CONFORMED COPY

SECURITIES ANDEXCHANGE COMMISSION

Washington, D.C.  20549

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

   THE SECURITIES EXCHANGE ACT OF 1934

   For the fiscal year ended December 31, 2004

Commission File Number  333-41977-12

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

PDC 2000-D LIMITEDPARTNERSHIP

(Exact name ofregistrant as specified in its charter)

| West Virginia

(State or other  jurisdiction of

incorporation or  organization) | 55-0774071

(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 2000-D LimitedPartnership ("the Partnership") is a limited partnership formed on December 27, 2000 pursuant to the West Virginia Uniform Limited Partnership Act. Petroleum Development Corporation ("PDC") serves as Managing GeneralPartner of the Partnership.

      Since thecommencement of operations on December 27, 2000, the Partnership has beenengaged in onshore, domestic gas exploration exclusively in the Rocky MountainRegion.  A total of 9 limited partners contributed initial capital of $175,000and a total of 1,081 additional general partners contributed initial capital of$24,825,000 and PDC (Managing General Partner) contributed $5,437,500 incapital as a participant in accordance with contribution provisions of theLimited Partnership Agreement (the Agreement). During 2001 in accordance withthe Partnership Agreement, all general partners were converted to limitedpartners.

      Under the terms ofthe Agreement, the allocation of revenues is as follows:

|                                              | Allocation

of Revenues |
|----------------------------------------------|-------------------------|
| Additional General and Limited Partners | 80%                     |
| Managing General Partner                     | 20%                     |

      Operating and directcosts are allocated and charged to the additional general and limited partnersand the 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 hasno employees, however, PDC has approximately 120 employees which include astaff of geologists, petroleum engineers, landmen and accounting personnel whoadminister all of the Partnership's operations.

Plan of Operations

      The Partnershipparticipated in the drilling of forty three (33.46 Net) wells and will continueto operate and produce them. The Partnership does not have unexpended initialcapital and no 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 thePartnership wells to and the capacity of natural gas pipelines, the availabilityand price of 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 natural gas is sold undercontracts based on market sensitive indices that vary from month to month. Nofixed contracts are in place. The Partnership sold oil and natural gas toseveral entities of which three customers accounted for 39.7%, 27.4% and 23.9%of the Partnership's total oil and natural gas sales for the year endedDecember 31, 2004 and 39.0%, 25.7% and 18.2% for 2003 and 34.7%, 21.4% and20.9% for the year ended December 31, 2002, 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 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 a 24 month period. The Managing GeneralPartner does not hold or issue derivatives for trading or speculative purposesand permits utilization of hedges only if there is an underlying physicalposition.  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 Partnershipcompetes in marketing its gas and oil with numerous companies and individuals,many of which have financial resources, staffs and facilities substantiallygreater than 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 of productionfrom oil and gas wells.  The Partnership believes it has complied in allmaterial respects with applicable state regulations. The Partnership estimatesit has spent approximately $8,566 and $10,400 in 2004 and 2003, respectively tocomply with federal and state regulations.

Federal Regulations

      Regulation ofLiquid Hydrocarbons.  Liquid hydrocarbons (including crude oil and naturalgas liquids) were subject to federal price and allocation controls untilJanuary 1981 when controls were effectively eliminated by executive order ofthe President.  As a result, to the extent the Partnership sells oil producedfrom its 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 andOil Regulation.  Sale of natural gas and oil  by the Partnership is subjectto regulation of production, transportation and pricing by governmentalregulatory agencies.  Generally, the regulatory agency in the state where aproducing well is located regulates production activities and, in addition, thetransportation of gas and oil sold intrastate.  The Federal Energy RegulatoryCommission (FERC) regulates the operation and cost of interstate pipelineoperators who transport gas and oil.  Currently the price of gas and oil to besold by the Partnership is not regulated by any state or federal agency.

   Proposed Regulation.  Numerousproposals concerning energy are being considered by the United States Congress,various state legislatures and regulatory agencies.  The possible outcome andeffect of these proposals cannot be accurately predicted.

3

Environmental and SafetyRegulation.  The Partnership believes that it complies, in all material respects,with all legislation and regulations affecting its operations in the drillingand production 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.

ITEM 2.  PROPERTIES.

Drilling Activity

     The following table setsforth the results of the Partnership's drilling activity from December 27, 2000 (date of inception) to December 31 2004. All of the Partnership's wellsdrilled and producing are located in the Rocky Mountain Region.

|  

                        Development  Wells                      |
|----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
|          Gross                                                                                                                                                                                                 |            Net              |
| Productive                                                                                                                                                                                                                                                                                               | Dry | Total | Productive | Dry | Total |
| 41                                                                                                                                                                                                                                                                                                       | 2 | 43 | 32.04 | 1.42 | 33.46 |

    The partnership has notparticipated in any exploratory wells.   No additional drilling activityis planned.

 

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.

Summaryof Productive Wells

 

     Thetable below shows the number of the Partnership's gross and net wells by stateas of December 31, 2004.

| Location     | Gross   | Net               |
|--------------|---------|-------------------|
| Colorado     | 38      | 30.39             |
| North Dakota |  3 |    1.65 |
| Total        | 41      | 32.04             |

     A"productive well" is a well producing, or capable of producing, oiland gas in commercial quantities. For purposes of the above table, a"gross well" is one in which the Partnership has a working interestand a "net well" is a gross well multiplied by the Partnership'sworking interest to which it is entitled under its drilling agreement.

 

Title to Properties

      The Partnership'sinterests in producing acreage are in the form of assigned direct interests inleases.  Such properties are subject to customary royalty interests generallycontracted for in connection with the acquisition of properties and could besubject to liens incident to operating agreements, liens for current taxes andother burdens. 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 oil and gas industry,little or no investigation of title is made at the time of acquisition ofundeveloped properties (other than a preliminary review of local mineralrecords).  Investigations are generally made, including in most cases receivinga title opinion of legal counsel, before commencement of drilling operations. Athorough examination of title has been made with respect to all of thePartnership's producing properties and the Partnership believes that it hasgenerally satisfactory title to such properties.

4

ITEM 3.  LEGAL PROCEEDINGS.

      The Managing GeneralPartner as driller/operator is not party to any legal action that it believeswould have 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.

      During 2003 theManaging General Partner proposed an amendment to Article 8.02 of thepartnership agreement to delete the word "independent" from"independent petroleum engineers". The proposed amendment wassubmitted to a vote and was passed.

PART II

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

      At December 31, 2000,PDC 2000-D Limited Partnership had one Managing General Partner, 9 LimitedPartners who fully paid for 8.75 units at $20,000 per unit of limitedpartnership interests and a total of 1,081 Additional General Partners whofully paid for 1,241.25 units at $20,000 per unit of additional generalpartnership interests.  During 2001 in accordance with the PartnershipAgreement, all Additional General Partners were converted to Limited Partners.At December 31, 2004, the Partnership had one Managing General Partner and1,090 limited partners who paid for 1,250 units at $20,000 per unit. Noestablished public trading market exists for the interests.

      Limited andadditional general partnership interests are transferable, however no assigneeof an interest 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 selectedfinancial data presented below has been derived from audited financialstatements of the Partnership appearing elsewhere herein.

|                                                                   |                  | Years Ended December 31, |
|-------------------------------------------------------------------|------------------|--------------------------|
|                                                                   |                  | 2004                     | 2003 | 2002 |
| Oil and Gas Sales                                                 | $3,502,192  | $3,577,192          | $3,729,913  |
| Costs and Expenses                                                | 1,688,528   | 1,909,980           | 2,583,649  |
| Cumulative effect of change in accounting 

  principle | -                |    (5,321)     | -      |
| Net Income                                                        | 1,814,957   | 1,663,541           | 1,150,118  |
| Allocation of Net Income:                                         |                  |                          |  |
|   Managing General Partner                              | 362,991     | 322,708             | 230,024  |
|   Limited and Additional General Partners               | 1,451,965   | 1,330,833           | 920,094 |
|   Per Limited and Additional General Partner  Unit      | 1,162       | 1,065               | 736 |
| Total Assets                                                      | 9,622,199   | 10,338,361          | 11,538,764 |
| Cash Distributions:                                               |                  |                          |  |
|   Managing General Partner                              | 515,072     | 568,901             | 579,046  |
|   Limited and Additional General Partners               | 2,060,288   | 2,275,606           | 2,316,182  |
|                                                                   |                  |                          |  |  |  |

 

ITEM 7.  MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION

         ANDRESULTS OF OPERATIONS.

Liquidity and Capital Resources

      The Partnership wasfunded with initial Limited and Additional General Partner contributions of$25,000,000 and the Managing General Partner's contribution of $5,437,500 inaccordance with the Agreement.  After payment 

5

of syndication costs of $2,625,000 and a one-timemanagement fee to the Managing General Partner of $625,000 the partnership hadavailable cash of $27,187,500 for Partnership activities.

   

  The Partnership had began exploration anddevelopment activities subsequent to the funding of the Partnership andcompleted these activities by December 31, 2001. Forty-three wells have beendrilled, 41 of which have been completed as producers. No additional wells willbe drilled.

      The Partnership hadworking capital at December 31, 2004 of $559,764.

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

Results of Operations

2004 ResultsCompared to 2003

** **

     Oil and gas sales for theyear ended December 31, 2004 were $3,502,192 compared to $3,577,192 for theyear ended December 31, 2003. For the year ended December 31, 2004, the Partnership sold 506,685 Mcf of gas and 25,765 barrels of oil at average prices of $5.03and $37.03, respectively. This compared with 654,879 Mcf of gas and 36,070barrels of oil at average sales prices of $3.84 and $29.44, respectively for theyear ended December 31, 2003. Lifting cost per Mcf in 2004 amounted to $1.18 ascompared to $1.04 for 2003. This increase is partially attributed to theincrease in severance and property taxes. The fixed costs of operations andwell maintenance are allocated to lower production volumes, thereforeincreasing the lifting cost per Mcfe. Depreciation, depletion and amortizationdecreased from $977,871 for the year ended December 31, 2003 to $886,887 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 $2,575,361 in 2004.

2003 ResultsCompared to 2002

     Oil and gas sales for theyear ended December 31, 2003 were $3,577,192 compared to $3,729,913 for theyear ended December 31, 2002. For the year ended December 31, 2003, the Partnership sold 654,879 Mcf of gas and 36,070 barrels of oil at average prices of $3.84and $29.44, respectively. This compared with 1,092,380 Mcf of gas and 57,767barrels of oil at average sales prices of $2.10 and $24.77, respectively for theyear ended December 31, 2002. Lifting cost per Mcf in 2003 amounted to $1.04 ascompared to $0.69 for 2002.  This increase is partially attributed to theincrease in severance and property taxes.  The fixed costs of operations andwell maintenance are allocated to lower production volumes, thereforeincreasing the lifting cost per Mcfe. Depreciation, depletion and amortizationdecreased from $1,549,068 for the year ended December 31, 2002 to $977,871 for the year ended December 31, 2003 as a result of lower volumes of natural gasand oil sold. Cash distributions to the partners amounted to $2,844,507 in 2003.

   The Partnership's revenues from oiland natural gas sales will be affected by changes in prices. As a result ofchanges in federal regulations, gas prices are highly dependent on the balancebetween supply and demand. The Partnership's gas sales prices are subject toincrease 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 thosepolicies, our management uses its judgment to determine the appropriateassumptions to be used in the determination of certain estimates. Thoseestimates are based on our historical experience, our observance of trends inthe industry, and information available from other outside sources, asappropriate. For a more detailed discussion on the application of these andother accounting policies, see "Note 1 - Summary of significant accountpolicies" in our financial statements and related notes. The Partnership'scritical accounting policies and estimates are as follows:

6

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 gas issold 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 Managing General Partnerbelieves that the pricing provisions of its natural gas contracts are customaryin the industry.

The Managing General Partner currentlyuses the "Net-Back" method of accounting for transportation arrangements of naturalgas sales.  The Managing General Partner sells gas at the wellhead and collectsa price and recognizes revenues based on the wellhead sales price sincetransportation costs downstream of the wellhead are incurred by the ManagingGeneral 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.

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. 

     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, if available.Otherwise, the Partnership seeks indicative price information from externalsources, 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.

7

Oil and Gas Properties 

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

      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 flow, 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 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 propertiesand leases are written-off to expense when it is determined that they willexpire to be abandoned.

Costs of provedproperties, including leasehold acquisitions, 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 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

     June 2001, the FinancialAccounting Standard Board issued FASB No. 143, "Accounting for AssetRetirement Obligations" that requires entities to record the fair value ofa liability for an asset retirement obligation in the period in which it isincurred and a corresponding increase in the carrying amount of the relatedlong-lived asset. This statement is effective for fiscal years beginning after June 15, 2002. The Partnership adopted FASB No. 143 on January 1, 2003 and recorded a net asset of $10,264 and a related liability of $15,585 (using a 6% discountrate) and a cumulative effect on change in accounting principle on prior yearsof $5,321.

Item 7A.  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 and marketingactivities.  These instruments consist of CIG-based contracts traded by JPMorgan for Colorado natural gas production and NYMEX traded oil futures andoption contacts for Colorado oil production.  These hedging arrangements havethe effect of locking in for specified periods (at predetermined prices orranges of prices) the prices the Managing General Partner will receive for thevolume to which the hedge relates.  As a result, while these hedgingarrangements are structured to reduce Partnership's exposure to changes in price associated with the hedged commodity, theyalso limit the benefit the Partnership might otherwise have received from pricechanges associated with the hedged commodity.  The Partnership's policyprohibits the use of natural gas future and option contracts for speculativepurposes.

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

8

| 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   | 152,765     | 3.91     |                          -                                           | 28,887               |
| Natural  Gas                                                | Ceilings | 76,382      | 5.11     |                          -        | (58,530)                  |
| Oil                                                         | Floors   | 11,581      | 32.30    | 374,064                                                                                                                                                                                      | 9,866                |
| Oil                                                         | Ceilings | 5,790       | 40.00    | 231,619                                                                                                                                                                                      | (31,320)                  |
|                                                             |          |             |          |                                                                                                                                                                                              |                           |
| Contracts maturing in 12 months following December 31, 2004 |
| Natural  Gas                                                | Floors   | 152,765     | 3.91     |                          -                                           | 28,887               |
| Natural  Gas                                                | Ceilings | 76,382      | 5.11     |                          -        | (58,530)                  |
| Oil                                                         | Floors   | 11,581      | 32.30    | 374,064                                                                                                                                                                                      | 9,866                |
| Oil                                                         | Ceilings | 5,790       | 40.00    | 231,619                                                                                                                                                                                      | (31,320)                  |
| Prior Year Total Contracts as of December 31, 2003          |
| Natural  Gas                                                | Floors   | 147,153     | 3.28     |                          -                                           | -     |
| Natural  Gas                                                | Ceilings | 147,153     | 4.84     |                          -        | (2,242)                   |

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

The average NYMEXclosing price for oil for the years 2004,  2003 and 2002 was $41.44 per bbl, $30.98per bbl and $26.98 per bbl. The average CIG closing price for natural gas forthe years 2004, 2003 and 2002 was $5.17 per Mmbtu, $4.04 per Mmbtu and $1.97per Mmbtu.  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.

Disclosure of Limitations

     As the information above incorporatesonly those exposures that exist at December 31, 2004, it does not consider those exposures or positions which could arise after that date. As a result, thePartnership's ultimate realized gain or loss with respect to commodity pricefluctuations will depend on the exposures that arise during the period, thePartnership's hedging strategies at the time and commodity prices at the time.

PART III

ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA:

      The response to thisItem is set forth herein in a separate section of this Report, beginning onPage F-1.

ITEM 9.  CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ONACCOUNTING 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,

9

processed, summarized,and reported, within the time periods specified in the Commission's rules andforms, and is accumulated and communicated to management, including theManaging General Partner's Chief Executive Officer and Chief Financial Officer,as appropriate to allow for timely disclosure. There have been no significantchanges in our internal controls or in other factors that could significantlyaffect these controls in the fourth quarter and subsequent to the date of theirevaluation.

 

ITEM 9B.  OTHER INFORMATION

     NONE

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THEREGISTRANT.

     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 presents compensationor reimbursements by the Partnership to PDC or other related parties for theyears ended December 31, 2004, 2003 and 2002.

|                               | 2004                                                                  | 2003                                                    | 2002                |
|-------------------------------|-----------------------------------------------------------------------|---------------------------------------------------------|---------------------|
| Drilling and completion costs | $        -     |     -      |  208,055  |
| Tax return preparation        | 11,890                                                                | 11,890                                             | 17,360         |
| Direct administrative cost    | 3,829                                                                 | 5,211                                              | 5,031          |
| Lifting costs                 | 778,491                                                               | 907,821                                            | 999,428        |

ITEM 14.  PRINCIPAL ACCOUNTANT FEES ANDSERVICES

For the years endedDecember 31, 2004 and 2003, the Partnership paid KPMG LLP $6,440 and $6,252,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. 

10

 

 

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES.

                        (1)   Financial Statements

                                See Index to FinancialStatements 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. 333-41977, and Rule 424 final prospectus, dated June 8, 2000, of PDC 2000 Drilling Program, filed with the SEC on June 12, 2000).

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

PDC 2000-D Limited Partnership

By its Managing General Partner

Petroleum Development Corporation

By /s/ Steven R. Williams      

   Steven R. Williams, Chairman

April 19, 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 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 2000-D 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's ReportThereon)

F-1

PDC 2000-D 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 2000-D Limited Partnership:

Wehave audited the accompanying balance sheets of PDC 2000-D 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 2000-D Limited Partnership asof December 31, 2004 and 2003, and the results of its operations and its cashflows for each of the years in three-year period ended December 31, 2004, inconformity with U.S. generally accepted accounting principles.

Asdiscussed in note 1 to the financial statements, the Partnership adopted theprovisions of Statement of Financial Accounting Standards No. 143, "Accountingfor Asset Retirement Obligations", in 2003.

                                                                                                                                                                                        

                                                   KPMG LLP             

                                                                                                                                                                    KPMGLLP

Pittsburgh, Pennsylvania 

April 19, 2005

F-3

PDC 2000-D LIMITEDPARTNERSHIP

(A West VirginiaLimited Partnership)

Balance Sheets

December 31, 2004 and 2003

     Assets

               2004

            2003

Cash

$2,622

   1,484 

Accounts  receivable - oil and gas revenues

675,916

   506,329 

          Total  current assets

678,538

507,813 

Oil and gas  properties, successful

      efforts  method (notes 3 and 6):

       Oil  and gas properties

14,601,009

14,601,009 

       Less  accumulated depreciation, 

        depletion, and  amortization

 

5,657,348

   4,770,461 

  8,943,661

 9,830,548 

$9,622,199

10,338,361 

     Liabilities  and Partners' Equity

Current  liabilities:

     Accrued  expenses

$  118,773

    26,667 

          Total  current liabilities

118,773

26,667 

     Asset  retirement obligation

17,511

    16,520 

Partners' equity

9,485,915

10,295,174 

$9,622,199

10,338,361 

See accompanying notes to financial statements.

F-4

PDC 2000-D LIMITEDPARTNERSHIP

(A West VirginiaLimited Partnership)

Statements ofOperations

Years Ended December 31, 2004, 2003 and 2002 

                  2004

              2003

              2002    

Revenues:

     Sales of oil and gas

$3,502,192

3,577,192

3,729,913 

     Interest income

       1,293

       1,650

        3,854 

3,503,485

3,578,842

3,733,767 

Expenses (note 3):

     Lifting cost

778,491

907,821

999,428 

     Independent audit fee

6,440

6,252

6,070 

     Tax return preparation

11,890

11,890

17,360 

     Direct administrative  cost

4,820

6,146

5,031 

     Independent engineering cost

-

-

6,692 

     Depreciation,  depletion and amortization

   886,887

   977,871

1,549,068 

1,688,528

1,909,980

2,583,649 

          Income  before cumulative effect of 

            change  in accounting principle

1,814,957

1,668,862

  1,150,118

Cumulative  effect of change in accounting principle

 

            -    

 

       (5,321)

 

             -    

 

          Net  income 

$1,814,957

1,663,541

1,150,118 

          Net  income per limited and additional 

            general  partner unit before cumulative 

            effect  of change in accounting principle

$1,162

1,068

         736 

          Cumulative  effect of change in accounting 

            principle

        -    

          (3)

        -    

 

 

 

          Net  income per limited and additional 

            general  partner unit 

$1,162

     1,065

       736 

See accompanying notes to financial statements.

F-5

PDC 2000-D 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

$10,412,349 

2,603,088 

     -    

 13,015,437 

Capital  contribution

208,055 

208,055 

Distributions to  partners

(2,316,182)

(579,046)

(2,895,228)

Comprehensive  income:

 

 

 

 Net income

920,094 

230,024 

 

1,150,118 

 Change in  fair value of outstanding 

  hedging  positions

 

  24,824 

 

Reclassification  adjustment for settled 

  contracts  included in net income (loss)

 

       -    

 

Other  comprehensive income

 

24,824 

    24,824 

Comprehensive  income

                  

                 

                

  1,174,942 

 

 

 

Balance December 31, 2002

 9,016,261 

2,462,121 

    24,824 

 11,503,206 

 

 

 

Distributions to  partners

(2,275,606)

(568,901)

 

(2,844,507)

 

 

 

Comprehensive  income

 

 

 

 Net income

1,330,833 

332,708 

 

1,663,541 

Changes in fair  value of outstanding 

  hedging  positions

 

  (16,546)

 

Reclassification  adjustment for settled 

  contracts  included in net income (loss)

 

    (10,520)

 

Other  comprehensive loss

 

(27,066)

    (27,066)

Comprehensive  income

      -    

      -    

      -    

  1,636,475 

 

 

 

Balance December 31, 2003

8,071,488 

2,225,928 

    (2,242)

10,295,174  

 

 

 

Distributions to  partners

(2,060,288)

(515,072)

-

(2,575,361)

 

 

 

Comprehensive  income

 

 

 

Net income

1,451,965

362,991

1,814,957 

Changes in fair  value of outstanding

 hedging positions

 

(111,012)

 

Reclassification  adjustment for settled 

  contracts  included in net income (loss)

 

     62,157 

 

Other  comprehensive loss

 

(48,855)

    (48,855)

Comprehensive  income

      -    

      -    

         -    

  1,766,102 

 

 

 

Balance December 31, 2004

$7,463,165

2,073,847

(51,097)

9,485,915 

See accompanyingnotes to financial statements.

F-6

PDC 2000-D 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 

$1,814,957 

1,663,541 

1,150,118 

    Adjustments  to reconcile net income

       to net cash provided from  operating activities:

    Depreciation,  depletion and 

      amortization

886,887 

977,871 

1,549,068 

    Cumulative  effect of change in accounting principle

-  

5,321 

-    

    Accretion  of asset retirement obligation

991 

935 

-    

    Changes  in operating assets and liabilities:

    (Increase)  decrease in accounts 

      receivable  - oil and gas revenues

(130,833)

205,727 

182,407 

    Increase  (decrease) in accrued expenses

4,497 

   (11,133)

    16,304 

 

 

 

    Net cash  provided from operating activities

2,576,499 

2,842,262 

2,897,897 

Cash flows used by investing  activities:

    Expenditures  for oil and gas properties

          -    

     -    

 (208,055)

    Net cash used  by investing activities

          -    

     -    

 (208,055)

Cash flows used by financing  activities:

    Managing  General Partner contribution

-

-    

208,055 

    Distributions  to partners

(2,575,361)

(2,844,507)

(2,895,228)

    Net cash used  by financing activities

(2,575,361)

(2,844,507)

(2,687,173)

 

 

 

Net increase (decrease) in cash

1,138 

(2,245)

2,669 

Cash at beginning of period

1,484 

    3,729 

    1,060 

Cash at end of period

$2,622 

    1,484 

    3,729 

See accompanyingnotes to financial statements.

F-7

PDC 2000-D LIMITEDPARTNERSHIP

(A West VirginiaLimited Partnership)

Notes to FinancialStatements

December 31, 2004, 2003 and 2002

(1)  Summary of Significant AccountingPolicies

PartnershipFinancial Statement Presentation Basis

The financialstatements include only those assets, liabilities and results of operations ofthe partners which relate to the business of PDC 2000-D 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 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 has notdiscovered economically producible reserves, then its costs are expensed as dryhole 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 flows, 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 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 Managing General Partnerbelieves that the pricing provisions of its natural gas contracts are customaryin 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 and collectsa price and recognizes revenues based on the wellhead sales price sincetransportation costs downstream of the wellhead are incurred by the ManagingGeneral 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

F-8

 

 PDC 2000-D LIMITEDPARTNERSHIP

(A West Virginia Limited Partnership)

Notes to Financial Statements

 

not refine any of its oil production. The Partnership'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. 

The Partnership soldoil and natural gas to several entities of which three customers accounted for39.7%, 27.4% and 23.9% of the Partnership's total oil and natural gas sales forthe year ended December 31, 2004 and 39.0%, 25.7% and 18.2% for 2003 and 34.7%,21.4% and 20.9% for the year ended December 31, 2002, respectively.

 

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 Managing GeneralPartner does not hold or issue derivatives for trading or speculative purposes.

All derivatives arerecognized on the Partnership's 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, thePartnership discontinues hedge accounting prospectively. No hedging activitieswere 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-hedgingderivatives are reported in current-period earnings. The Partnershipdiscontinues 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.Additionally, if the derivative is dedesignated as a hedging instrument,because it is probable that a forecasted transaction will not occur, or thePartnership determines that designation of the derivative as a hedginginstrument is no longer appropriate, hedge accounting will be discontinued.

F-9

PDC 2000-D LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

                                                 Notes to Financial Statements

By using derivative financial instrumentsto hedge exposures to changes in commodity prices, the Managing General Partnerexposes the Partnership to credit 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 the Partnership,which creates credit risk. The Managing General Partner minimizes the creditrisk in derivative 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 general accepted in the United States of America.  Actualresults could differ from those estimates. Estimates which are particularlysignificant to the financial statements include estimates of oil and gasreserves and future cash flows from oil and gas properties which are used inassessing impairment of long-lived assets.

 

New AccountingStandards

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 $10,264 and a related liability of $15,585(using a 6% discount rate) and a cumulative effect on change in accountingprinciple on prior years of $5,321.

(2)  Organization

ThePartnership was organized as a limited partnership on December 27, 2000 in accordance with the laws of the State of West Virginia for the purpose ofengaging in the drilling, completion and operation of oil and gas developmentand exploratory wells in the Rocky Mountain Region.

Purchasersof partnership units subscribed to and fully paid for 8.75 units of limitedpartner interests and 1,241.25 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 theirsubscriptions, including the Managing General Partner to the extent of itscapital contributions, there are significant differences in the federal incometax effects and liability associated with these different types of units in thePartnership.

Uponcompletion of the drilling phase of the Partnership's wells, all additionalgeneral partners units are converted into units of limited partner interestsand thereafter become limited partners of the Partnership. Limited partners donot have any rights to convert their units into units of additional generalpartner interests 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.

F-10

                                                       PDC 2000-D LIMITEDPARTNERSHIP

(A West VirginiaLimited Partnership)

Notes to FinancialStatements

 (3)  Transactions with Managing GeneralPartner and Affiliates

Pursuantto the authorization 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 Partnership toPDC or other related parties for years ended December 31, 2004, 2003 and 2002.

2004

2003

2002

Drilling and completion costs

$        -         

        -      

208,055 

Lifting costs

778,491

907,821 

999,428 

Tax return  preparation

11,890

11,890 

17,360 

Direct administrative cost

3,829

5,211 

5,031 

(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 Cost

  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,were paid 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.

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

F-11

PDC 2000-D LIMITEDPARTNERSHIP

(A West VirginiaLimited Partnership)

Notes to FinancialStatements

(4)  TheManaging General Partner receives monthly reimbursement from the Partnershipfor their direct      costs incurred by the Managing General Partner on behalfof the Partnership.

     (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 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 cost ofLeases 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 cash distributionswill be increased to equal the percentage arrived at by dividing the CapitalContribution made by the Managing General Partner by the Capital Available forInvestment; the allocation of the Investor Partners will be decreasedaccordingly.

      (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 7.17 units of partnershipinterest for a total ownership of 8.92 units as of December 31, 2004 which represents a .71% ownership of the original Investor Partners share of limitedand additional general partnership units. Therefore, costs and revenues anddistributions for these purchased units are allocated to PDC in accordance withthe Investor Partners allocation percentages disclosed in this table.

(5)  DerivativeFinancial Instruments

The Managing General Partner utilizescommodity-based derivative instruments as hedges to manage a portion of its exposureto price risk from its oil and natural gas sales and marketing activities.  Theseinstruments consist of CIG-based contracts traded by JP Morgan for Colorado production.  These hedging arrangements have the effect of locking in forspecified periods (at predetermined prices or ranges of prices) the prices theManaging General Partner will receive for the volume to which the hedgerelates.  As a result, while these hedging arrangements are structured toreduce Partnership's exposure to changes inprice associated with the hedged commodity, they also limit the benefit thePartnership might otherwise have received from price changes associated withthe hedged commodity.  The Partnership's policy prohibits the use of naturalgas future and option contracts for speculative purposes.

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

F-12

PDC 2000-D LIMITEDPARTNERSHIP

(A West VirginiaLimited Partnership)

Notes to Financial Statements

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

152,765

3.91

                         -

28,887 

Natural  Gas

Ceilings

76,382

5.11

                         -         

(58,530)

Oil

Floors

11,581

32.30

374,064

9,866 

Oil

Ceilings

5,790

40.00

231,619

(31,320)

Contracts maturing in 12 months following December 31, 2004 

Natural  Gas

Floors

152,765

3.91

                         -

28,887 

Natural  Gas

Ceilings

76,382

5.11

                         -         

(58,530)

Oil

Floors

11,581

32.30

374,064

9,866 

Oil

Ceilings

5,790

40.00

231,619

(31,320)

Prior Year Total Contracts as of December 31, 2003

Natural  Gas

Floors

147,153

3.28

                         -

-    

Natural  Gas

Ceilings

147,153

4.84

                         -         

(2,242)

The maximum termover which the Partnership is hedging exposure to the variability of cash flowsfor commodity price risk is 24 months. 

 (6)  CostsRelating to Oil and Gas Activities

      ThePartnership is engaged solely in oil and gas activities, all of which are locatedin the continental United States. Information regarding aggregate capitalizedcosts and 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 acquisition  costs

$784,456 

    784,456 

 784,456 

Intangible  development costs

21,738,000 

21,738,000 

21,738,000 

Well equipment

4,858,099 

4,858,099 

4,858,099 

Impairment charge

(12,793,416)

 (12,793,416)

 (12,793,416)

Capitalized asset  retirement cost

        13,870 

         13,870 

           -    

$14,601,009 

 14,601,009 

 14,587,139 

     Thefollowing costs were incurred for the Partnership's oil and gas activities:

Years Ended  December 31, 

2004

2003

2002

Property acquisition 

 costs

  $             -    

  -    

  -    

Development costs

-    

-    

208,055 

Unevaluated oil and  gas properties

              -    

             -    

             -    

              -    

            -     

    208,055 

F-13

        PDC 2000-DLIMITED PARTNERSHIP

(A West VirginiaLimited Partnership)

Notes to FinancialStatements

(7)  IncomeTaxes

As aresult of the differences in the treatment of certain items for income taxpurposes as opposed to financial reporting purposes, primarily depreciation,depletion and amortization of oil and gas properties and the recognition ofintangible drilling costs as an expense or capital item, the income tax basisof oil and gas properties differs from the basis used for financial reportingpurposes. At December 31, 2004 and 2003, the income tax basis of thepartnership's oil and gas properties was $2,355,722 and $2,918,307,respectively.

    (8)  SupplementalReserve Information (unaudited)

Provedoil and gas reserves 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:

Oil  (BBL)

 
 
2004

2003

2002

 
Proved developed reserves:

 
    Beginning of year

448,000  

437,000 

   414,000  

 
    Revisions of previous estimates

   (32,000) 

47,000 

81,000  

 
    Production

(26,000) 

(36,000)

(58,000) 

 
    End of Year

339,000  

448,000 

437,000  

Gas  (MCF)

2004

2003

2002

Proved developed reserves:

    Beginning of year

8,223,000 

9,388,000  

 8,666,000 

    Revisions of previous estimates

(1,590,000)

(510,000) 

1,814,000 

    Production

(507,000)

(655,000) 

(1,092,000)

    End of Year

6,126,000 

8,223,000  

9,388,000 

(9)  StandardizedMeasure of Discounted Future Net Cash Flows and Changes Therein Relating toProved Oil and Gas Reserves (Unaudited)

Summarized in the following table is information for the Partnership withrespect to the standardized measure of discounted future net cash flowsrelating to proved oil and gas reserves. Future cash inflows are computed byapplying year-end prices of oil and gas relating to the Partnership provedreserves to the year-end quantities of those reserves.  Future production,development, site restoration, and abandonment costs are derived based oncurrent costs assuming continuation of existing economic conditions.

F-14

PC 2000-D LIMITEDPARTNERSHIP

(A West Virginia Limited Partnership)

Notes to Financial Statements

As of  December 31,

2004

2003

2002

Future estimated revenues

$55,032,000

59,419,000 

45,445,000 

Future estimated production costs

(14,772,000)

(14,590,000)

(11,574,000)

Future estimated development costs

(2,412,000)

(2,412,000)

(2,338,000)

   Future net cash flows

37,848,000

42,417,000 

31,533,000 

10% annual discount for estimated timing of cash flows

(17,929,000)

(21,649,000)

(15,864,000)

Standardized measure of discounted future

   estimated net cash flows

$19,919,000

20,768,000 

15,669,000 

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

Years  Ended December 31,

2004

2003

2002

Sales of oil and gas production, net of production  costs

($2,724,000)

($2,669,000)

(2,730,000)

Net changes in prices and production costs

5,124,000 

13,735,000 

14,381,000 

Extensions, discoveries, and improved recovery,     less related cost

  -     

  -     

  -     

Revisions of previous quantity estimates

(6,969,000)

(181,000)

3,376,000 

Accretion of discount

3,720,000 

(5,785,000)

 

(8,139,000)

$    (849,000)

$5,100,000 

 

6,888,000 

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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