CONFORMED COPY

SECURITIES ANDEXCHANGE COMMISSION

Washington, D.C.  20549

Form 10-K

[X]ANNUAL REPORTPURSUANT TO SECTION 13 or 15 (d) OF

THE SECURITIESEXCHANGE ACT OF 1934

For the fiscal yearended December 31, 2004

Commission FileNumber  001-31264

[]Transition Report Pursuant to Section 13 or 15(d) of the SecuritiesExchange Act of 1934 for the transaction period from         to         

PDC 2001-C LIMITEDPARTNERSHIP

(Exact name ofregistrant as specified in its charter)

| West Virginia

(State or other jurisdiction of incorporation or  organization) | 02-0533219

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 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  X    No     

Indicate by check mark if disclosure of delinquent filerspursuant to Item 405 of Regulation S-K is not contained herein, and will becontained, to the best of registrant's knowledge, in definitive proxy orinformation statements incorporated by reference in Part III of this Form 10-Kor 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 trading market for the registrant's securities.

PART I

ITEM 1.  BUSINESS.

General

     PDC 2001-C LimitedPartnership ("the Partnership") is a limited partnership formed on November 9, 2001 pursuant to the West Virginia Uniform Limited Partnership Act.  PetroleumDevelopment Corporation ("PDC") serves as Managing General Partner ofthe Partnership.

     Since the commencement ofoperations on November 9, 2001, the Partnership has been engaged in onshore,domestic oil and natural gas exploration exclusively in the Rocky MountainRegion.  A total of 9 limited partners contributed initial capital of $430,000;a total of 586 additional general partners contributed initial capital of$10,197,234; and PDC (Managing General Partner) contributed $2,311,423 incapital as a participant in accordance with contribution provisions of theLimited Partnership Agreement (the Agreement). During 2002 in accordance withthe Partnership 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 are allocated.Leasehold, drilling and completion costs, and equipment costs are borne 80% bythe Additional General and Limited Partners and 20% by the Managing GeneralPartner. See Footnote 4 of financial statements for a complete description ofthe allocation of Partnership revenue and costs.

Employees

     The Partnership has no employees;however, PDC has approximately 120 employees, including 17 in finance and dataprocessing, 8 in administration, 12 in exploration and development, 78 inproduction and 5 in natural gas marketing. 

Plan of Operations

     The Partnershipparticipated in the drilling of eighteen gross (15.53 net) wells (all of whichare productive) and will continue to operate and produce its nineteenproductive wells. The Partnership does not have unexpended initial capital andno additional drilling activity 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 the Partnershipwells to and the capacity of natural gas pipelines, the availability and priceof competitive fuels, fluctuations in seasonal supply and demand, andgovernment regulation of supply and demand created by its pricing andallocation restrictions.  Oversupplies of gas can be expected to occur fromtime to time and may result in the Partnership's wells being shut-in orcurtailed.  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 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 two customers accounted for 58.8% and 41.2% of thePartnership's total oil and natural gas sales for the year ended December 31, 2004 and 66.7% and 28.3% in 2003, respectively.

 

 

2

Derivatives and 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 NYMEX-traded natural gas futures and option contractsfor eastern Colorado production, and CIG (Colorado Interstate Gas Index)-basedcontracts for other Colorado production and NYMEX traded oil futures and optioncontracts for Colorado oil production.  The contracts hedge committed andanticipated natural gas sales, generally forecasted to occur within the nexttwo year period. The Managing General Partner does not hold or issuederivatives for trading or speculative purposes and permits utilization ofhedges only if there is an underlying physical position.  See "CommodityPrice 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 $5,438      and $6,700 in 2004 and 2003, respectively to complywith 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 to be sold by the Partnership is not regulated byany state 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 SafetyRegulation.  The Partnership believes that it complies, in all materialrespects, with all legislation and regulations affecting its operations in thedrilling and production of oil and gas wells and the discharge of wastes.  Todate, compliance with such provisions and regulations has not had a materialeffect upon the Partnership's expenditures for capital equipment, itsoperations or its competitive position.  The cost of such compliance is notanticipated to be material in the future.

                                                                                                  3                                           

 

 

ITEM 2.  PROPERTIES.

Drilling Activity

     The following table sets forth theresults of the Partnership's drilling activity from November 9, 2001 (date of inception) to December 31, 2004.  All of the Partnership's wells drilled andproducing are located in Colorado.

|                     Development  Wells                      |
|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
|        Gross  Wells                                                                                                                                        |           Net  Wells              |
| Productive                                                                                                                                                                                                                                                               | Dry | Total | Productive | Dry | Total |
| 18                                                                                                                                                                                                                                                                       | - | 18 | 15.53 | - | 15.53 |

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

Production 

See "Management's Discussion and Analysis" on page5 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 18 gross productive wells (15.53 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 toliens incident to operating agreements, liens for current taxes and otherburdens.  The Partnership believes that none of these burdens materiallyinterfere with the use of such properties in the operation of the Partnership'sbusiness.

     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 SECURITY HOLDERS.

NONE

 

 

 

 

 

4

 

 

 

 

PART II

 

ITEM 5.  MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATEDSTOCKHOLDER MATTERS.

     At December 31, 2001, PDC 2001-C LimitedPartnership had one Managing General Partner, 9 Limited Partners who fully paidfor 21.5 units at $20,000 per unit of limited partnership interests and a totalof 586 Additional General

Partners who fullypaid for 509.8617 units at $20,000 per unit of additional general partnershipinterests. During 2002 in

accordance with the Partnership Agreement, all AdditionalGeneral Partners were converted to Limited Partners. At December 31, 2003, the Partnership had one Managing General Partner and 595 limited partners who paidfor 531.3617 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.

ITEM 6.  SELECTED FINANCIAL DATA.

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

|                                                              | Year Ended

December 31, 2004 | Year Ended

December 31, 2003 | Year Ended

December 31, 2002 |
|--------------------------------------------------------------|-------------------------------|-------------------------------|-------------------------------|
| Oil and Gas Sales                                            | $1,366,254                    | $2,104,889               | $1,741,435               |
| Costs and Expenses                                           | 1,141,585                     | 1,468,291                | 1,591,433                |
| Cumulative Effect of change in accounting principle          | -                             | (829)                         | -              |
| Net Income                                                   | 225,255                       | 636,762                  | 150,668                  |
| Allocation of Net Income:                                    |                               |                               |                               |
|   Managing General Partner                         | 45,051                        | 127,352                  | 30,134                   |
|   Limited and Additional General Partners          | 180,204                       | 509,410                  | 120,534                  |
|   Per Limited and Additional General Partner  Unit | 339                           | 959                      | 227                      |
| Total Assets                                                 | 9,204,457                     | 9,865,494                | 10,849,189               |
| Cash Distributions                                           |                               |                               |                               |
|   Managing General Partner                         | 180,307                       | 325,021                  | 213,837                  |
|   Limited and Additional General Partners          | 721,232                       | 1,300,092                | 855,354                  |

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

Liquidity and Capital Resources

     ThePartnership was funded on November 9, 2001 with initial Limited and AdditionalGeneral Partner contributions of $10,627,234 and the Managing General Partner'scash contribution of $2,311,423 in accordance with the Agreement.  Afterpayment of syndication costs of $1,115,860 and a one-time management fee to themanaging general partner of $265,681 the Partnership had available cash of$11,557,116 for Partnership activities. During2002 the Managing General Partner made an additional capital contribution inthe amount of $199,371 which was expended for the development of oil and gasproperties.

     The Partnership had workingcapital at December 31, 2004 of $243,024.

     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

     Oiland gas sales for the year ended December 31, 2004 were $1,366,254 compared to $2,104,889 for the year ended December 31, 2003.  For the year ended December 31, 2004, the Partnership sold 143,798  Mcf of gas and 16,374 barrels ofoil at average sales prices of $5.22 and $37.57, respectively.  This comparedwith 395,773 Mcf of gas and 21,635 barrels of oil sold at average sales pricesof $3.66 and $30.40, respectively for the year ended December 31, 2003.  Lifting cost per Mcfe in 2004 amounted to $1.89 as compared to $1.00 for 2003.This increase is partially attributed to the increase in severance and propertytaxes on the significantly higher oil & gas prices along with additional wellworkovers. The fixed costs of operations and well maintenance are allocated tolower production volumes, therefore increasing the lifting cost per Mcfe.   Depreciation, depletion and amortizationdecreased from $926,200 for the year ended December 31, 2003 to $675,235 for the year ended December 31, 2004 as a result of lower volumes of natural gasand oil sold. Cash distributions to the partners amounted to $901,539 in2004.

2003 Results Compared to 2002

     Oiland gas sales for the year ended December 31, 2003 were $2,104,889 compared to $1,741,435 for the year ended December 31, 2002.  For the year ended December 31, 2003, the Partnership sold 395,773 Mcf of gas and 21,635 barrels ofoil at average sales prices of $3.66 and $30.40, respectively.  This comparedwith 442,568 Mcf of gas and 33,875 barrels of oil sold at average sales pricesof $2.01 and $25.09, respectively for the year ended December 31, 2002. Lifting cost per Mcfe in 2003 amounted to $1.00 as compared to $0.52 for 2002. Thisincrease 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 $1,242,841 for the year ended December 31, 2002 to $926,200 for the year ended December 31, 2003 as a result of lower volumes of natural gas and oilsold. Cash distributions to the partners amounted to $1,625,113 in 2003.

     The Partnership's revenuesfrom oil and natural gas sales will be affected by changes in prices.  As aresult of changes in federal regulations, gas prices are highly dependent onthe balance between supply and demand. The Partnership's gas sales prices aresubject 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 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.

           Salesof oil are recognized when persuasive evidence of a sales arrangement exists,the oil is verified as produced and is delivered in a stock tank, collection ofrevenue from the sale is reasonably assured and the sales price isdeterminable.  The Partnership is currently able to sell all the oil that itcan produce under existing sales contracts with petroleum refiners andmarketers.  The Partnership does not refine any of its oil production.  ThePartnership's crude oil production is sold to purchasers at or near thePartnership's wells under short-term purchase contracts at prices and inaccordance with arrangements that are customary in the oil industry.

Accounting forDerivative 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. 

     Derivatives are reported on the BalanceSheets at fair value. Changes in fair value of derivatives that are notdesignated as accounting hedges are recorded in earnings.

    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 involvesjudgment and estimates. These estimates are based on valuation methodologiesconsidered appropriate 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 assessesimpairment of capitalized costs of proved oil and gas properties by comparingnet capitalized 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.

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 have discoveredeconomically producible reserves.  If reserves are not discovered, such costsare expensed as dry holes.  Development costs, including equipment andintangible drilling costs related to both producing wells and developmental dryholes are capitalized.

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

7

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

      Upon sale or retirement of complete fields ofdepreciable or depletable property, the book value thereof, less proceeds orsalvage value, is credited or charged to income.  Upon sale of a partial unitof property, the proceeds are credited to accumulated depreciation anddepletion.

New Accounting Standards

In June 2001, the Financial Accounting Standard Boardissued FASB No. 143, "Accounting for Asset Retirement

Obligations" that requires entities to record thefair value 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 $7,169 and a related liability of $7,998(using a 6% discount rate) and a cumulative effect of change in accountingprinciple on prior years of $829.

Item 7A. Quantitative and Qualitative Disclosure AboutMarket 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 Partnership willreceive for the volume to which the hedge relates.  As a result, while thesehedging arrangements are structured to reduce the Partnership's exposure tochanges in price associated with the hedged commodity, they also limit thebenefit the Partnership might otherwise have received from price changesassociated with the hedged commodity.  The Partnership's policy prohibits theuse of natural gas future and option contracts for speculative purposes.

The following tables summarize the open futures andoptions contracts for the Partnership as of December 31, 2004 and 2003.

| Commodity | Type | Quantity

Gas-Mmbtu

Oil-Barrels | Weighted

Average   Price | Total

Contract

Amount | Fair

Market

Value |
|-----------|------|----------------------------------|---------------------------|-------------------------|---------------------|

Total Contracts as of December 31, 2004

| Natural Gas | Floors   | 26,828 | 4.36  | -       | 7,657  |
|-------------|----------|--------|-------|---------|-------------|
| Natural Gas | Ceilings | 13,414 | 5.56  | -       | (6,956)     |
| Oil         | Floors   | 8,178  | 32.30 | 264,155 | 6,967  |
| Oil         | Ceilings | 4,089  | 40.00 | 163,564 | (22,118)    |
|             |          |        |       |         |             |

Contracts maturing in 12 months following December 31 , 2004

| Natural Gas | Floors   | 26,828 | 4.36  | -       | 7,657  |  |  |  |
|-------------|----------|--------|-------|---------|-------------|--|--|--|
| Natural Gas | Ceilings | 13,414 | 5.56  | -       | (6,956)     |  |  |  |
| Oil         | Floors   | 8,178  | 32.30 | 264,155 | 6,967  |  |  |  |
| Oil         | Ceilings | 4,089  | 40.00 | 163,564 | (22,118)    |  |  |  |
|             |          |        |       |         |             |  |  |  |

Prior Year Total Contracts as of December 31, 2003

| Natural Gas | Floors   | 16,754 | 3.28 | - | -     |
|-------------|----------|--------|------|---|-------|
| Natural Gas | Ceilings | 16,754 | 4.84 | - | (255) |

The maximum term over which the Partnership is hedgingexposure to the variability of cash flows for commodity price risk is 12months.

The average CIG closing price for natural gas for theyears 2004, 2003 and 2002 was $5.17 per Mmbtu, $4.04 per Mmbtu and $1.97 perMmbtu. Future near-term gas prices will be affected by various supply anddemand factors such as weather, government and environmental regulations andnew drilling activities within the industry.

8

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 WITH ACCOUNTANTS ONACCOUNTING AND

        FINANCIAL DISCLOSURE.

        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

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.  The following table presents compensation or reimbursements bythe Partnership to PDC or other related parties during the years ended December 31, 2004, 2003 and 2002.

9

                                                                                            December 31,

|                               | 2004                                                                                           | 2003                                                                      | 2002   |
|-------------------------------|------------------------------------------------------------------------------------------------|---------------------------------------------------------------------------|------------------|
| Drilling and completion costs |         $         - |         -     | 199,371     |
| Lifting costs                 | 456,281                                                                                        | 527,952                                                              | 335,536     |
| Tax return preparation        | 5,473                                                                                          | 6,927                                                                | 4,175       |
| Direct administrative cost    | 866                                                                                            | 3,606                                                                | 2,840       |

ITEM 14.  PRINCIPAL ACCOUNTANT FEES ANDSERVICES 

     For the years endedDecember 31, 2004 and 2003, the Partnership paid KPMG LLP $3,220 and $3,126,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. Since the Partnership does not have an AuditCommittee, the Managing General Partner's Audit Committee also serves for thePartnership.  The Audit Committee has adopted policies and procedures forpre-approval of all audit services and non-audit services to be provided by thePartnership's independent accountants. Services necessary to conduct the annualaudit must be pre-approved by the Audit Committee or by the authorized AuditCommittee member. 

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES.

                            (1)       FinancialStatements

                                        See Index toFinancial Statements on F-2

                            (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 May 25, 2001, of PDC 2003 Drilling Program, filed with the SEC on May 30, 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. |

10

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-C Limited Partnership

By its Managing General Partner

Petroleum Development Corporation

 
By /s/ Steven R. Williams      

   Steven R. Williams, Chairman

April 14, 2005

     Pursuant to therequirements of the Securities Exchange Act of 1934, this report has beensigned below by the following persons on behalf of the Registrant and in thecapacities and on the dates indicated:

Signature

Title

Date

/s/ Steven R. Williams

    Steven R. Williams

Chairman, Chief Executive Officer and

 Director 

April 14, 2005

/s/ Darwin L. Stump 

    Darwin L. Stump

Chief Financial Officer and Treasurer

(principal financial and accounting officer)

April 14, 2005

 

/s/ Thomas E. Riley 

    Thomas E. Riley

President and Director

April 14, 2005

/s/ Donald B. Nestor

    Donald B. Nestor

Director

April 14, 2005

/s/ Vincent F. D'Annunzio

    Vincent F. D'Annunzio

Director

April 14, 2005

11

PDC 2001-C LIMITEDPARTNERSHIP

(A West VirginiaLimited Partnership)

Financial Statementsfor Annual Report

on Form 10-K toSecurities and Exchange

Commission

Years Ended December31, 2004, 2003 and

2002

(With Independent RegisteredPublic Accounting Firm's Report Thereon)

F-1

PDC 2001-C 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 the Partners

PDC 2001-C LimitedPartnership:

We have audited theaccompanying balance sheets of PDC 2001-C Limited Partnership (a West Virginia limited partnership) as of December 31, 2004 and 2003, and the relatedstatements of operations, partners' equity and comprehensive income (loss), andcash 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.

We conducted our audits inaccordance with the standards of the Public Company Accounting Oversight Board(United States).  Those standards require that we plan and perform the audit toobtain reasonable assurance about whether the financial statements are free ofmaterial misstatement.  An audit includes examining, on a test basis, evidencesupporting the amounts and disclosures in the financial statements.  An auditalso includes assessing the accounting principles used and significantestimates made by management, as well as evaluating the overall financialstatement presentation.  We believe that our audits provide a reasonable basisfor our opinion.

In our opinion, thefinancial statements referred to above present fairly, in all materialrespects, the financial position of PDC 2001-C Limited Partnership as ofDecember 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 discussed in note 1 tothe financial statements, the Partnership adopted the provisions of Statementof Financial Accounting Standards No. 143, "Accounting for Asset Retirement Obligations",in 2003.

                                                                                                                                                                                        

                                                                                                                                                                    KPMGLLP

Pittsburgh, Pennsylvania 

April 15, 2005

F-3

PDC 2001-C LIMITEDPARTNERSHIP

(A West VirginiaLimited Partnership)

Balance Sheets

December 31, 2004 and 2003

Assets

 

Current assets:

2004

2003  

 Cash

$ 2,413

1,967 

 Account  receivable - oil and gas revenues

  282,664

268,912 

         Total  current assets

285,077

270,879 

Oil and gas properties, successful efforts method 

    (notes 3 and 6): 

11,764,033

  11,764,033 

      Less accumulated  depreciation,

       depletion and  amortization

 

2,844,653

 2,169,418 

8,919,380

 9,594,615 

$9,204,457

9,865,494 

Liabilities and Partners' Equity

Current liabilities:

   Accrued expenses

$42,053

    13,120 

         Total  current liabilities

42,053

13,120 

Asset retirement obligation

8,987

8,478 

Partners' equity

9,153,417

9,843,896 

$9,204,457

9,865,494 

See accompanying notes to financial statements.

F-4

PDC 2001-C LIMITEDPARTNERSHIP

(A West VirginiaLimited Partnership)

Statements ofOperations

Years Ended December 31, 2004, 2003 and 2002

2004

2003

2002   

Revenues:

    Sales of oil and gas

$1,366,254 

2,104,889 

1,741,435 

 
    Interest income

     585 

      993 

      666 

 
1,366,839 

2,105,882 

1,742,101 

 
Expenses (note 3):

 
    Lifting costs

456,281 

527,952 

335,536 

 
    Independent engineering fee

-    

-    

3,006 

 
    Independent audit fee

3,220

3,126

3,035 

 
    Tax return preparation

5,473

6,927

4,175 

 
    Direct administrative cost

1,375

4,086

    2,840 

 
    Depreciation, depletion and 

     amortization

  675,235 

  926,200 

1,242,841 

 
 
1,141,585 

1,468,291 

1,591,433 

 
 

 

 

 
Income before  cumulative effect of change in 

 accounting  principle

225,255 

637,591 

150,668 

 
 
Cumulative effect  of change in accounting principle

           -    

        (829)

        -    

 
 
Net income 

$  225,255 

  636,762 

  150,668 

 
 

 

 

Net income per  limited and additional 

 general  partner unit before cumulative effect of 

 change in  accounting principle

$   339

    960 

  227 

Cumulative effect  of change in accounting 

 principle

          -

          (1)

          -    

Net income per  limited and 

 additional  general partner unit

$     339 

       959 

       227 

 

 

 

    See accompanying notes to financial statements.

F-5

PDC 2001-C LIMITED PARTNERSHIP

(A West VirginiaLimited Partnership)

Statements ofPartners' Equity

And ComprehensiveIncome (Loss)

Years Ended December 31, 2004, 2003 and 2002

Limited and 

additional

general

partners  

Managing 

general 

Partner     

Accumulated

Other

Comprehensive
Income     
 

   Total   

Balance December 31, 2001

$9,241,323 

2,310,331 

11,551,654 

Capital  contribution

199,371 

199,371 

Distribution to  partners

(855,354)

(213,837)

(1,069,191)

Comprehensive  income:

 

 

 

 Net income

120,534 

30,134 

 

150,668 

Change in fair  value of  outstanding 

  hedging  positions 

 

  2,391 

 

Reclassification  adjustment  for settled 

  contracts  included in net income 

 

 

Other  comprehensive income

 

2,391 

     2,391 

Comprehensive  income 

          

          

           

   153,059 

 

 

 

Balance December 31, 2002

8,506,503 

2,325,999 

2,391 

10,834,893 

 

 

 

Distribution to  partners

(1,300,092)

(325,021)

(1,625,113)

Comprehensive  income:

 

 

 

 Net income:

509,410 

127,352 

 

636,762 

Change in fair  value of  outstanding 

  hedging   positions

 

  (1,448)

 

Reclassification  adjustment  for settled 

  contracts  included in net income 

 

            (1,198)

 

Other  comprehensive loss

 

(2,646)

    (2,646)

Comprehensive  income

                      

                  

                    

   634,116 

 

 

 

Balance December 31, 2003

7,715,821

2,128,330

(255)

9,843,896

Distribution to  partners

(721,232)

(180,307)

(901,539)

Comprehensive  income:

 

 

 

 Net income:

180,204

45,051

 

225,255

Change in fair  value of  outstanding 

  hedging   positions

 

  (22,024)

 

Reclassification  adjustment  for settled 

  contracts  included in net income 

 

         7,829

 

Other  comprehensive loss

 

(14,195)

   (14,195)

Comprehensive  income

                      

                  

                   

   211,060 

 

 

 

Balance December 31, 2004

$7,174,793

1,993,074

(14,450)

9,153,417

 

 

See accompanying notes to financialstatements.

F-6

 

 

 

 

 

 

 

 

 

 

 

 

    

                                                                PDC2001-C LIMITED PARTNERSHIP

(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

$    225,255

    636,762 

150,668 

   Adjustments to reconcile net income 

    to net cash used by operating  activities:

       Depreciation,  depletion and

         amortization

  675,235

  926,200 

  1,242,841 

       Cumulative  effect of change in accounting principle

- 

829 

-    

       Accretion of  asset retirement obligation

509 

480 

-    

       Changes in  operating assets and liabilities:

       Decrease  (increase) in accounts receivable -

         oil  and gas revenues

872

63,169 

(332,082)

       Decrease in  due to  Managing General Partner

-    

-    

(109)

       Increase (decrease)  increase in accrued expenses

         114

    (1,430)

     2,155 

              Net  cash provided from

               operating  activities

   901,985 

   1,626,010 

   1,063,473 

Cash flows from investing activities:

   Expenditures for oil and gas  properties

      -    

      -    

  (199,371)

              Net  cash used by  

               investing  activities

        -    

        -    

    (199,371)

Cash flows from financing activities:

   Managing General Partner contribution

-    

-    

   199,371 

   Distributions to partners

(901,539)

(1,625,113)

(1,069,191)

              Net  cash used by 

              financing  activities

  (901,539)

  (1,625,113)

    (869,820)

Net increase (decrease) in cash

446 

897 

(5,718)

Cash at beginning of period

     1,967

     1,070 

     6,788 

Cash at end of period

$    2,413

   1,967 

    1,070 

See accompanying notes to financial statements.

F-7

PDC 2001-C LIMITEDPARTNERSHIP

(A West VirginiaLimited Partnership)

Notes to FinancialStatements

December 31, 2004, 2003 and 2002

(1) Summary of Significant Accounting Policies

PartnershipFinancial Statement Presentation Basis

The financialstatements include only those assets, liabilities and results of operations of thepartners which relate to the business of PDC 2001-C Limited Partnership (thePartnership).  The statements do not include any assets, liabilities, revenuesor 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 ofdevelopment wells, including equipment and intangible drilling costs related toboth producing wells and developmental dry holes, and successful exploratorywells are 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 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 flow, the measurement of impairment isbased on estimated fair value which would consider future discounted cashflows.  

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 certain adjustmentsbased on, among other factors, whether a well delivers to a gathering ortransmission line, quality of natural gas and prevailing supply and demandconditions, so that the price of the natural gas fluctuates to remaincompetitive 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.

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. 

F-8

PDC 2001-C LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Notes to Financial Statements

 

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 option contractstraded on the New York Mercantile Exchange.  The costless collars and optioncontracts hedge committed and anticipated natural gas sales generallyforecasted to occur within a 12 month period. The Partnership does not hold orissue 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 hedging instrumentsand hedged items, as well as its risk-management objective and strategy forundertaking various hedge transactions.  This process includes linking allderivatives that are designated as cash-flow hedges to specific firmcommitments or forecasted transactions.  The Managing General Partner alsoformally assesses, both at the hedge's inception and on an ongoing basis,whether the derivatives that are used in hedging transactions are highlyeffective in offsetting changes in cash flows of hedged items.  When it isdetermined that a derivative is not highly effective as a hedge or that it hasceased to be a highly effective hedge, the Partnership discontinues hedgeaccounting prospectively.  No hedging activities were discontinued during 2004or 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, until earnings are affected by the variability in cash flows of thedesignated hedged item. Changes in the fair value of non-hedging derivativesare reported in current-period earnings. The Partnership discontinues hedgeaccounting prospectively when it is determined that the derivative is no longereffective in offsetting changes in the cash flows of the hedged item, thederivative expires or is sold, terminated, or exercised.  Additionally, if thederivative is dedesignated as a hedging instrument, because it is probable thata forecasted transaction will not occur, a hedged firm commitment no longermeets the definition of a firm commitment, or the Partnership determines thatdesignation of the derivative as a hedging instrument is no longer 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 and market risk.  Credit risk is the failure of thecounterparty to perform under the terms of the derivative contract. When thefair value of a derivative contract is positive, the counterparty owes thePartnership, which creates credit/repayment risk. The Managing General Partnerminimizes the credit/repayment risk in derivative instruments by entering intotransactions with high-quality counterparties.

F-9

PDC 2001-C LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Notes to Financial Statements

Use of Estimates

The Partnership has made a number ofestimates and assumptions relating to the reporting of assets and liabilities andrevenues and expenses and the disclosure of contingent assets and liabilitiesto prepare these financial statements in conformity with generally acceptedaccounting principles.  Actual results could differ from those estimates. Estimates which are particularly significant to the financial statementsinclude estimates of oil and gas reserves and future cash flows from oil andgas properties which are used in assessing the 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 $7,169 and a related liability of $7,998(using a 6% discount rate) and a cumulative effect of change in accountingprinciple on prior years of $829.

 (2)  Organization

The Partnership wasorganized as a limited partnership on November 9, 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 of partnership unitssubscribed to and fully paid for 21.5 units of limited partner interests and509.8617 units of additional general partner interests at $20,000 per unit(Investor Partners).  Petroleum Development Corporation has been designated theManaging General Partner of the Partnership. Although costs, revenues and cashdistributions allocable to the limited and additional general partners areshared pro rata based upon the amount of their subscriptions, including theManaging General Partner to the extent of its capital contributions, there aresignificant differences in the federal income tax effects and liabilityassociated with these different types of units in the Partnership.

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.

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.

                                                                                                                                                                (Continued)

F-10

PDC 2001-C LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Notes to Financial Statements

(3)  Transactionswith Managing General 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, 2003 and 2002.

  Year Ended

December 31, 2004

  Year Ended

December 31, 2003

  Year Ended

December 31, 2002

Drilling and completion costs

$           -    

    -    

   199,371

Lifting costs

456,281 

527,952 

335,536

Tax return preparation

5,473 

6,927 

4,175 

Direct administrative cost

866 

3,606 

2,840 

(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 Operating Capital, in thecosts and revenues 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%

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, due diligenceexpenses, and wholesaling fees of the Partnership were paid by the ManagingGeneral Partner and not from Partnership funds.  In addition, organization andoffering costs in excess of 10-1/2% of Subscriptions, if any, were paid by theManaging General Partner, without recourse to the Partnership.

F-11

PDC 2001-C LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Notes to Financial Statements

(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.

(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, will be utilized to pay for intangibledrilling costs. In the event that the Intangible Drilling Costs exceed thefunds of the Investor Partners available for payment of Intangible DrillingCosts (herein "excess IDC"), a portion of the Capital Contribution ofthe Managing General Partner may be used to pay such excess IDC.  If the costof Leases and tangible well equipment were to exceed the Managing GeneralPartner's Capital Contribution of 21-3/4% of the aggregate Capital Contributionof the Investor Partners, then the Managing General Partner will increase itsCapital Contribution to fund such additional capital requirements and theManaging General Partner's allocation of profits, losses, and cashdistributions will be increased to equal the percentage arrived at by dividingthe Capital Contribution made by the Managing General Partner by the CapitalAvailable for Investment; the allocation of the Investor Partners will bedecreased 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 and 2003 there were no units purchased byPDC.

(5)  Derivative Financial Instruments

TheManaging General Partner utilizes commodity-based derivative instruments ashedges to manage a portion of its exposure to price risk from its oil andnatural gas sales.  These instruments consist of CIG-based contracts traded byJP Morgan for Colorado production.  These hedging arrangements have the effectof locking in for specified periods (at predetermined prices or ranges ofprices) the prices the Partnership will receive for the volume to which thehedge relates.  As a result, while these hedging arrangements are structured toreduce the Partnership's exposure to changes in price associated with thehedged commodity, they also limit the benefit the Partnership might otherwisehave received from price changes associated with the hedged commodity.  ThePartnership's policy prohibits the use of natural gas future and optioncontracts for speculative purposes.

    F-12

PDC 2001-C LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Notes to Financial Statements

Thefollowing tables summarize the open futures and options contracts for thePartnership as of December 31, 2004 and 2003.

Commodity

Type

Quantity

Gas-Mmbtu

Oil-Barrels

Weighted

Average   Price

Total

Contract

Amount

Fair

Market

Value

Total Contracts as of December 31, 2004

Natural Gas

Floors

26,828

4.36

-

7,657 

Natural Gas

Ceilings

13,414

5.56

-

(6,956)

Oil

Floors

8,178

32.30

264,155

6,967 

Oil

Ceilings

4,089

40.00

163,564

(22,118)

Contracts maturing in 12 months following December 31, 2004

Natural Gas

Floors

26,828

4.36

-

7,657 

Natural Gas

Ceilings

13,414

5.56

-

(6,956)

Oil

Floors

8,178

32.30

264,155

6,967 

Oil

Ceilings

4,089

40.00

163,564

(22,118)

Prior Year Total Contracts as of December 31, 2003

Natural Gas

Floors

16,754

3.28

-

-

Natural Gas

Ceilings

16,754

4.84

-

(255)

The maximum term over which the Partnership is hedgingexposure to the variability of cash flows for commodity price risk is 12months.

(6)  Costs Relating to Oil and GasActivities

The Partnership is engaged solely in oiland gas activities, all of which are located in the continental United States.  Information regarding aggregate capitalized costs and results of operationsfor these activities is located in the basic financial statements.  Costscapitalized for these activities are as follows:

 

 

 

2004

2003   

2002   

 
Lease acquisitions  at cost

$      416,050

 416,050 

   416,050 

 
Intangible  development costs

9,245,693

9,245,693 

9,245,693 

 
Well equipment

2,094,744

 2,094,744 

 2,094,744 

 
Capitalized asset  retirement costs

         7,546

       7,546 

         -    

 
$11,764,033

11,764,033 

11,756,487 

 
The following costswere incurred for the Partnership's oil and gas activities:

Year Ended 

December 31, 2004

Year Ended 

December 31, 2003

Year Ended 

December 31, 2002

 
 
Costs  incurred:

 
  Property  acquisition costs

$     -    

     -    

     -    

 
  Development  costs

     -    

     -    

  199,371 

$     -    

     -    

  199,371 

 
F-13

PDC 2001-C LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Notes to Financial Statements

(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 $1,003,983 and $1,269,891 respectively.

(8)  Supplemental Reserve Information(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.  Thesereserves have been prepared in compliance with the Securities and ExchangeCommission rules based on year-end prices. A copy of the reserve report hasbeen made available to all partners. All of the partnership's reserves areproved developed.  An analysis of the change in estimated quantities of proveddeveloped oil and gas reserves is shown below:

Net  Proved Oil and Gas Reserves (Unaudited)

 
 
Oil (BBL)

 
2004

2003

2002

 
Proved developed reserves:

Beginning of year

329,000

359,000 

241,000 

 
Revisions of previous estimates

(126,000)

(8,000)

152,000 

 
New Discoveries and extensions

 
     Rocky Mountain Region

-

-    

-    

 
Production

(16,000)

(22,000)

(34,000)

 
End of year

187,000

329,000 

359,000 

 
Gas (MCF)

 
2004

2003

2002

 
Proved developed reserves:

Beginning of year

4,789,000

4,515,000 

4,175,000 

 
Revisions of previous estimates

(2,083,000)

670,000 

783,000 

 
New Discoveries and extensions

 
     Rocky Mountain Region

-

-    

-    

 
Production

(144,000)

(396,000)

(443,000)

 
End of year

2,562,000

4,789,000 

4,515,000 

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

                and GasReserves (Unaudited)

Summarized in the followingtable is information for the Partnership with respect to the standardizedmeasure of discounted future net cash flows relating to proved oil and gasreserves.  Future cash inflows are computed by applying year-end prices of oiland gas relating to the Partnership proved reserves to the year-end quantitiesof those reserves.  Future production, development, site restoration andabandonment costs are derived based on current costs assuming continuation ofexisting economic conditions.

F-14

PDC 2001-C LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Notes to Financial Statements

As  of December 31,

2004

 

2003

2002

Future estimated revenues

$24,711,000

   33,505,000 

25,241,000 

Future estimated production costs

(6,135,000)

(7,940,000)

(5,914,000)

Future estimated development costs

(1,351,000)

(2,321,000)

(2,321,000)

    Future net cash flows

17,225,000

23,244,000 

17,006,000 

10% annual discount for estimated timing of cash flows

(8,630,000)

(11,980,000)

(8,317,000)

Standardized measure of discounted future

estimated net cash flows

$8,595,000

11,264,000 

8,689,000 

The following tablesummarizes the principal sources of change in the standardized measure ofdiscounted future estimated net cash flows:

         

                                                                                                                                                                                                                                            YearsEnded December 31, 

2004

2003

 

2002

Sales of oil and gas production, net of production costs

$(884,000)

(1,577,000)

(1,406,000)

Net changes in prices and production costs

4,587,000

6,584,000 

6,035,000 

Extensions, discoveries, and improved recovery,

     less related cost

-

-    

-    

Revisions of previous quantity estimates

(9,722,000)

1,231,000 

3,096,000 

Accretion of discount

3,350,000

(3,663,000)

 

(3,870,000)

$(2,669,000)

2,575,000 

3,855,000 

It is necessary to emphasizethat the data presented should not be viewed as representing the expected cashflows from, or current value of, existing proved reserves since thecomputations are based on a large number of estimates and arbitraryassumptions.  Reserve quantities cannot be measured with precision and theirestimation requires many judgmental determinations and frequent revisions.  Therequired projection of production and related expenditures over time requiresfurther estimates with respect to pipeline availability, rates of demand andgovernmental control.  Actual future prices and costs are likely to besubstantially different from the current prices and costs utilized in the computationof reported amounts.  Any analysis or evaluation of the reported amounts shouldgive specific recognition to the computational methods utilized and thelimitations inherent therein.

F-15 |
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