CONFORMED COPY

SECURITIES ANDEXCHANGE COMMISSION

Washington, D.C.  20549

FORM10-K

[X]ANNUALREPORT PURSUANT TO SECTION 13 or 15 (d) OF

  THESECURITIES EXCHANGE ACT OF 1934

  Forthe fiscal year ended December 31, 2004

  CommissionFile Number  000-49673

[]TransitionReport Pursuant to Section 13 or 15(d) of the Securities

 ExchangeAct of 1934 for the transaction period from         to          

PDC 2001-A LIMITEDPARTNERSHIP

(Exact name ofregistrant as specified in its charter)

|   West Virginia          

(State or other  jurisdiction of

incorporation or  organization) |     55-0779061    

(I.R.S. Employer 

Identification  No.) |
|------------------------------------------------------------------------------------------------------------------------------------------------|-------------------------------------------------------------------------------------------|

103 East Main Street, Bridgeport, West Virginia  26330

(Address ofprincipal executive offices)     (zip code)

Registrant'stelephone number, including area code           (304) 842-3597

SECURITIESREGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:  NONE

SECURITIESREGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:

General and LimitedPartnership Interests

(Title of class)

Indicate by checkmark whether the registrant (1) has filed all reports required to be filed bySection 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding12 months and (2) has been subject to such filing requirements for the past 90days.   Yes    No     X     

Indicate by checkmark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-Kis not contained herein, and will be contained, to the best of registrant'sknowledge, in definitive proxy or information statements incorporated byreference in Part III of this Form 10-K or any amendment to this Form 10-K.  [ ]

Indicate by checkmark whether the registrant is an accelerated filer (as definition in Rule12b-2 of the Exchange Act). Yes   No X 

There is no tradingmarket for the registrant's securities.

PART I

ITEM 1.  BUSINESS.

General

     PDC 2001-A LimitedPartnership ("the Partnership") is a limited partnership formed on May 7, 2001 pursuant to the West Virginia Uniform Limited Partnership Act.  Petroleum DevelopmentCorporation ("PDC") serves as Managing General Partner of thePartnership.

     Since the commencement ofoperations on May 7, 2001, the Partnership has been engaged in onshore,domestic oil and natural gas exploration exclusively in the Rocky MountainRegion.  A total of 3 limited partners contributed initial capital of $25,000and a total of 459 additional general partners contributed initial capital of$9,358,798 and PDC (Managing General Partner) contributed $2,040,976 in capitalas a participant in accordance with contribution provisions of the LimitedPartnership Agreement (the Agreement). During 2002 in accordance with thePartnership Agreement, all Additional General Partners were converted toLimited Partners.

     Under the terms of theAgreement, the allocation of revenues is as follows:

|                                                | Allocation

of Revenues |
|------------------------------------------------|-------------------------|
| Additional General and

 Limited Partners | 80%                     |
| Managing General Partner                       | 20%                     |

     Operating and direct costsare allocated and charged to the additional general and limited partners andthe Managing General Partner in the same percentages as revenues areallocated.  Leasehold, drilling and completion costs, and equipment costs areborne 80% by the Additional General and Limited Partners and 20% by theManaging General Partner. See Footnote 4 of financial statements for a completedescription of the allocation of Partnership revenue and costs.

Employees

     The Partnership has noemployees, however, PDC has approximately 120 employees which include 17 infinance and data processing, 8 in administration, 12 in exploration anddevelopment, 78 in production and 5 in natural gas marketing.

Plan of Operations

     The Partnershipparticipated in the drilling of thirty-two gross (15.44 net) wells and willcontinue to operate and produce its thirty-two gross productive wells.  ThePartnership does not have unexpended initial capital and no additional drillingactivity is planned.

     See Item 2 herein forinformation concerning the Partnership's gas wells.

Markets for Oil and Gas

     The availability of amarket for any oil and gas produced from the operations of the Partnership willdepend upon a number of factors beyond the control of the Partnership whichcannot be accurately predicted.  These factors include the proximity of thePartnership wells to and the capacity of natural gas pipelines, theavailability and price of competitive fuels, fluctuations in seasonal supplyand demand, and government regulation of supply and demand created by itspricing and allocation restrictions.  Oversupplies of gas can be expected tooccur from time to time and may result in the Partnership's wells being shut-inor curtailed.  Increased imports of oil and natural gas have occurred and areexpected to continue. The effects of such imports could adversely impact themarket for domestic oil and natural gas. All oil and natural gas is sold undercontracts based on market sensitive indexes that vary from month to month. Nofixed price contracts are in place. The Partnership sold oil and natural gas toseveral entities of which three customers accounted for 38.0%, 37.3% and 17.3%of the Partnership's total oil and natural gas sales for the year endedDecember 31, 2004, 22.3%, 22.7% and 32.9% for the year ended December 31,  2003,and 28.7%, 28.4% and 27.3% for the year ended December 31, 2002.

2

Hedging Activities

          The Managing General Partner, through itssubsidiary Riley Natural Gas, has been in the gas marketing business since1986. During that time period, the Managing General Partner has utilized andcontinues to utilize commodity basedderivative instruments as hedges to manage a portion of the Partnership'sexposure to price volatility stemming from natural gas production.  Theseinstruments consist of CIG (Colorado Interstate Gas Index)-based contracts for Colorado production and NYMEX traded oil futures and option contracts for Colorado oilproduction.  The contracts hedge committed and anticipated natural gas sales,generally forecasted to occur within the next two year period. The ManagingGeneral Partner does not hold or issue derivatives for trading or speculativepurposes and permits utilization of hedges only if there is an underlyingphysical position.  See "Commodity Price Risk" under Item 7A.

     Notwithstanding the measuretaken by the Managing General Partner to attempt to control price risk, thePartnership remains subject to price fluctuations for natural gas and oil soldin the spot market.  The Managing General Partner continues to evaluate thepotential for reducing these risks by entering into hedge transactions.  Inaddition, the Managing General Partner may also close out any portion of hedgesthat may exist from time to time.

 

Competition

     The Partnership competes inmarketing its gas and oil with numerous companies and individuals, many ofwhich have financial resources, staffs and facilities substantially greaterthan those of the Partnership or Petroleum Development Corporation.

State Regulations

     State regulatoryauthorities have established rules and regulations requiring permits for welloperations, reclamation bonds and reports concerning operations.  States alsohave statutes and regulations concerning the spacing of wells, environmentalmatters and conservation, and have established regulations concerning theunitization and pooling of oil and gas properties and maximum rates ofproduction from oil and gas wells. The Partnership believes it has complied inall material respects with applicable state regulations. The Partnership estimates it has spentapproximately $4,283, $5,800, and $8,900 in 2004, 2003 and 2002, respectivelyto comply with federal and state regulations.

Federal Regulations

     Regulation of LiquidHydrocarbons. Liquid hydrocarbons (including crude oil and natural gasliquids) were subject to federal price and allocation controls until January1981 when controls were effectively eliminated by executive order of thePresident.  As a result, to the extent the Partnership sells oil produced fromits properties, those sales are at unregulated market prices.

     Although it appearsunlikely under present circumstances that controls will be reimposed uponliquid hydrocarbons, it is possible Congress may enact such legislation at afuture date. 

     Natural Gas Regulation.   Sale of natural gas by the Partnership is subject to regulation ofproduction, transportation and pricing by governmental regulatory agencies. Generally, the regulatory agency in the state where a producing well is locatedregulates production activities and, in addition, the transportation of gassold intrastate.  The Federal Energy Regulatory Commission (FERC) regulates theoperation and cost of interstate pipeline operators who transport gas. Currently the price of gas sold by the Partnership is not regulated by anystate or federal agency.

     Proposed Regulation. Numerous proposals concerning energy are being considered by the United StatesCongress, various state legislatures and regulatory agencies.  The possibleoutcome and effect of these proposals cannot be accurately predicted.

  

  Environmental and Safety Regulation. The Partnership believes that it complies, in all material respects, with alllegislation and regulations affecting its operations in the drilling andproduction of oil and gas wells and the discharge of wastes.  To date,compliance with such provisions and regulations has not had a material effectupon the Partnership's expenditures for capital equipment, its operations orits competitive position.  The cost of such compliance is not anticipated to bematerial in the future.

3

ITEM 2.  PROPERTIES.

Drilling Activity

     The following table sets forth theresults of the Partnership's drilling activity from May 7,  2001 (date of inception) to December 31, 2004.  All of the Partnership's wells drilled and producingare located in Colorado.

|                                         Development  Wells                                                                   |
|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
|                 Gross Wells                                                                                                                                                                                                                                                                                                                                                                                                                        |                Net Wells                                           |
| Productive                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                     | Dry | Total | Productive | Dry | Total |
| 32                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                             | - | 32 | 15.44 | - | 15.44 |

     The Partnership has notparticipated in any exploratory wells.  No additional drilling activity isplanned.

Production 

See "Management's Discussion and Analysis" onpage 5 for Partnership production. 

Reserves

See "Footnote 8" to the Partnership's financialstatements for information related to the Partnership's oil and gas reserves.

Productive Wells

     As outlined in the abovetable, the Partnership has a total of 32 gross productive wells (15.44 netwells) all of which are located in Colorado.

     A "productivewell" is a well producing, or capable of producing, oil and gas incommercial quantities.  For purposes of the above table, a "grosswell" is one in which the Partnership has a working interest and a"net well" is a gross well multiplied by the Partnership's workinginterest to which it is entitled under its drilling agreement.

Title to Properties

     The Partnership's interestsin producing acreage are in the form of assigned direct interests in leases.Such properties are subject to customary royalty interests generally contractedfor in connection with the acquisition of properties and could be subject to liensincident to operating agreements, liens for current taxes and other burdens. The Partnership believes that none of these burdens materially interfere withthe use of such properties in the operation of the Partnership's business.

     As is customary in the oiland gas industry, little or no investigation of title is made at the time ofacquisition of undeveloped properties (other than a preliminary review of localmineral records).  Investigations are generally made, including in most casesreceiving a title opinion of legal counsel, before commencement of drillingoperations.  A thorough examination of title has been made with respect to allof the Partnership's producing properties and the Partnership believes that ithas generally satisfactory title to such properties.

 

ITEM 3.  LEGAL PROCEEDINGS.

     The Managing Generalpartner as driller/operator is not party to any legal action that it believes wouldhave a materially adverse affect on the Managing General Partner's orPartnership's business, financial condition, results of operations or liquidity.

ITEM 4.  SUBMISSION OF MATTERS TO A VOTE OF SECURITYHOLDERS.

          NON-APPLICABLE

4

 

 

PART II

ITEM 5.  MARKET FOR REGISTRANT'S COMMON EQUITY ANDRELATED STOCKHOLDER MATTERS.

     At December 31, 2001, PDC2001-A Limited Partnership had one Managing General Partner and a total of 3Limited Partners who paid for 1.25 units at $20,000 per unit of limitedpartnership interest, a total of 459 Additional General Partners who paid for467.94 units at $20,000 per unit of additional general partnership interests. During 2002 in accordance with the Partnership Agreement, all AdditionalGeneral Partners were converted to Limited Partners. At December 31, 2004, the Partnership had one Managing General Partner and 462 limited partners who paidfor 469.19 units at $20,000 per unit. No established public trading marketexists for the interests.

     Limited and additionalgeneral partnership interests are transferable, however no assignee of aninterest in the Partnership can become a substituted partner without thewritten consent of the transferor and the Managing General Partner. There is noestablished trading market for the securities of the Partnership.

ITEM 6.  SELECTED FINANCIAL DATA.

     The selected financial datapresented below has been derived from audited financial statements of thePartnership appearing elsewhere herein.

                                                                                                                                                YearsEnded December 31, 

|                                                                    | 2004

               | 2003                      | 2002                      |
|--------------------------------------------------------------------|---------------------------|---------------------------|---------------------------|
| Oil and Gas Sales                                                  | $1,261,545           | $1,327,456           | $1,502,400           |
| Costs and Expenses                                                 | 653,952              | 816,160              | 1,179,581            |
| Cumulative Effect of change in accounting principle                | -     | (2,218)                   | -     |
| Loss on impairment of oil and gas properties                       | -     | -     | (4,560,861)               |
|    Net income (loss)                                | 608,098              | 509,774              | (4,236,517)               |
| Allocation of Net income (loss):                                   |                           |                           |                           |
|    Managing General Partner                         | 121,620              | 101,955              | (847,303)                 |
|    Limited and Additional General  Partners         | 486,479              | 407,819              | (3,389,214)               |
|    Per Limited and Additional General  Partner Unit | 1,037                | 869                  | (7,224)                   |
| Total Assets                                                       | 3,763,445            | 4,045,266            | 4,598,006            |
| Cash Distributions:                                                |                           |                           |                           |
|    Managing General Partner                         | 181,110              | 213,232              | 256,167              |
|    Limited and Additional General  Partners    | 724,452              | 852,938              | 1,024,682            |

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIALCONDITION AND RESULTS OF OPERATIONS.

Liquidity and Capital Resources

     ThePartnership was funded on May 7, 2001 with initial Limited and AdditionalGeneral Partner contributions of $9,383,798 and the Managing General Partner'scash contribution of $2,040,976 in accordance with the Agreement.  Afterpayment of syndication costs of $985,299 and a one-time management fee to themanaging general partner of $234,595 the Partnership had available cash of$10,204,880 for Partnership activities.

     ThePartnership began exploration and development activities subsequent to thefunding of the Partnership and completed these activities by December 31, 2001. Thirty-two wells have been drilled, all of which have been completed asproducers.  No additional wells will be drilled.

     The Partnership had workingcapital at December 31, 2004 of $233,515.

     Operations are expected tobe conducted with available funds and revenues generated from oil and gasactivities.  No bank borrowings are anticipated.  

5

 

Results of Operations

2004 Results Compared to 2003 

     Oil and gas sales for the year ended December 31, 2004 were $1,261,545 compared to $1,327,456 for the year ended December 31, 2003.  For the year ended December 31, 2004, the Partnership sold 156,116 Mcfof gas and 11,943 barrels of oil at average sales prices of $5.16 and $38.15,respectively.  This compared with 209,994 Mcf of gas and 18,081 barrels of oilsold at average sales prices of $3.81 and $29.12, respectively for the yearended December 31, 2003. Lifting cost per Mcfe in 2004 amounted to $1.38 ascompared to $1.11 for 2003. This increase is partially attributed to theincrease in severance and property taxes, on the significantly higher oil andgas prices along with additional well workovers.  Depreciation, depletion and amortization decreased from $451,881 for theyear ended December 31, 2003 to $328,925 for the year ended December 31, 2004.  Cash distributions to the partners amounted to $905,562 in 2004and $1,066,170 in 2003.

2003 Results Compared to 2002

     Oiland gas sales for the year ended December 31, 2003 were $1,327,456 compared to $1,502,400 for the year ended December 31, 2002.  For the year ended December 31, 2003, the Partnership sold 209,994 Mcf of gas and 18,081 barrels ofoil at average sales prices of $3.81 and $29.12, respectively.  This comparedwith 309,732 Mcf of gas and 33,932 barrels of oil sold at average sales pricesof $2.08 and $25.30, respectively for the year ended December 31, 2002. Lifting cost per Mcfe in 2003 amounted to $1.11 as compared to $0.69 for 2002.This increase is partially attributed to the increase in severance and propertytaxes. The fixed costs of operations and well maintenance are allocated tolower production volumes, therefore increasing the lifting cost per Mcfe. Depreciation, depletion and amortization decreasedfrom $810,115 for the year ended December 31, 2002 to $451,881 for the year ended December 31, 2003 as a result of lower volumes of natural gas and oilsold along with lower net book value of oil and gas properties due to 2002'simpairment charge for oil and gas properties. Cash distributions to thepartners amounted to $1,066,170 in 2003 and $1,280,849 in 2002.

The Partnership'srevenues from oil and natural gas sales will be affected by changes in prices. As a result of changes in federal regulations, gas prices are highly dependenton the balance between supply and demand. The Partnership's gas sales pricesare subject to increase and decrease based on various market sensitive indices.

 

Critical Accounting Policies and Estimates

     Certain accounting policiesare very important to the portrayal of the Partnership's financial conditionand results of operations and require management's most subjective or complexjudgments. In applying those policies,our management uses its judgment to determine the appropriate assumptions to beused in the determination of certain estimates. Those estimates are based onour historical experience, our observance of trends in the industry, andinformation available from other outside sources, as appropriate. For a moredetailed discussion on the application of these and other accounting policies,see "Note 1 - Summary of significant account policies" in our financialstatements and related notes. The Partnership's critical accounting policiesand estimates are as follows:

Revenue Recognition

Sales of natural gas are recognized whennatural gas has been delivered to a custody transfer point, persuasive evidenceof a sales arrangement exists, the rights and responsibility of ownership passto the purchaser upon delivery, collection of revenue from the sale isreasonably assured and the sales price is fixed or determinable.  Natural gasis sold by the Managing General Partner under contracts with terms ranging fromone month to three years.  Virtually all of the Managing General Partner'scontracts pricing provisions are tied to a market index, with certainadjustments based on, among other factors, whether a well delivers to agathering or transmission line, quality of natural gas and prevailing supplyand demand conditions, so that the price of the natural gas fluctuates toremain competitive with other available natural gas supplies.  As a result, thePartnership's revenues from the sale of natural gas will suffer if marketprices decline and benefit if they increase.  The Partnership believes that thepricing provisions of its natural gas contracts are customary in the industry.

6

     The Managing General Partner currently uses the "Net-Back" methodof accounting for transportation arrangements of natural gas sales.  TheManaging General Partner sells gas at the wellhead and collects a price andrecognizes revenues based on the wellhead sales price since transportationcosts downstream of the wellhead are incurred by the Managing General Partner'scustomers and reflected in the wellhead price.

Sales of oil are recognized whenpersuasive evidence of a sales arrangement exists, the oil is verified asproduced and is delivered in a stock tank, collection of revenue from the saleis reasonably assured and the sales price is determinable.  The Partnership iscurrently able to sell all the oil that it can produce under existing salescontracts with petroleum refiners and marketers.  The Partnership does notrefine any of its oil production.  The Partnership's crude oil production issold to purchasers at or near the Partnership's wells under short-term purchasecontracts at prices and in accordance with arrangements that are customary inthe oil industry. 

Accounting forDerivatives Contracts at Fair Value

     ThePartnership uses derivative instruments to manage its commodity and financialmarket risks. Accounting requirements for derivatives and hedging activitiesare complex; interpretation of these requirements by standard-setting bodies isongoing. 

     Derivativesare reported on the Balance Sheets at fair value. Changes in fair value ofderivatives that are not designated as accounting hedges are recorded inearnings. 

    Themeasurement of fair value is based on actively quoted market prices, ifavailable. Otherwise, the Partnership seeks indicative price information fromexternal sources, including broker quotes and industry publications. If pricinginformation from external sources is not available, measurement involves judgmentand estimates. These estimates are based on valuation methodologies consideredappropriate by the Partnership's management. 

     Forindividual contracts, the use of different assumptions could have a materialeffect on the contract's estimated fair value. In addition, for hedges offorecasted transactions, the Partnership must estimate the expected future cashflows of the forecasted transactions, as well as evaluate the probability ofthe occurrence and timing of such transactions. Changes in conditions or theoccurrence of unforeseen events could affect the timing of recognition inearnings for changes in fair value of certain hedging derivatives.

Use of Estimates inLong-Lived Asset Impairment Testing

Impairmenttesting for long-lived assets and intangible assets with definite lives isrequired when circumstances indicate those assets may be impaired.  Inperforming the impairment test, the Partnership would estimate the future cashflows associated with individual assets or groups of assets.  Impairment mustbe recognized when the undiscounted estimated future cash flows are less thanthe related asset's carrying amount.  In those circumstances, the asset must bewritten down to its fair value, which, in the absence of market priceinformation, may be estimated as the present value of its expected future netcash flows, using an appropriate discount rate.  Although cash flow estimatesused by the Partnership are based on the relevant information available at thetime the estimates are made, estimates of future cash flows are, by nature,highly uncertain and may vary significantly from actual results.

Oil and Gas Properties 

     Explorationand development costs are accounted for by the successful efforts method.

     The Partnership assesses impairmentof capitalized costs of proved oil and gas properties by comparing netcapitalized costs to estimated undiscounted future net cash flows on afield-by-field basis using expected prices. Prices utilized in each year'scalculation for measurement purposes and expected costs are held constantthroughout the estimated life of the properties. If net capitalized costsexceed undiscounted future net cash flows, the measurement of impairment isbased on estimated fair value which would consider future discounted cashflows.

7

Property acquisitioncosts are capitalized when incurred.  Geological and geophysical costs anddelay rentals are expensed as incurred.  The costs of drilling exploratorywells are capitalized pending determination of whether the wells havediscovered economically producible reserves.  If reserves are not discovered,such costs are expensed as dry holes.  Development costs, including equipmentand intangible drilling costs related to both producing wells and developmentaldry holes, are capitalized.

Unproved propertiesor leases are written-off to expense when it is determined that they willexpire or be abandoned.

Costs of provedproperties, including leasehold acquisition, exploration and development costsand equipment, are depreciated or depleted by the unit-of-production methodbased on estimated proved developed oil and gas reserves.

Upon sale orretirement of complete fields of depreciable or depletable property, the bookvalue thereof, less proceeds or salvage value, is credited or charged toincome.  Upon sale of a partial unit of property, the proceeds are credited toaccumulated depreciation and depletion.

New Accounting Standards

      In June 2001, theFinancial Accounting Standard Board issued FASB No. 143, "Accounting forAsset Retirement Obligations" that requires entities to record the fairvalue of a liability for an asset retirement obligation in the period in whichit is incurred and a corresponding increase in the carrying amount of therelated long-lived asset. This statement is effective for fiscal yearsbeginning after June 15, 2002. The Partnership adopted FASB No. 143 on January 1, 2003 and recorded a net asset of $5,511 and a related liability of $7,729(using a 6% discount rate) and a cumulative effect on change in accountingprinciple on prior years of $2,218.

Item 7 A.  Quantitative and QualitativeDisclosure About Market Risk.

Market-Sensitive Instruments and Risk Management

     The Partnership's primarymarket risk exposure is commodity price risk.  This exposure is discussed indetail below:

Commodity Price Risk

The Managing General Partner utilizescommodity-based derivative instruments as hedges to manage a portion of itsexposure to price risk from its oil and natural gas sales.  These instrumentsconsist of CIG-based contracts traded by JP Morgan for Colorado production. These hedging arrangements have the effect of locking in for specified periods(at predetermined prices or ranges of prices) the prices the Managing GeneralPartner will receive for the volume to which the hedge relates.  As a result,while these hedging arrangements are structured to reduce the Partnership'sexposure to changes in price associated with the hedged commodity, they alsolimit the benefit the Partnership might otherwise have received from pricechanges associated with the hedged commodity.  The Managing General Partner's policy prohibits the use of natural gas futureand option contracts for speculative purposes.

The following tablessummarize the open futures and options contracts for the Partnership as of December 31, 2004 and 2003.

| Commodity                                                      | Type     | Quantity    | Weighted | Total                     | Fair                      |
|----------------------------------------------------------------|----------|-------------|----------|---------------------------|---------------------------|
|                                                                |          | Gas-Mmbtu   | Average  | Contract                  | Market                    |
|                                                           |     | Oil-Barrels | Price    | Amount                    | Value                     |
| Total Contracts as of December 31, 2004                        |
|  Natural  Gas                                             | Floors   | 31,019      | 4.16     | -     | 7,509                |
| Natural  Gas                                                   | Ceilings | 15,509      | 5.36     | -     | (9,771)                   |
| Oil                                                            | Floors   | 6,774       | 32.30    | 218,816                   | 5,772                |
| Oil                                                            | Ceilings | 3,387       | 40.00    | 135,490                   | (18,322)                  |
| 8

Contracts maturing in 12 months following December 31, 2004 |
| Natural  Gas                                                   | Floors   | 31,019      | 4.16     | -     | 7,509                |
| Natural  Gas                                                   | Ceilings | 15,509      | 5.36     | -     | (9,771)                   |
| Oil                                                            | Floors   | 6,774       | 32.30    | 218,816                   | 5,772                |
| Oil                                                            | Ceilings | 3,387       | 40.00    | 135,490                   | (18,322)                  |
|                                                                |
| Prior Year Total Contracts as of December 31, 2003             |
| Natural  Gas                                                   | Floors   | 21,812      | 3.28     | -     | -     |
| Natural  Gas                                                   | Ceilings | 21,812      | 4.84     | -     | (332)                     |

The maximum termover which the Partnership is hedging exposure to the variability of cash flowsfor commodity price risk is 12 months.

The average CIGclosing price for natural gas for the years 2004, 2003 and 2002 was $5.17 perMmbtu, $4.04 per Mmbtu and $1.97 per Mmbtu.  The average NYMEX closing pricefor oil for the years 2004, 2003 and 2002 was $41.44 per bbl, $30.98 per bbland $26.98 per bbl.  Future near-term gas prices will be affected by varioussupply and demand factors such as weather, government and environmentalregulations and new drilling activities within the industry.

Disclosure of Limitations

     As the information aboveincorporates only those exposures that exist at December 31, 2004, it does not consider those exposures or positions which could arise after that date. As aresult, the Partnership's ultimate realized gain or loss with respect tocommodity price fluctuations will depend on the exposures that arise during theperiod, the Partnership's hedging strategies at the time and commodity pricesat the time.

PART III

ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA:

     The response to this Itemis set forth herein in a separate section of this Report, beginning on PageF-1.

ITEM 9.  CHANGES IN AND DISAGREEMENTS WITHACCOUNTANTS ON ACCOUNTING AND

         FINANCIALDISCLOSURE.

         NONE.

 

ITEM 9A CONTROLS AND PROCEDURES

     Underthe supervision and with the participation of the Managing General Partner'smanagement, including the Managing General Partner's Chief Executive Officerand Chief Financial Officer, the Managing General Partner has evaluated theeffectiveness of the design and operation of its disclosure controls andprocedures (as defined in Exchange Act Rule 13a-14(c)) as of the end of theperiod covered by this annual report on Form 10-K, and, based on theirevaluation, the Chief Executive Officer and Chief Financial Officer haveconcluded that these disclosure controls and procedures are effective in allmaterial respects, including those to ensure that information required to bedisclosed in reports filed or submitted under the Securities Exchange Act isrecorded, processed, summarized, and reported, within the time periodsspecified in the Commission's rules and forms, and is accumulated andcommunicated to management, including the Managing General Partner's ChiefExecutive Officer and Chief Financial Officer, as appropriate to allow fortimely disclosure. There have been no significant changes in our internalcontrols or in other factors that could significantly affect these controls inthe fourth quarter and subsequent to the date of their evaluation.

ITEM 9B.  OTHER INFORMATION

 

      None

 

9

 

 

 

 

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.

     The Partnership has nodirectors or executive officers.  The partnership is managed by PetroleumDevelopment Corporation (the Managing General Partner).  Petroleum DevelopmentCorporation's common stock is traded in the NASDAQ National Market and Form10-K for 2004 has been filed with the Securities and Exchange Commission.  

        Although the Partnership has no Code of Ethics,Petroleum Development Corporation, the Managing General Partner of thePartnership, has a Code of Ethics that applies to its senior executiveofficers.  The Code of Ethics is posted on the website of Petroleum DevelopmentCorporation at  www.petd.com. 

ITEM 11.  EXECUTIVE COMPENSATION.

        NON-APPLICABLE.

ITEM 12.  SECURITY OWNERSHIP OF CERTAIN BENEFICIALOWNERS, MANAGEMENT AND RELATED STOCKHOLDER MATTERS.

        NON-APPLICABLE.

 

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.

     Pursuant to theauthorization contained in the Limited Partnership Agreement, PDC receives feesfor services rendered and reimbursement of certain expenses from thePartnership.  See respective drilling prospectus for further informationregarding the Limited Partnership Agreement. The following table presentscompensation or reimbursements by the Partnership to PDC or other related partiesfor years ended December 31, 2004, 2003 and 2002.

|                            | 2004    | 2003    | 2002    |
|----------------------------|------------------------|------------------------|------------------------|
| Lifting costs              | $315,302          | 353,519           | 356,040           |
| Tax return preparation     | 4,453             | 5,657             | 3,495             |
| Direct administrative cost | 1,938             | 1,880             | 1,832             |

ITEM 14.  PRINCIPAL ACCOUNTANT FEES ANDSERVICES 

     For the years endedDecember 31, 2004 and 2003, the Partnership paid KPMG LLP $2,842 and $2,759,respectively, for professional services for the audit of the Partnership'sfinancial statements in its Form 10-K and review of financial statementsincluded in the Partnership's Form 10-Qs.

Pre-Approval Policies and Procedures

 

     The Sarbanes-Oxley Act of2002 requires that all services provided to the Partnership by its independentaccountants be subject to pre-approval by the Audit Committee or authorizedmembers of the Committee. The Partnership does not have an Audit Committee, theManaging General Partner's Audit Committee also serves for the Partnership. The Audit Committee has adopted policies and procedures for pre-approval of allaudit services and non-audit services to be provided by the Partnership'sindependent accountants. Services necessary to conduct the annual audit must bepre-approved by the Audit Committee or by the authorized Audit Committeemember. Actual fees incurred for all services performed by the independentaccountant will be reported to the Audit Committee after the services are fullyperformed.

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES.

                            (1)       FinancialStatements

                                        See Index toFinancial Statements on F-2

                            

10

                         (2)          Financial StatementSchedules

                                SeeIndex to Financial Statements on page F-2.  All financial statement schedulesare omitted because they are not required, inapplicable, or the information isincluded in the Financial Statements or Notes thereto.

(3)          Exhibits

| 4.1  | Form  of Limited Partnership Agreement (incorporated by reference to Appendix A to  Form S-1, SEC File No. 333-47622, and Rule 424 final prospectus, dated January 12, 2001, of Petroleum Development Corporation, filed with the SEC on February 2, 2001). |
|------|-------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| 14   | Code  of Ethics of Petroleum Development Corporation (incorporated by reference to  the posted code on the web site of Petroleum Development Corporation at www.petd.com).                                                                                  |
| 31.1 | Rule  13a-14(a)/15d-14(c) Certification of Chief Executive Officer of Petroleum  Development Corporation, the managing general partner of the Limited  Partnership.                                                                                         |
| 31.2 | Rule  13a-14(a)/15d-14(c) Certification of Chief Financial Officer of Petroleum  Development Corporation, the managing general partner of the Limited  Partnership.                                                                                         |
| 32.1 | Title 18  U.S.C. Section 1350 (Section 906 of Sarbanes-Oxley Act of 2002)  Certifications by Chief Executive Officer and Chief Financial Officer of Petroleum  Development Corporation, the managing general partner of the Limited  Partnership.           |

11

CONFORMED COPY

SIGNATURES

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

|  
PDC 2001-A Limited Partnership

By its Managing General Partner

Petroleum Development Corporation

 
By /s/ Steven R. Williams      

   Steven R. Williams, Chairman

April 19, 2005

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

Signature

Title

Date

/s/ Steven R. Williams

    Steven R. Williams

Chairman, Chief Executive Officer and

 Director 

April 19, 2005

/s/ Darwin L. Stump 

    Darwin L. Stump

Chief Financial Officer and Treasurer

(principal financial and accounting officer)

April 19, 2005

 

/s/ Thomas E. Riley 

    Thomas E. Riley

President and Director

April 19, 2005

/s/ Donald B. Nestor

    Donald B. Nestor

Director

April 19, 2005

/s/ Vincent F. D'Annunzio

    Vincent F. D'Annunzio

Director

April 19, 2005

12

PDC 2001-A LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Financial Statements for Annual Report

on Form 10-K to Securities and Exchange

Commission

Years Ended December 31, 2004, 2003 and 2002

(With Independent Registered Public Accounting Firm'sReport Thereon)

F-1

PDC 2001-A LIMITEDPARTNERSHIP

(A West VirginiaLimited Partnership)

Index to FinancialStatements

Report of Independent Registered Public Accounting Firm

F-3

Balance Sheets - December 31, 2004 and 2003

F-4

Statements of Operations -  Years Ended December 31, 2004,  2003 and 2002

F-5

Statements of Partners' Equity and Comprehensive Income  (Loss) 

  - Years Ended December 31, 2004, 2003 and 2002

  F-6

Statements of Cash Flows -  Years Ended December 31, 2004, 2003  and 2002

F-7

Notes to Financial Statements

F-8

All financial statement schedules have been omittedbecause they are not applicable or not required or the required information isshown in the financial statements or notes thereto.

F-2

Reportof Independent Registered Public Accounting Firm

To thePartners

PDC 2001-ALimited Partnership:

Wehave audited the accompanying balance sheets of PDC 2001-A Limited Partnership(a West Virginia limited partnership) as of December 31, 2004 and 2003, and the related statements of operations, partners' equity and comprehensive income(loss), and cash flows for each of the years in the three-year period ended December 31, 2004. These financial statements are the responsibility of the Partnership'smanagement. Our responsibility is to express an opinion on these financialstatements based on our audits.

Weconducted our audits in accordance with the standards of the Public CompanyAccounting Oversight Board (United States).  Those standards require that weplan and perform the audit to obtain reasonable assurance about whether thefinancial statements are free of material misstatement.  An audit includesexamining, on a test basis, evidence supporting the amounts and disclosures inthe financial statements.  An audit also includes assessing the accountingprinciples used and significant estimates made by management, as well asevaluating the overall financial statement presentation.  We believe that ouraudits provide a reasonable basis for our opinion.

Inour opinion, the financial statements referred to above present fairly, in allmaterial respects, the financial position of PDC 2001-A Limited Partnership asof December 31, 2004 and 2003, and the results of its operations and its cashflows for each of the years in the three-year period ended December 31, 2004,in conformity with U.S. generally accepted accounting principles.

As discussedin note 1 to the financial statements, the Partnership adopted the provisions ofStatement of Financial Accounting Standards No. 143, "Accounting for AssetRetirement Obligations", in 2003.                                                                     

                                                                                                                                                                                        

                                                                                                                                                                    KPMGLLP

Pittsburgh, Pennsylvania 

April 19, 2005

F-3

PDC 2001-A LIMITEDPARTNERSHIP

(A West VirginiaLimited Partnership)

Balance Sheets

December 31, 2004 and 2003

Assets

 

 

 

 

 

Current assets:

2004

2003

  Cash

        $       8,319 

 10,620 

  Accounts receivable - oil and gas revenues

264,641 

215,236 

          Total  current assets

272,960 

225,856 

  Oil and gas properties, successful efforts  method (notes 3 and 6):

5,651,311 

5,651,311 

          Less  accumulated depreciation, depletion and amortization

 2,160,826 

 1,831,901 

 3,490,485 

 3,819,410 

$3,763,445 

4,045,266 

 

 

Liabilities and Partners' Equity

Current liabilities:

  Accrued expenses

$    39,445 

    9,814 

          Total  current liabilities

39,445 

9,814 

Asset retirement obligation

8,685 

8,193 

 

 

Partners' equity

 3,715,315 

 4,027,259 

$ 3,763,445 

 4,045,266 

See accompanying notes to financial statements.

F-4

PDC 2001-A LIMITEDPARTNERSHIP

(A West VirginiaLimited Partnership)

Statements ofOperations

Years Ended December 31, 2004, 2003 and 2002

2004

2003

2002

 

 

Revenues:

  Sales of oil and gas

$1,261,545 

1,327,456 

1,502,400 

  Interest income

           505 

       696 

     1,525 

1,262,050 

1,328,152 

1,503,925 

Expenses (note 3):

  Lifting costs

315,302 

353,519 

356,040 

  Independent engineering fee

-    

-    

5,420 

  Independent audit fee

2,842 

2,759 

2,679 

  Tax return preparation

4,453 

5,657 

3,495 

  Direct administrative cost

2,430 

2,344 

1,832 

  Depreciation, depletion and amortization

328,925 

451,881 

810,115 

  Loss on impairment of oil and gas  properties

          -    

          -    

4,560,861 

 

 653,952 

 816,160 

5,740,442 

Income (loss) before cumulative effect of 

    change in accounting principle

  608,098 

  511,992 

  (4,236,517)

Cumulative effect of change in accounting principle

             -    

   (2,218)

        -    

  Net income (loss) 

$   608,098 

   509,774 

(4,236,517)

 

 

 

  Net income (loss) per limited and  additional 

    general partner unit before  cumulative effect of 

    change in accounting principle

  $        1,037 

          873 

      (7,224)

 

 

 

Cumulative effect of change in accounting principle

      -    

      (4)

        -    

 

 

 

 

 

Net income (loss) per limited and additional general  partner unit

  $       1,037 

       869 

      (7,224)

See accompanying notes to financial statements.

F-5

PDC 2001-A LIMITED PARTNERSHIP

(A West VirginiaLimited Partnership)

Statements ofPartners' Equity and Comprehensive Income (Loss)

Years Ended December 31, 2004, 2003 and 2002

Limited 

Partners       

Managing 

General 

Partner     

Accumulated

Other

Comprehensive
Income (Loss)  
 

   Total            

 

 

 

 Balance December 31, 2001

$8,081,082 

2,020,271 

10,101,353 

Distribution to  partners

(1,024,682)

(256,167)

(1,280,849)

Comprehensive  loss:

 

 

 

 Net loss

(3,389,214)

(847,303)

 

(4,236,517)

Change in fair  value of  outstanding 

  hedging   positions

 

  2,572 

 

Reclassification  adjustment  for settled 

  contracts  included in net income 

 

            -     

 

Other  comprehensive income

 

2,572 

     2,572 

Comprehensive loss

                      

                  

                    

(4,233,945)

 

 

 

Balance December 31, 2002

3,667,186 

916,801 

    2,572 

 4,586,559 

 

 

 

Distribution to  partners

(852,938)

(213,232)

(1,066,170)

Comprehensive  income:

 

 

 

 Net income:

407,819 

101,955 

 

509,774 

Change in fair  value of  outstanding 

  hedging   positions

 

  (1,345)

 

Reclassification  adjustment  for settled 

  contracts  included in net income

 

         (1,559)

 

Other  comprehensive loss

 

(2,904)

    (2,904)

Comprehensive  income

                      

                  

                    

   506,870 

 

 

 

Balance December 31, 2003

3,222,067 

  805,524 

    (332)

 4,027,259 

Distribution to  partners

(724,452)

(181,110)

(905,562)

Comprehensive  income:

 

 

 

 Net income:

486,479 

121,620 

 

608,098 

Change in fair  value of  outstanding 

  hedging   positions

 

  (25,138)

 

Reclassification  adjustment  for settled 

  contracts  included in net income 

 

      10,658 

 

Other  comprehensive loss

 

(14,480)

    (14,480)

Comprehensive  income

                  

                  

                  

   593,618 

 

 

 

Balance December 31, 2004

$2,984,094 

  746,034 

    (14,812)

 3,715,315 

See accompanying notes to financial statements.

F-6

PDC 2001-A LIMITEDPARTNERSHIP

(A West VirginiaLimited Partnership)

Statements of CashFlows

Years Ended December 31, 2004, 2003 and 2002

2004  

2003  

2002  

Cash flows from operating activities:

     Net income (loss)

$  608,098 

  509,774 

(4,236,517)

     Adjustments to reconcile  net income (loss) to 

      net cash used by  operating activities:

         Loss  on impairment of oil and gas properties

-    

-    

4,560,861

         Depreciation,  depletion and amortization

328,925 

451,881 

810,115 

         Cumulative  effect of accounting change

-     

2,218 

-    

         Accretion  of asset retirement obligation

492 

464 

-    

         Changes  in operating assets and liabilities:

          (Increase)  decrease in accounts receivable -oil and gas 

           revenues

  (36,122)

  92,283 

  134,492 

          Decrease  in accounts receivable - Managing 

           General  Partner

  -    

  -    

  7,523 

            Increase (decrease) in accrued expenses

    1,868

     (1,965)

          397 

               Net  cash provided from operating activities

 903,261 

 1,054,655 

1,276,871 

Cash flows from financing activities:

     Distributions to partners

(905,562)

(1,066,170)

(1,280,849)

               Net  cash used by financing activities

(905,562)

(1,066,170)

(1,280,849)

Net decrease in cash

(2,301)

(11,515)

(3,978)

Cash at beginning of period

    10,620 

    22,135 

    26,113 

Cash at end of period

$       8,319 

   10,620 

   22,135 

See accompanying notes to financial statements.

F-7

PDC 2001-A LIMITEDPARTNERSHIP

(A West VirginiaLimited Partnership)

Notes to FinancialStatements

December 31, 2004, 2003 and 2002

(1)    Summary of SignificantAccounting Policies

       PartnershipFinancial Statement Presentation Basis

The financialstatements include only those assets, liabilities and results of operations ofthe partners which relate to the business of PDC 2001-A Limited Partnership(the Partnership).  The statements do not include any assets, liabilities,revenues or expenses attributable to any of the partners' other activities. PetroleumDevelopment Corporation ("PDC") serves as Managing General Partner ofthe Partnership.

Oil and GasProperties

The Partnershipfollows the successful efforts method of accounting for the cost of exploringfor and developing oil and gas reserves.  Under this method, costs of developmentwells, including equipment and intangible drilling costs related to bothproducing wells and developmental dry holes, and successful exploratory wellsare capitalized and amortized on an annual basis to operations by theunits-of-production method using estimated proved developed reserves determinedat December 31, 2004 and 2003 by the Managing General Partner's petroleumengineers and at December 31, 2002 by an independent petroleum engineer, Wright& Company, Inc.  If a determination is made that an exploratory well hasnot discovered economically producible reserves, then its costs are expensed asdry hole costs.

The Partnershipassesses impairment of capitalized costs of proved oil and gas properties bycomparing net capitalized costs to undiscounted future cash flows on afield-by-field basis using expected prices. Prices utilized in each year'scalculation for measurement purposes and expected costs are held constantthroughout the estimated life of the properties.  If net capitalized costsexceed undiscounted future net cash flows, the measurement of impairment isbased on estimated fair value which would consider future discounted cashflows.  During 2002 the loss on impairment of oil and gas properties asreflected in the Statement of Operations amounted to $4,560,861.

Revenue Recognition

Sales of natural gas are recognized whennatural gas has been delivered to a custody transfer point, persuasive evidenceof a sales arrangement exists, the rights and responsibility of ownership passto the purchaser upon delivery, collection of revenue from the sale isreasonably assured and the sales price is fixed or determinable.  Natural gasis sold by the Managing General Partner under contracts with terms ranging fromone month to three years.  Virtually all of the Managing General Partner'scontracts pricing provisions are tied to a market index, with certainadjustments based on, among other factors, whether a well delivers to agathering or transmission line, quality of natural gas and prevailing supplyand demand conditions, so that the price of the natural gas fluctuates toremain competitive with other available natural gas supplies.  As a result, thePartnership's revenues from the sale of natural gas will suffer if marketprices decline and benefit if they increase.  The Partnership believes that thepricing provisions of its natural gas contracts are customary in the industry.

The Managing General Partner currentlyuses the "Net-Back" method of accounting for transportation arrangements ofnatural gas sales.  The Managing General Partner sells gas at the wellhead andcollects a price and recognizes revenues based on the wellhead sales pricesince transportation costs downstream of the wellhead are incurred by theManaging General Partner's customers and reflected in the wellhead price.

F-8

PDC 2001-A LIMITEDPARTNERSHIP

(A West VirginiaLimited Partnership)

Notes to FinancialStatements

Sales of oil are recognized whenpersuasive evidence of a sales arrangement exists, the oil is verified as producedand is delivered in a stock tank, collection of revenue from the sale isreasonably assured and the sales price is determinable.  The Partnership iscurrently able to sell all the oil that it can produce under existing salescontracts with petroleum refiners and marketers.  The Partnership does notrefine any of its oil production.  The Partnership's crude oil production issold to purchasers at or near the Partnership's wells under short-term purchasecontracts at prices and in accordance with arrangements that are customary inthe oil industry.

The Partnership soldoil and natural gas to several entities of which three customers accounted for38.0%, 37.3% and 17.3% of the Partnership's total oil and natural gas sales forthe year ended December 31, 2004, 22.3%, 22.7% and 32.9% for the year endedDecember 31,  2003, and 28.7%, 28.4% and 27.3% for the year ended December 31,2002.

 

Income Taxes

Since the taxableincome or loss of the Partnership is reported in the separate tax returns ofthe partners, no provision has been made for income taxes on the Partnership'sbooks.

Under federal incometax laws, regulations and administrative rulings, certain types of transactionsmay be accorded varying interpretations. Accordingly, the Partnership's taxreturn and, consequently, individual tax returns of the partners may be changedto conform to the tax treatment resulting from a review by the Internal RevenueService.

 

Derivative FinancialInstruments

The Managing GeneralPartner utilizes commodity based derivative instruments as hedges to manage aportion of the Partnership's exposure to price volatility stemming from naturalgas production. These instruments consist of costless collars and optioncontracts traded on the CIG (Colorado Interstate Gas Index). The costlesscollars and option contracts hedge committed and anticipated natural gas salesgenerally forecasted to occur within a 24 month period. The Partnership doesnot hold or issue derivatives for trading or speculative purposes.

All derivatives arerecognized on the Partnership balance sheet at their fair value.  On the datethe derivative contract is entered into, the Managing General Partnerdesignates the derivative as either a hedge of a forecasted transaction or thevariability of cash flows to be received or paid related to a recognized assetor liability ("cash flow" hedge), or a non-hedging derivative. The ManagingGeneral Partner formally documents all relationships between hedginginstruments and hedged items, as well as its risk-management objective andstrategy for undertaking various hedge transactions. This process includeslinking all derivatives that are designated as cash-flow hedges to specificfirm commitments. The Managing General Partner also formally assesses, both atthe hedge's inception and on an ongoing basis, whether the derivatives that areused in hedging transactions are highly effective in offsetting changes in cashflows of hedged items.  When it is determined that a derivative is not highlyeffective as a hedge or that it has ceased to be a highly effective hedge, the ManagingGeneral Partner discontinues hedge accounting prospectively.  No hedgingactivities were discontinued during 2004 or 2003.

Changes in fairvalue of a derivative that is highly effective and that is designated andqualifies as a cash-flow hedge are recorded in accumulated other comprehensiveincome (loss), until earnings are affected by the variability in cash flows ofthe designated hedged item. Changes in the fair value of non-hedging derivativesare reported in current-period earnings. The Managing General Partnerdiscontinues hedge accounting prospectively when it is determined that thederivative is no longer effective in offsetting changes in the cash flows ofthe hedged item, the derivative expires or is sold, terminated, or exercised.

F-9

PDC 2001-A LIMITEDPARTNERSHIP

(A West VirginiaLimited Partnership)

Notes to FinancialStatements

Additionally, if thederivative is designated as a hedging instrument, because it is probable that aforecasted transaction will not occur, or the Managing General Partnerdetermines that designation of the derivative as a hedging instrument is nolonger appropriate, hedge accounting will be discontinued.

By using derivative financial instruments to hedge exposuresto changes in commodity prices, the Managing General Partner exposes thePartnership to credit risk. Credit risk is the failure of the counterparty toperform under the terms of the derivative contract. When the fair value of aderivative contract is positive, the counterparty owes the Partnership, whichcreates credit risk. The Managing General Partner minimizes the credit risk inderivative instruments by entering into transactions with high-qualitycounterparties.

 

Use of Estimates

The Partnership hasmade a number of estimates and assumptions relating to the reporting of assetsand liabilities and revenues and expenses and the disclosure of contingentassets and liabilities to prepare these financial statements in conformity withaccounting principles generally accepted in the United States of America.Actual results could differ from those estimates. Estimates which areparticularly significant to the financial statements include estimates of oiland gas reserves and future cash flows from oil and gas properties which areused in assessing impairment of long-lived assets.

New AccountingStandards

In June 2001, theFinancial Accounting Standard Board issued FASB No. 143, "Accounting forAsset Retirement Obligations" that requires entities to record the fairvalue of a liability for an asset retirement obligation in the period in whichit is incurred and a corresponding increase in the carrying amount of therelated long-lived asset. This statement is effective for fiscal yearsbeginning after June 15, 2002. The Partnership adopted FASB No. 143 on January 1, 2003 and recorded a net asset of $5,511 and a related liability of $7,729(using a 6% discount rate) and a cumulative effect of change in accountingprinciple on prior years of $2,218.

 (2)    Organization

The Partnership wasorganized as a limited partnership on May 7, 2001, in accordance with the laws of the State of West Virginia for the purpose of engaging in the drilling,completion and operation of oil and gas development and exploratory wells inthe Rocky Mountain Region.

Purchasers ofpartnership units subscribed to and fully paid for 1.25 units of limitedpartner interest and 467.94 units of additional general partner interests at$20,000 per unit (Investor Partners). Petroleum Development Corporation hasbeen designated the Managing General Partner of the Partnership. Althoughcosts, revenues and cash distributions allocable to the limited and additionalgeneral partners are shared pro rata based upon the amount of their subscriptions,including the Managing General Partner to the extent of its capitalcontributions, there are significant differences in the federal income taxeffects and liability associated with these different types of units in thePartnership.

Upon completion ofthe drilling phase of the Partnership's wells, all additional general partnersunits are converted into units of limited partner interests and thereafterbecome limited partners of the Partnership.  Limited partners do not have anyrights to convert their units into units of additional general partnerinterests in the Partnership.

F-10

PDC 2001-A LIMITEDPARTNERSHIP

(A West VirginiaLimited Partnership)

Notes to FinancialStatements

In accordance withthe terms of the Limited Partnership Agreement (the Agreement), the ManagingGeneral Partner manages all activities of the Partnership and acts as theintermediary for substantially all Partnership transactions.

(3)    Transactions with ManagingGeneral Partner and Affiliates

Pursuant to theauthorization contained in the Agreement, PDC receives fees for servicesrendered and reimbursement of certain expenses from the Partnership.  Seerespective drilling prospectus for further information regarding the Agreement.The following table presents compensation or reimbursements by the Partnershipto PDC or other related parties for years ended December 31, 2004 and 2003 and 2002.

                      

                                                                                          Year Ended December 31, 

2004

2003

2002

Lifting costs

$315,302

353,519

356,040

Tax return  preparation

4,453

5,657

3,495

Direct  administrative cost

1,938

1,880

1,832

(4)     Allocation

Thetable below summarizes the participation of the Managing General Partner andthe Investor Partners, taking account of the Managing General Partner's capitalcontribution equal to a minimum of 20% of the initial capital, in the costs andrevenues of the Partnership.

  Partnership Costs

          Investor

        Partners(5)(6)

       Managing

        General

        Partner  (5)(6)

Broker-dealer  Commissions and Expenses(1)

100%

 0%

Management Fee(2)

100%

 0%

Lease Costs

 0%

100%

Tangible Well  Costs

 0%

100%

Intangible  Drilling and Development Costs

100%

 0%

Total Drilling and  Completion Costs

80%

20%

Operating Costs(3)

80%

20%

Direct Costs(4)

80%

20%

Administrative  Costs

 0%

100%

Partnership  Revenues

Sale of Oil and Gas  Production

80%

20%

Sale of Productive  Properties

80%

20%

Sale of Equipment 

 0%

100%

Sale of Undeveloped  Leases . 

80%

20%

Interest Income

80%

20%

____________________

(1)  Organizationand offering costs, net of the dealer manager commissions, discounts, duediligence expenses, and wholesaling fees of the Partnership were paid by theManaging General Partner and not from Partnership funds.  In addition,organization and offering costs in excess of 10-1/2% of Subscriptions, if any,  werepaid by the Managing General Partner, without recourse to the Partnership.

(2)  Representsa one-time fee paid to the Managing General Partner on the day the Partnershipis funded equal to 2-1/2% of total investor subscriptions.

F-11

PDC 2001-A LIMITEDPARTNERSHIP

(A West VirginiaLimited Partnership)

Notes to FinancialStatements

(3)   RepresentsOperating costs incurred after the completion of productive wells, includingmonthly per-well charges paid to the Managing General Partner.

(4)   TheManaging General Partner receives monthly reimbursement from the Partnershipfor direct costs incurred by the Managing General Partner on behalf of thePartnership.

(5)  Tothe extent that Investor Partners receive preferred cash distributions, theallocations for Investor Partners will be increased accordingly and theallocation for the Managing General Partner will likewise be decreased.

(6)  Theallocation of profits, losses and cash distributions of the Managing GeneralPartner might be increased, and the allocation of profits, losses, and cashdistributions of the Investor Partners might be decreased in the event that theManaging General Partner were to invest more than the Managing GeneralPartner's minimum required Capital Contribution to cover tangible equipment andlease costs. The Managing General Partner will pay for the Partnership's shareof all Leases and tangible well equipment. The entire Capital Contribution ofthe Investor Partners, after payment of brokerage commissions, due diligencereimbursement, and the Management Fee, was utilized to pay for intangibledrilling costs. In the event that the Intangible Drilling Costs exceed thefunds of the        Investor Partners available for payment of IntangibleDrilling Costs (herein "excess IDC"), a portion of the CapitalContribution of the Managing General Partner may be used to pay such excessIDC. If the cost of Leases and tangible well equipment were to exceed theManaging General Partner's Capital Contribution of 21-3/4% of the aggregateCapital Contribution of the Investor Partners, then the Managing GeneralPartner will increase its Capital Contribution to fund such additional capitalrequirements and the Managing General Partner's allocation of profits, losses,and cash distributions will be increased to equal the percentage arrived at bydividing the Capital Contribution made by the Managing General Partner by theCapital Available for Investment; the allocation of the Investor Partners willbe decreased accordingly.

(7)  Inaccordance with the repurchase provision of the partnership prospectus, PDC mayrepurchase units from the investor partners, which is entirely voluntary on thepart of the partners.  During 2004 PDC purchased a total of .5 units ofpartnership interest for a total ownership of .7717 units as of December 31, 2004 which represents a .001645% ownership of the original Investor Partnersshare of limited and general partnership units. Therefore, costs and revenuesand distributions for those purchased units are allocated to PDC in accordancewith the Investor Partners allocation percentages disclosed in this table.

(5)  Derivative Financial Instruments

The Managing General Partner utilizescommodity-based derivative instruments as hedges to manage a portion of itsexposure to price risk from its oil and natural gas sales.  These instrumentsconsist of CIG-based contracts traded by JP Morgan for Colorado production. These hedging arrangements have the effect of locking in for specified periods(at predetermined prices or ranges of prices) the prices the Managing GeneralPartner will receive for the volume to which the hedge relates.  As a result,while these hedging arrangements are structured to reduce the Partnership'sexposure to changes in price associated with the hedged commodity, they alsolimit the benefit the Partnership might otherwise have received from pricechanges associated with the hedged commodity.  The Managing General Partner's policy prohibits the use of natural gas futureand option contracts for speculative purposes.

F-12

PDC 2001-A LIMITEDPARTNERSHIP

(A West VirginiaLimited Partnership)

Notes to FinancialStatements

The following tablessummarize the open futures and options contracts for the Partnership as of December 31, 2004 and 2003.

Commodity

Type

Quantity

Weighted  

Total

Fair

Gas-Mmbtu

Average

Contract

Market

 

 

Oil-Barrels

Price

Amount

Value

Total Contracts as of December 31, 2004

 Natural  Gas

Floors

31,019

4.16

-    

7,509 

Natural  Gas

Ceilings

15,509

5.36

-    

(9,771)

Oil

Floors  

6,774

32.30

218,816

5,772 

Oil

Ceilings

3,387

40.00

135,490

(18,322)

Contracts maturing in 12 months following December 31, 2004 

Natural  Gas

Floors

31,019

4.16

-    

7,509 

Natural  Gas

Ceilings

15,509

5.36

-    

(9,771)

Oil

Floors

6,774

32.30

218,816

5,772 

Oil

Ceilings

3,387

40.00

135,490

(18,322)

Prior Year Total Contracts as of December 31, 2003

Natural  Gas

Floors

21,813

3.28

-    

-    

Natural  Gas

Ceilings

21,813

4.84

-    

(332)

The maximum termover which the Partnership is hedging exposure to the variability of cash flowsfor commodity price risk is 12 months.

(6)    Costs Relating to Oil andGas Activities

The Partnership isengaged solely in oil and gas activities, all of which are located in thecontinental United States.  Information regarding aggregate capitalized costsand results of operations for these activities is located in the basicfinancial statements.  Costs capitalized for these activities are as follows:

                December  31,                     

 
 
2004

2003

2002

 
Lease acquisitions at cost

$324,923 

324,923 

324,923 

 
Intangible development costs

8,163,904 

8,163,904 

8,163,904 

 
Well equipment

1,716,053 

1,716,053 

 1,716,053 

 
Impairment charges

(4,560,861)

(4,560,861)

 (4,560,861)

 
Capitalized asset retirement cost

        7,292 

      7,292  

           -    

 
$5,651,311 

5,651,311 

5,644,019 

There were no costs incurred for the Partnership's oiland gas activities for the years ended December 31, 2004, 2003 and 2002.

(7)    Income Taxes

As a result of thedifferences in the treatment of certain items for income tax purposes asopposed to financial reporting purposes, primarily depreciation, depletion andamortization of oil and gas properties and the recognition of intangibledrilling costs as an expense or capital item, the income tax basis of oil andgas properties differs from the basis used for financial reporting purposes. At December 31, 2004 and 2003, the income tax basis of the Partnership's oil andgas properties was $936,293 and $1,175,600, respectively.

F-13

PDC 2001-A LIMITEDPARTNERSHIP

(A West VirginiaLimited Partnership)

Notes to FinancialStatements

(8)    Supplemental ReserveInformation (Unaudited)

Proved oil and gasreserves of the Partnership have been estimated at December 31, 2004 and 2003 by the Managing General Partner's petroleum engineers and at December 31, 2002 by an independent petroleum engineer, Wright & Company, Inc. These reserveshave been prepared in compliance with the Securities and Exchange Commissionrules based on year end prices. A copy of the reserve report has been madeavailable to all partners. All of the partnership's reserves are proveddeveloped. An analysis of the change in estimated quantities of proveddeveloped oil and gas reserves is shown below:

Oil  (Bbls)

2004

2003

2002

Proved developed reserves:

Beginning of year

226,000 

239,000 

313,000 

Revisions of previous estimates

(13,000) 

5,000 

(40,000)

Production

(12,000)

(18,000)

(34,000)

End of Year

201,000 

226,000 

239,000 

Gas  (MCF)

2004

2003

2002

Proved developed reserves:

Beginning of year

2,251,000 

2,094,000 

2,750,000 

Revisions of previous estimates

15,000 

367,000 

 (346,000)

Production

(156,000)

(210,000)

(310,000)

End of Year

2,110,000 

2,251,000 

2,094,000 

(9)  Standardized Measure of DiscountedFuture Net Cash Flows and Changes Therein Relating to Proved Oil

        andGas Reserves (Unaudited)

Summarizedin the following table is information for the Partnership with respect to thestandardized measure of discounted future net cash flows relating to proved oiland gas reserves.  Future cash inflows are computed by applying year-end pricesof oil and gas relating to the Partnership proved reserves to the year-endquantities of those reserves.  Future production, development, site restorationand abandonment costs are derived based on current costs assuming continuationof existing economic conditions. 

As of  December 31,

2004

2003

2002

Future estimated revenues

 $   22,420,000 

    18,883,000 

14,342,000 

Future estimated production costs

(5,378,000)

(5,110,000)

(3,690,000)

Future estimated development costs

(1,299,000)

(1,299,000)

(1,299,000)

   Future net cash flows

15,743,000 

12,474,000 

9,353,000 

10% annual discount for estimated timing of cash flows

(7,540,000)

(5,992,000)

(4,435,000)

Standardized measure of discounted future

   estimated net cash flows

$8,203,000 

6,482,000 

4,918,000 

F-14

PDC 2001-A LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Notes to Financial Statements

The following table summarizes the principal sources of change in thestandardized measure of discounted future estimated net cash flows:

As of  December 31,

2004

2003

2002

Sales of oil and gas production, net of production  costs

$(947,000)

 (974,000)

(1,146,000)

Net changes in prices and production costs

4,441,000 

3,194,000 

3,832,000 

Extensions, discoveries, and improved recovery,     less related cost

  -    

  -    

  -    

Revisions of previous quantity estimates

(225,000) 

901,000 

(971,000)

Accretion of discount

(1,548,000)

(1,557,000)

 

(950,000)

 $1,721,000 

1,564,000 

  765,000 

It isnecessary to emphasize that the data presented should not be viewed asrepresenting the expected cash flow from, or current value of, existing provedreserves since the computations are based on a large number of estimates andarbitrary assumptions.  Reserve quantities cannot be measured with precisionand their estimation requires many judgmental determinations and frequentrevisions.  The required projection of production and related expenditures overtime requires further estimates with respect to pipeline availability, rates ofdemand and governmental control. Actual future prices and costs are likely tobe substantially different from the current prices and costs utilized in thecomputation of reported amounts.  Any analysis or evaluation of the reportedamounts should give specific recognition to the computational methods utilizedand the limitations inherent therein.

F-15 |
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