
Sales
             
Total
 
(in thousands)
   
MMcfe
   
per Mcfe
   
(in thousands)
   
MMcfe
   
per Mcfe
 
Jan-Mar
  $ 954       127     $ 7.53     $ 902       156     $ 5.79  
Apr-Jun
    1,480       158       9.35       812       146       5.55  
Jul-Sept
    924       112       8.28       655       133       4.93  
Oct-Dec
    406       107       3.78       651       106       6.13  
Total
  $ 3,764       504     $ 7.47     $ 3,020       541     $ 5.58  
Change (year over year)
    25 %     -7 %     34 %                        
 
   
2008
   
2007
 
   
Sales
               
Sales
             
Oil
 
(in thousands)
   
MBbl
   
per Bbl
   
(in thousands)
   
MBbl
   
per Bbl
 
Jan-Mar
  $ 194       2     $ 81.91     $ 165       4     $ 44.60  
Apr-Jun
    290       3       113.51       184       3       54.20  
Jul-Sept
    285       3       105.95       202       3       64.08  
Oct-Dec
    93       2       45.21       201       3       74.35  
Total
  $ 862       10     $ 89.15     $ 752       13     $ 58.04  
Change (year over year)
    15 %     -25 %     54 %                        
 
   
2008
   
2007
 
   
Sales
               
Sales
             
Natural Gas
 
(in thousands)
   
MMcf
   
per Mcf
   
(in thousands)
   
MMcf
   
per Mcf
 
Jan-Mar
  $ 760       113     $ 6.75     $ 737       133     $ 5.52  
Apr-Jun
    1,190       143       8.32       628       126       4.99  
Jul-Sept
    639       95       6.70       453       114       3.98  
Oct-Dec
    313       95       3.29       450       90       5.00  
Total
  $ 2,902       446     $ 6.51     $ 2,268       463     $ 4.89  
Change (year over year)
    28 %     -4 %     33 %                        

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

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

- 27 -


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

Overall quarterly sales declined, however, by $0.3 million, during the quarter ended December 31, 2008 over the previous year’s fourth quarter, due to commodity price reductions of $0.3 million while production volumes remained substantially unchanged period-to-period.

The Partnership expects to experience continued declines in both oil and natural gas production volumes over the wells’ life cycles until such time that the Wattenberg wells may be successfully recompleted.  Subsequent to successful recompletion, if any, production will once again begin to decline.

Oil and Natural Gas Pricing

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

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 $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 $0.96 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 at market prices.

Oil pricing is also driven strongly by supply and demand relationships.  In the Rocky Mountain Region for 2008, Partnership oil sales averaged $89.15 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 -


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

Through September 2009, oil and natural gas prices have continued to fluctuate, with oil prices on NYMEX as high as $74.37 (per Barrel) on August 24, 2009 and as low as $33.98 (per Barrel) on February 12, 2009 and natural gas prices on CIG as high as $4.59 (per MMbtu) on January 7, 2009 and as low as $1.33 (per MMbtu) on April 14, 2009.

Oil and Natural Gas Price Risk Management, Net

The Managing General Partner uses oil and natural gas commodity derivative instruments to manage price risk for PDC as well as its sponsored drilling partnerships.  The Managing General Partner sets these instruments for PDC and the various partnerships managed by PDC jointly by area of operations.  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 on a pro-rata basis.  As of September 30, 2008, PDC has fixed the allocation of derivative positions, between PDC and each partnership. Existing positions are allocated based on fixed quantities for each position and new positions will have specific designations relative to the applicable partnership.  Realized and unrealized gains and losses resulting from derivative positions are reported on the statement of operations as “Oil and gas price risk management, 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 volatility in oil and gas prices that resulted in 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:

   
Three months ended
       
   
March 31, 2008
   
June 30, 2008
   
September 30, 2008
   
December 31, 2008
   
Total
 
                               
Realized gains (losses)
                             
Oil
  $ (10,885 )   $ (45,232 )   $ (37,585 )   $ 48,660     $ (45,042 )
Natural gas
    (24,010 )     (237,628 )     75,399       301,595       115,356  
Realized (loss) gain
    (34,895 )     (282,860 )     37,814       350,255       70,314  
Unrealized (loss) gain
    (363,931 )     (566,693 )     1,627,955       556,381       1,253,712  
Oil and gas price risk management, net
  $ (398,826 )   $ (849,553 )   $ 1,665,769     $ 906,636     $ 1,324,026  
                                         
   
Three months ended
         
   
March 31, 2007
   
June 30, 2007
   
September 30, 2007
   
December 31, 2007
   
Total
 
                                         
Realized gains (losses)
                                       
Oil
  $ (1,422 )   $ (1,552 )   $ (449 )   $ (181 )   $ (3,604 )
Natural gas
    (6,228 )     53,992       99,166       28,582       175,512  
Realized (loss) gain
    (7,650 )     52,440       98,717       28,401       171,908  
Unrealized (loss) gain
    (141,498 )     54,023       (21,128 )     (234,764 )     (343,367 )
Oil and gas price risk management, net
  $ (149,148 )   $ 106,463     $ 77,589     $ (206,363 )   $ (171,459 )
 
“Oil and gas price risk management, net” includes realized gains and losses and unrealized changes in the fair value of oil and natural gas derivatives related to Partnership oil and natural gas production.  See and Note 4, Fair Value of Financial Instruments and Note 5, Derivative Financial Instruments, to the accompanying financial statements for additional details of the Partnership’s derivative financial instruments.

- 29 -


For the year ended December 31, 2008, the Partnership recorded realized gains of $0.1 million and unrealized gains of $1.2 million, resulting in a net $1.3 million gain for the year.  During the quarter ended March 31, 2008, prices increased and remained above December 31, 2007 prices resulting in unrealized losses of $0.4 million.  The CIG-index 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 $0.3 million realized and $0.6 million unrealized losses for that period. Although Rocky Mountain Region oil and natural gas prices increased during the first seven months of 2008, the Partnership experienced significant commodity price declines during the last five months of 2008, relative to the Partnership’s current derivative positions, which resulted in significant unrealized 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 Rocky Mountain Region for oil and natural gas resulted in the Partnership’s third quarter unrealized gains of $1.7 million and fourth quarter realized and unrealized gains of  $0.4 million and $0.5 million, respectively.  When forward prices for oil and natural gas decrease as they did throughout the last five months of 2008, the Partnership’s derivative positions, which include floors, ceilings and swaps, tend to increase in value, resulting in unrealized gain positions.

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

Oil and Natural Gas Sales Derivative Instruments.  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 protection swaps on a portion of the Partnership’s oil and natural gas production, as set forth in the following table.

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

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

In July 2009, the Managing General Partner entered into a NYMEX-based oil swap covering approximately 50% of the Partnership’s estimated production of oil for the calendar year 2011 at $70.75 per barrel.

- 30 -


Production and Operating Costs

Production and Operating Costs include production taxes and transportation costs which vary with revenues and production, well operating costs charged on a per well basis and other direct costs incurred in the production process.

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

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

Generally, production and operating costs vary either with total oil and natural gas sales or production volumes.  Property and severance taxes are estimates by the Managing General Partner based on rates determined using historical information.  These amounts are subject to revision based on actual amounts determined during future filings by the Managing General Partner with the taxing authorities.  Property and severance taxes vary directly with total oil and natural gas sales.  Transportation costs vary directly with production volumes.  Fixed monthly well operating costs increase on a per unit basis as production decreases per the historical decline curve.  In addition, general oil field services and all other costs vary and can fluctuate based on services required.  These costs include water hauling and disposal, equipment repairs and maintenance, snow removal and service rig workovers.  In addition, general oil field service costs have experienced significant inflationary increases.

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

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

Direct Costs – General and Administrative

Direct costs – general and administrative consist primarily of professional fees for financial statement audits, income tax return preparation and legal matters.  Direct costs increased during 2008 by approximately $54,000 due primarily to increases in audit fees of approximately $23,000 and outside professional fees of approximately $46,000 offset by a reduction in legal fees of approximately $13,000.

- 31 -


Depreciation, Depletion and Amortization

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

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

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

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

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

Interest Income

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

Liquidity and Capital Resources

As the Partnership completed its drilling activities as of March 31, 2005, the Partnership’s operations are expected to be conducted with available funds and revenues generated from oil and natural gas production activities. Because oil and gas production from the Partnership’s existing properties declined rapidly in the first two years, the Partnership may be unable to maintain its current level of oil and gas production and cash flows from operations if commodity prices remain in their current depressed state for a prolonged period beyond 2009.  This decreased production would have a material negative impact on the Partnership’s operations and may result in reduced cash distributions to the Investor Partners in 2010 and beyond. Based on the current economic environment, the Managing General Partner has no immediate plans to initiate recompletion activities in the Codell formation of the Wattenberg Field wells.  The Managing General Partner will re-evaluate the feasibility of commencing these recompletion activities as economic conditions improve.  However, no assurance can be given that recompletion activities will be feasible.

- 32 -


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

Working Capital

The following table sets forth the working capital position of the Partnership:

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

Cash Flows From Financing and Investing Activities

In 2008, the Partnership received a refund of approximately $37,000 from the State of Colorado for state sales taxes charged during prior years 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 $8,000 in 2008.

The Partnership initiated monthly cash distributions to investors in February 2005 and has distributed $17.1 million of its operating cash flows from its July 2, 2004 date of inception through December 31, 2008.  The following table sets forth the quarterly cash distributions to the Managing General Partner and the Investor Partners during the years ended December 31, 2008 and 2007, respectively.

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

- 33 -


Cash Flows From Operating Activities

Net cash provided by operating activities was $3.0 million in 2008 compared to $2.4 million in 2007, an increase of $0.6 million.  The increase in cash provided by operating activities was due primarily to the following:

 
·
An increase in oil and gas sales revenues of 25% offset by a $0.1 million decrease in realized oil and gas price risk management gains, net; an increase in production and operating costs of 16% and an increase in direct costs of approximately $54,000.

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

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

   
2008
 
   
Quarter ended
   
Quarter ended
   
Quarter ended
   
Quarter ended
 
   
March 31,
   
June 30,
   
September 30,
   
December 31,
 
                         
Cash flows from operating activities
  $ 501,665     $ 744,152     $ 984,395     $ 760,352  
 
   
2007
 
   
Quarter ended