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  333-41977-04

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

     period from          to          

PDC 1998-D LIMITEDPARTNERSHIP

(Exact name ofregistrant as specified in its charter)

|     West Virginia          

(State or other jurisdiction of

incorporation or organization) | 55-0757539(I.R.S.  Employer  Identification No.) |
|----------------------------------------------------------------------------------------------------------------------------------------------------------|--------------------------------------------------|

103 East Main Street, Bridgeport, West Virginia  26330                 

(Address of principal executive offices)     (zipcode)     

Registrant's telephone number, including areacode           (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) hasfiled all reports required to be filed by Section 13 or 15(d) of the SecuritiesExchange Act of 1934 during the preceding 12 months and (2) has been subject tosuch 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 check mark whether the registrant is anaccelerated filer (as definition in Rule 12b-2 of the Exchange Act). Yes   No X 

There is no trading market for the registrant'ssecurities.

PART I

ITEM 1.  BUSINESS.

General

     PDC 1998-D LimitedPartnership ("the Partnership") is a limited partnership formed on December 31, 1998 pursuant to the West Virginia Uniform Limited Partnership Act.  PetroleumDevelopment Corporation ("PDC") serves as Managing General Partner ofthe Partnership.

     Since the commencement ofoperations on December 31, 1998, the Partnership has been engaged in onshore,domestic gas exploration exclusively in the northern Appalachian and MichiganBasins.  A total of 11 limited partners contributed initial capital of$330,000; a total of 1,045 additional general partners contributed initialcapital of $20,195,261; and PDC (Managing General Partner) contributed$4,464,244 in capital as a participant in accordance with contributionprovisions of the Limited Partnership Agreement (the Agreement). During 1999 inaccordance with the Partnership Agreement, all Additional General Partners wereconverted to Limited Partners.

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

|                                         | Allocation

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

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

Employees

     The Partnership has noemployees; however, PDC has approximately 120 employees which include a staffof geologists, petroleum engineers, landmen and accounting personnel whoadminister all of the partnership's operations.

Plan of Operations

     The Partnershipparticipated in the drilling of 97 gross wells (73.8 net) and will continue tooperate and produce its productive wells.  The Partnership does not haveunexpended initial capital 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, theavailability and price of competitive fuels, fluctuations in seasonal supplyand demand, and government regulation of supply and demand created by itspricing and allocation restrictions.  Oversupplies of gas can be expected tooccur from time to time and may result in the Partnership's wells being shut-inor curtailed.  Increased imports of natural gas have occurred and are expectedto continue. The effects of such imports could adversely impact the market fordomestic natural gas. All gasis sold under contracts based on market sensitive indexes that vary from monthto month. No fixed price contracts are in place. The Partnership sold naturalgas to two customers which accounted for 99.04% and .96% of the Partnership'stotal natural gas sales for the year ended December 31, 2004, 98.86 % and 1.14%for the year ended December 31, 2003, and 98.07% and 1.93% for the year endedDecember 31, 2002.

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 Appalachian and Michigan production.  The contracts hedge committed and anticipatednatural gas sales, generally forecasted to occur within a 24 month period. TheManaging General Partner does not hold or issue derivatives for trading orspeculative purposes and permits utilization of hedges only if there is anunderlying physical position.  See "Commodity Price Risk" underItem 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 with numerous companies and individuals, many of which havefinancial resources, staffs and facilities substantially greater than those ofthe 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 Partnershipestimates it has spent approximately $0 and $3,300 in 2004 and 2003,respectively to comply with federal and state regulations.

Federal Regulations

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

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

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

3

        

Environmental and Safety Regulation.  The Partnershipbelieves that it complies, in all material respects, with all legislation andregulations affecting its operations in the drilling and production of oil andgas wells and the discharge of wastes.  To date, compliance with suchprovisions and regulations has not had a material effect upon the Partnership'sexpenditures for capital equipment, its operations or its competitiveposition.  The cost of such compliance is not anticipated to be material in thefuture.

ITEM 2.  PROPERTIES.

Drilling Activity

     The following table setsforth the results of drilling activity of the Partnership, from December 31, 1998 (date of inception) to December 31, 2004 which was conducted in theContinental United States.

|             Development  Wells                    |
|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
|    Gross Wells                                                                                                                                                  |        Net Wells           |
| Productive                                                                                                                                                                                                   | Dry | Total | Productive | Dry | Total |
| 89                                                                                                                                                                                                           | 5 | 94 | 65.81 | 4.88 | 70.69 |

     The Partnership drilledthree dry exploratory wells (2.69 net), two in Colorado and one in Michigan.  No additional drilling activity is 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.

Summary of Productive Wells

     During 2002 the Partnershiptransferred five wells in the Paxton Quarry Antrim Unit in Michigan to anunrelated third party. The Partnership received no proceeds or incurred nocosts in this transaction. The table below shows the number of thePartnership's gross and net wells by state as of December 31, 2004.  

|                    |  Natural Gas Wells |
|--------------------|-------------------------|
| Location           | Gross                   |     Net |
| Michigan           |    32         |  12.28 |
| Pennsylvania       |    42         |  40.83 |
| West Virginia      |    10         |   9.96 |
|    Total |    84         |  63.07 |

     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.

      

                                                                                        4

As is customary in the oil and gas industry, little or noinvestigation of title is made at the time of acquisition of undevelopedproperties (other than a preliminary review of local mineral records). Investigations are generally made, including in most cases receiving a titleopinion 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.

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 to the Managing General Partner's orPartnership's business, financial condition, results of operations or liquidity.

 

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

     Not Applicable.

PART II

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

     At December 31, 2003, PDC1998-D Limited Partnership had one Managing General Partner, 11 LimitedPartners who fully paid for 16.5 units at $20,000 per unit of limitedpartnership interests and a total of 1,045 Additional General Partners whofully paid for 1,009.763 units at $20,000 per unit of additional generalpartnership interests.  During 1999 in accordance with the PartnershipAgreement, all Additional General Partners were converted to Limited Partners.No established public trading market exists for the interests.

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

ITEM 6.  SELECTED FINANCIAL DATA.

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

|                                                                                           | Years Ended  December 31, |
|-------------------------------------------------------------------------------------------|---------------------------|
|                                                                                           | 2004                      | 2003 | 2002 |
| Oil and Gas Sales                                                                         | $2,692,812           | 2,469,093  | 1,749,877  |
| Costs and Expenses                                                                        | 1,191,863            | 1,328,404  | 1,391,940  |
| Cumulative effect of change in accounting principle                                       | -     | (14,001) | -     |
| Net Income (loss)                                                                         | 1,501,901            | 1,127,699  | 359,528  |
| Allocation of Net Income:                                                                 |                           |  |  |
|    Managing General Partner                                                | 300,380              | 225,539  | 71,906  |
|    Limited and Additional General  Partners                                | 1,201,521            | 902,160  | 287,622  |
|    Per Limited and Additional General  Partner Unit                        | 1,171                | 879  | 280  |
| Total Assets                                                                              | 6,145,769            | 6,380,862  | 6,876,225  |
| Distributions:                                                                            |                           |  |  |
|    Managing General Partner                                                | 175,202              | 165,810  | 181,197  |
|    Limited and Additional General 

     Partners | 1,585,813            | 1,463,308  | 808,663  |
|                                                                                           |                           |  |  |  |

ITEM 7.  MANAGEMENT'S DISCUSSION AND ANALYSIS OFFINANCIAL CONDITION

          ANDRESULTS OF OPERATIONS.

Liquidity and Capital Resources

     The Partnership was funded on December 31, 1998 with initial Limited and Additional General Partner contributionsof $20,525,261 and the Managing General Partner contributed $4,464,244 inaccordance with the Agreement.  Syndication and management fee costs of$2,668,284 were incurred leaving available cash of $22,321,221 for Partnershipactivities.

5

   The Partnership began exploration anddevelopment activities subsequent to the funding of the Partnership andcompleted these activities by December 31, 1999.  Ninety-seven wells have beendrilled, 89 of which have been completed as producers, currently the Partnershiphas eighty-four producing wells.  No additional wells will be drilled.

     The Partnership had workingcapital at December 31, 2004 of $469,077.

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

Results of Operations

 

2004 Results Compared to 2003 

     Oil and gas sales for the year ended December 31, 2004 were $2,692,812 compared to $2,469,093 for the year ended December 31, 2003.  For the year ended December 31, 2004, the Partnership sold 472,447 Mcfof gas and 16 barrels of oil at average sales prices of $5.70 and $34.25,respectively.  This compared with 518,437 Mcf of gas and 124 barrels of oilsold at average sales prices of $4.76 and $26.84, respectively for the yearended December 31, 2003. Lifting cost per Mcfe in 2004 amounted to $1.55 ascompared to $1.53 for 2003. The fixed costs of operations and well maintenanceare allocated to lower production volumes, therefore increasing the liftingcost per Mcfe.  Depreciation, depletion andamortization decreased from $515,111 for the year ended December 31, 2003 to $437,833 for the year ended December 31, 2004 as a result of lower volumes ofnatural gas and oil sold.  Cash distributions to the partners amountedto $1,761,015 in 2004 and $1,629,118 in 2003.

 

2003Compared to 2002

 

     Oiland gas sales for the year ended December 31, 2003 were $2,469,093 compared to $1,749,877 for the year ended December 31, 2002. For the year ended December 31, 2003, the Partnership sold 518,437 Mcf of gas and 124 barrels of oil atan average price of $4.76 and $26.84, respectively.  This compared with 597,799Mcf of gas and 60 barrels of oil sold at average prices of $2.93 and $14.68,respectively, for the year ended December 31, 2002.  Lifting cost per Mcfe in 2003 amounted to $1.53 as compared to $1.25 for 2002. This increase ispartially attributed to the increase in severance and property taxes. The fixedcosts of operations and well maintenance are allocated to lower productionvolumes, therefore increasing the lifting cost per Mcfe. Depreciation,depletion and amortization decreased from $623,393 for the year ended December 31, 2002 to $515,111 for the year ended December 31, 2003 as a result of lower volumes of natural gas sold. Cash distributions to the partners amounted to$1,629,118 in 2003 and $989,860 in 2002.

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

 

CriticalAccounting Policies and Estimates

      Certainaccounting policies are very important to the portrayal of the Partnership'sfinancial condition and results of operations and require management's mostsubjective or complex judgments.  In applying those policies, our managementuses its judgment to determine the appropriate assumptions to be used in thedetermination of certain estimates. Those estimates are based on our historicalexperience, our observance of trends in the industry, and information availablefrom other outside sources, as appropriate. For a more detailed discussion onthe application of these and other accounting policies, see "Note 1 - Summaryof significant account policies" in our financial statements and related notes.The Partnership's critical accounting policies and estimates are as follows:

 

RevenueRecognition

         Sales ofnatural gas are recognized when natural gas has been delivered to a custodytransfer point, persuasive evidence of a sales arrangement exists, the rightsand responsibility of ownership pass to the purchaser upon delivery, collectionof revenue from the sale is reasonably assured and the sales price is fixed ordeterminable.  Natural gas is sold by the Managing General Partner undercontracts with terms ranging from

                                                                       

                                                                                        6

onemonth 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 Partership 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.

Accounting forDerivatives Contracts at Fair Value

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

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

    Themeasurement of fair value is based on actively quoted market prices, ifavailable. Otherwise, the Partnership seeks indicative price information fromexternal sources, including broker quotes and industry publications. If pricinginformation from external sources is not available, measurement 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.

                                                                                    7

         ThePartnership assesses impairment of capitalized costs of proved oil and gas propertiesby comparing 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 costs exceedundiscounted future net cash flow, the measurement of impairment is based onestimated fair value which would consider future discounted cash flows.

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.

NewAccounting Standards

     In 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 $14,491 and a related liability of $28,491 (using a 6% discountrate) and a cumulative effect of change in accounting principle on prior yearsof $14,001.

     Item 7A.  Quantitative andQualitative Disclosure 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 natural gas sales.  These instruments consistof NYMEX-traded natural gas futures contracts and option contracts forAppalachian and Michigan production. These hedging arrangements have the effectof locking in for specified periods (at predetermined prices or ranges ofprices) the prices the Managing General Partner will receive for the volume towhich the hedge relates.  As a result, while these hedging arrangements arestructured to reduce the Partnership's exposure to changes in price associatedwith the hedged commodity, they also limit the benefit the Partnership mightotherwise have received from price changes associated with the hedgedcommodity.  The Partnership's policy prohibits the use of natural gas futureand option contracts for speculative purposes.

                                                                                        8

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 | Purchase | 7,092   | 6.63 | 47.054 | (2,700)      |
|-------------|----------|---------|------|--------|--------------|
| Natural Gas | Floors   | 195,038 | 4.79 | -      | 22,351  |
| Natural Gas | Ceilings | 97,519  | 5.73 | -      | (88,866)     |
|             |          |         |      |        |              |

Contracts maturing in 12 months following December 31, 2004

| Natural Gas | Purchase | 7,092 | 6.63 | 47.054 | (2,700) |  |  |  |  
Natural Gas

Floors

195,038

4.79

-

22,351 

 
Natural Gas

Ceilings

97,519

5.73

-

(88,866)

 
Prior Year Total Contracts as of December 31, 2003

Natural Gas

Sale

8,210

5.40

44,334

(6,149)

Natural Gas

Purchase

7,037

4.77

33,567

4,672 

Natural Gas

Floors

131,360

4.12

-    

1,412 

Natural Gas

Ceilings

106,730

5.55

-    

(18,982)

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

The average NYMEX closing price for natural gas for theyears 2004, 2003 and 2002 was $6.14 per Mmbtu, $5.39 per Mmbtu, and $3.22 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.

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

     Under the supervision andwith the participation of the Managing General Partner's management, includingthe Managing General Partner's Chief Executive Officer and Chief FinancialOfficer, the Managing General Partner has evaluated the effectiveness of thedesign and operation of its disclosure controls and procedures (as defined inExchange Act Rule 13a-14(c)) as of the end of the period covered by this annualreport on Form 10-K, and, based on their evaluation, the Chief ExecutiveOfficer and Chief Financial Officer have concluded that these disclosurecontrols and procedures are effective in all material respects, including thoseto ensure that information required 

                                                                                      9

to be disclosed in reports filed or submitted under theSecurities Exchange Act is recorded, processed, summarized, and reported,within the time periods specified in the Commission's rules and forms, and isaccumulated and communicated to management, including the Managing GeneralPartner's Chief Executive Officer and Chief Financial Officer, as appropriateto allow for timely disclosure. There have been no significant changes in ourinternal controls or in other factors that could significantly affect thesecontrols in the fourth quarter and subsequent to the date of their evaluation.

 

ITEM 9B.  OTHERINFORMATION

 

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 thePartnership has no Code of Ethics, Petroleum Development Corporation, theManaging General Partner of the Partnership, has a Code of Ethics that appliesto its senior executive officers.  The Code of Ethics is posted on the websiteof Petroleum Development Corporation at www.petd.com.

ITEM 11.  EXECUTIVE COMPENSATION.

        NON-APPLICABLE.

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

        NON-APPLICABLE.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.

     Pursuant to theauthorization contained in the Limited Partnership Agreement, PDC receives feesfor services rendered and reimbursement of certain expenses from thePartnership. See respective drilling prospectus for further informationregarding the Limited Partnership Agreement. The following table presentscompensation or reimbursements by the Partnership to PDC or other relatedparties for the years listed below:

Years  Ended December 31,

  2004   

  2003   

  2002   

Lifting costs

$733,486 

794,988 

745,099 

Tax return preparation

6,162 

8,886 

 8,847 

Direct administrative cost

3,950 

-     

5,848 

ITEM 14.  PRINCIPAL ACCOUNTANT FEES ANDSERVICES

     For the years ended December 31, 2004 and 2003, The Partnership paid KPMG LLP $5,997and $5,997 respectively,for professional services for the audit of the Partnership's financialstatements in its Form 10-K and review of financial statements included in thePartnership'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)       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. 333-41977, and Rule 424 final prospectus, dated June 19 1998, of PDC 2000 Drilling Program, filed with the SEC on June 30, 1998).

 
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 1998-D 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 been signedbelow 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

12

PDC 1998-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'sReport Thereon)

F-1

PDC 1998-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

 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 1998-DLimited Partnership:

We haveaudited the accompanying balance sheets of PDC 1998-D Limited Partnership (a West Virginia limited partnership) as of December 31, 2004 and 2003, and the relatedstatements of operations, partners' equity and comprehensive income, and cashflows for each of the years in the three-year period ended December 31, 2004. These financial statements are the responsibility of the Partnership's management.Our responsibility is to express an opinion on these financial statements basedon our audits.

We conductedour audits in accordance with the standards of the Public Company AccountingOversight Board (United States).  Those standards require that we plan andperform the audit to obtain reasonable assurance about whether the financialstatements are free of material misstatement.  An audit includes examining, ona test basis, evidence supporting the amounts and disclosures in the financialstatements.  An audit also includes assessing the accounting principles usedand significant estimates made by management, as well as evaluating the overallfinancial statement presentation.  We believe that our audits provide areasonable basis for our opinion.

In ouropinion, the financial statements referred to above present fairly, in allmaterial respects, the financial position of PDC 1998-D Limited Partnership asof December 31, 2004 and 2003, and the results of its operations and its cashflows for each of the years in the three-year period ended December 31, 2004,in conformity with U.S. generally accepted accounting principles.

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

                                                                                                                                                                    KPMGLLP

Pittsburgh, Pennsylvania 

April 15, 2005

F-3

PDC 1998-D LIMITEDPARTNERSHIP

(A West VirginiaLimited Partnership)

Balance Sheets

December 31, 2004 and 2003

     Assets

2004

2003

Cash

$      770 

      2,664 

Accounts  receivable - 

      oil  and gas revenues

   582,726 

   378,092 

          Total  current assets

583,496 

380,756 

Oil and gas  properties, successful efforts 

     method  (notes 3 and 6):

  10,146,279 

  10,146,279 

     Less  accumulated depreciation, 

      depletion, and  amortization

  4,584,006 

  4,146,173 

5,562,273 

6,000,106 

$6,145,769 

6,380,862 

     Liabilities  and Partners' Equity

Current  liabilities:

Due  to managing general partner

$         5,997 

-    

     Accrued  expenses

   108,422 

   42,042 

          Total  current liabilities

114,419 

42,042 

Asset retirement  obligation

32,013 

30,201 

Partners' equity

5,999,337 

6,308,619 

$6,145,769 

6,380,862 

See accompanying notes to financial statements.

F-4

PDC 1998-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

$2,692,812 

$2,469,093 

1,749,877 

     Interest income

           952 

    1,011 

    1,591 

2,693,764 

2,470,104 

1,751,468 

Expenses (note 3):

     Lifting cost

733,486 

794,988 

745,099 

     Independent audit fee

5,997 

5,997 

5,822 

     Franchise taxes

2,623 

2,780 

2,931 

     Tax return preparation

6,162 

8,886 

8,847 

     Direct administrative  cost

5,762 

642 

5,848 

     Depreciation, depletion

      and amortization

     437,833 

    515,111 

    623,393 

1,191,863 

1,328,404 

1,391,940 

Income before cumulative effect of change in 

   accounting principle

  1,501,901 

  1,141,700 

  359,528 

Cumulative effect of change in accounting principle

             -    

  (14,001)

    -    

Net income 

$ 1,501,901 

$ 1,127,699 

  359,528 

Net income per limited and additional general 

  partner unit before cumulative effect of  change 

  in accounting principle

  $     1,171 

  $     890 

        280 

Cumulative effect of change in accounting principle

        -    

        (11)

    -    

Net income per limited and additional general 

  partner unit

  $     1,.171 

  $     879 

      280 

See accompanying notes to financial statements.

F-5

PDC 1998-D LIMITED PARTNERSHIP

(A West VirginiaLimited Partnership)

Statements ofPartners' Equity and Comprehensive Income

Years Ended December 31, 2004, 2003 and 2002

  Limited and

Additional

General Partners

  Managing

General

Partner 

Accumulated

Other 

Comprehensive

Income (Loss)

  Total

Balance December 31, 2001

5,967,530

1,491,887

     -     

7,459,417

Distributions to  partners

(808,663)

(181,197)

(989,860)

Comprehensive  income:

 Net income 

287,622 

71,906 

359,528 

 Change in  fair value of  outstanding 

  hedging  positions

  (64,773)

Reclassification  adjustment for settled 

  contracts  included in net income 

        -    

Other  comprehensive loss

(64,773)

   (64,773)

  Comprehensive  income

            

           

           

   294,755 

Balance December 31, 2002

5,446,489 

 1,382,596 

   (64,773)

 6,764,312 

 

 

 

Distributions to  partners

(1,463,308)

(165,810)

(1,629,118)

Comprehensive  income:

 Net income 

902,160 

225,539 

1,127,699 

Change in fair  value of outstanding 

  hedging  positions

  36,952 

Reclassification  adjustment for settled 

 contracts   included in net income 

       8,774 

Other  comprehensive income

45,726 

    45,726 

  Comprehensive  income 

            

           

           

  1,173,425 

Balance December 31, 2003

$4,885,341 

 1,442,325 

   (19,047)

 6,308,619 

Distributions to  partners

(1,585,813)

(175,202)

(1,761,015)

Comprehensive  income:

 Net income 

1,201,521 

300,380 

1,501,901 

Change in fair  value of outstanding 

  hedging  positions

  (146,797)

Reclassification  adjustment for settled 

 contracts   included in net income 

       96,629 

Other  comprehensive income

(50,168)

    (50,168)

  Comprehensive  income 

                 

                  

                 

  1,451,733 

Balance December 31, 2004

$4,501,049 

1,567,503 

   (69,215)

 5,999,337 

   Seeaccompanying notes to financial statements.

F-6

PDC 1998-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 

$1,501,901 

$1,127,699 

  359,528 

    Adjustments to reconcile net  income to 

        net  cash provided from operating activities:

      Depreciation,  depletion and amortization

437,833 

515,111 

623,393 

      Cumulative effect  of change in accounting principle

-     

14,001 

-    

      Accretion of asset  retirement obligation

1,812 

1,709 

-    

      Changes in  operating assets and liabilities:

       (Increase) in  accounts receivable - 

        oil and  gas revenues

  (183,695) 

  (14,971) 

  (2,120) 

Increase in  due  to managing general partner

5,997 

-    

-       

       Increase (decrease)  in accrued expenses

       (4,727)

  (13,583)

    4,774 

       Net cash  provided from operating activities

1,759,121 

1,629,966 

  985,575 

Cash flows from financing activities:

     Distributions to partners

(1,761,015)

(1,629,118)

  (989,860)

       Net cash used  by financing activities

(1,761,015)

(1,629,118)

  (989,860)

 

 

 

Net increase (decrease) in cash

(1,894)

848 

(4,285)

Cash at beginning of year

     2,664 

     1,816 

     6,101 

Cash at end of year

$         770 

$     2,664 

     1,816 

See accompanyingnotes to financial statements.

F-7

PDC 1998-D LIMITEDPARTNERSHIP

(A West VirginiaLimited Partnership)

Notes to FinancialStatements

Years Ended 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 1998-D Limited Partnership(the Partnership). The statements do not include any assets, liabilities,revenues or expenses attributable to any of the partners' other activities. Petroleum Development Corporation ("PDC") serves as Managing GeneralPartner of the Partnership.

Oil and GasProperties

The Partnership followsthe successful efforts method of accounting for the cost of exploring for anddeveloping oil and gas reserves. Under this method, costs of development wells,including equipment and intangible drilling costs related to both producingwells and developmental dry holes, and successful exploratory wells arecapitalized and amortized on an annual basis to operations by theunits-of-production method using estimated proved developed reserves determinedat year end by the Managing General Partner's petroleum engineers. If adetermination is made that an exploratory well has not discovered economicallyproducible reserves, then its costs are expensed as dry 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. 

RevenueRecognition

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 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 when persuasiveevidence of a sales arrangement exists, the oil is verified as produced and isdelivered in a stock tank, collection of revenue from the sale is reasonablyassured and the sales price is determinable.  The Partnership is currently ableto sell all the oil that it can produce under existing sales contracts withpetroleum refiners and marketers.  The Partnership does not refine any of itsoil production.  The Partnership's crude oil production is sold to purchasersat or near the Partnership's wells under short-term purchase contracts atprices and in accordance with arrangements that are customary in the oilindustry. 

                                                                                 F-8

PDC 1998-D LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Notes to Financial Statements, Continued

 

 

IncomeTaxes

Sincethe taxable income or loss of the Partnership is reported in the separate taxreturns of the partners, no provision has been made for income taxes on thePartnership's books.

Underfederal income tax laws, regulations and administrative rulings, certain typesof transactions may be accorded varying interpretations.  Accordingly, thePartnership's tax return and, consequently, individual tax returns of thepartners may be changed to conform to the tax treatment resulting from a reviewby the Internal Revenue Service.

DerivativeFinancial Instruments

TheManaging General Partner utilizes commodity based derivative instruments ashedges to manage a portion of the Partnership's exposure to price volatilitystemming from natural gas production. These instruments consist of costlesscollars and option contracts traded on the New York Mercantile Exchange.  Thecostless collars and option contracts hedge committed and anticipated naturalgas sales generally forecasted to occur within a 24 month period. ThePartnership does not hold or issue derivatives for trading or speculativepurposes. 

Allderivatives are recognized on the Partnership balance sheet at their fairvalue. On the date the derivative contract is entered into, the ManagingGeneral Partner designates the derivative as either a hedge of a forecastedtransaction or the variability of cash flows to be received or paid related toa recognized asset or liability ("cash flow" hedge), or a non-hedgingderivative. The Managing General Partner formally documents all relationshipsbetween hedging instruments and hedged items, as well as its risk-managementobjective and strategy for undertaking various hedge transactions. This processincludes linking all derivatives that are designated as cash-flow hedges tospecific firm commitments. The Managing General Partner also formally assesses,both at the hedge's inception and on an ongoing basis, whether the derivativesthat are used in hedging transactions are highly effective in offsettingchanges in cash flows of hedged items.  When it is determined that a derivativeis not highly effective as a hedge or that it has ceased to be a highlyeffective hedge, the Partnership discontinues hedge accounting prospectively.No hedging activities were discontinued during 2004 or 2003.

Changesin fair value of a derivative that is highly effective and that is designatedand qualifies 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, or the Partnership determines thatdesignation of the derivative as a hedging instrument is no longer appropriate,hedge accounting will be discontinued.

By using derivative financialinstruments to hedge exposures to changes in commodity prices, the ManagingGeneral Partner exposes the Partnership to credit risk. Credit risk is thefailure of the counterparty to perform under the terms of the derivativecontract. When the fair value of a derivative contract is positive, thecounterparty owes the Partnerhip, which creates credit risk. The ManagingGeneral Partner minimizes the credit risk in derivative instruments by enteringinto transactions with high-quality counterparties.

F-9

PDC 1998-D LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Notes to Financial Statements, Continued

 

Useof Estimates

ThePartnership has made a number of estimates and assumptions relating to thereporting of assets and liabilities and revenues and expenses and thedisclosure of contingent assets and liabilities to prepare these financialstatements in conformity with accounting principles generally accepted in the United States of America. Actual results could differ from those estimates. Estimates whichare particularly significant to the financial statements include estimates ofoil and gas reserves and future cash flows from oil and gas properties whichare used in assessing impairment of long-lived assets.

New Accounting Standards

 InJune 2001, the Financial Accounting Standard Board issued FASB No. 143,"Accounting for Asset Retirement Obligations" that requires entitiesto record the fair value of a liability for an asset retirement obligation inthe period in which it is incurred and a corresponding increase in the carryingamount of the related long-lived asset. This statement is effective for fiscalyears beginning after June 15, 2002. The Partnership adopted FASB No. 143 on January 1, 2003 and recorded a net asset of $14,491 and a related liability of $28,491(using a 6% discount rate) and a cumulative effect of change in accountingprinciple on prior years of $14,001.

(2)  Organization

ThePartnership was organized as a limited partnership on December 31, 1998 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 Northern Appalachian and Michigan Basins.

Purchasersof partnership units subscribed to and fully paid for 16.5 units of limitedpartner interests and 1,009.763 units of additional general partner interestsat $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 accordancewith the terms of the Limited Partnership Agreement (the Agreement), theManaging General Partner manages all activities of the Partnership and acts asthe intermediary for substantially all Partnership transactions.

(3)   Transactionswith Managing General Partner 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 Partnershipto PDC or other related parties for years ended December 31, 2004, 2003 and 2002.

F-10

PDC 1998-D LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Notes to Financial Statements, Continued

 

 

Years Ended December 31,

  2004  

  2003  

  2002  

Lifting  costs

$733,486

$794,988 

745,099 

Tax  return preparation

6,162

8,886 

8,847 

Direct  administrative cost

3,950

-    

5,848 

 (4)   Allocation

Thefollowing table summarizes the participation of the Managing General Partnerand the Investor Partners, taking account of the Managing General Partner'scapital contribution equal to a minimum of 20% of the initial capital, in thecosts and revenues of the Partnership.

 

  Investor

Partners(5)(6)

Managing

General

Partners(5)(6)

Partnership Costs

Broker-dealer  Commissions and Expenses(1)

100%

0%

Management Fee(2)

100%

0%

Undeveloped Lease  Costs

0%

100%

Drilling and  Completion Costs

80%

20%

Tangible Equipment

0%

100%

Intangible  Drilling and Development Costs

100%

0%

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.

(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.  Inaccordance with the drilling prospectus the investor partners receivedpreferred cash distributions of $176,999, $160,012 and $16,773 in 2004, 2003and 2002.

F-11

PDC 1998-D LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Notes to Financial Statements, Continued

 

(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 share ofall Leases and tangible well equipment. The entire Capital Contribution of theInvestor 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 the ManagingGeneral Partner's allocation of profits, losses, and cash distributions will beincreased 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 a total of 13.07 units ofpartnership interest for a total ownership of 38.49 units as of December 31, 2004 which represents a 3.75% ownership of the original Investor Partnersshare of limited and additional general partnership units.  Therefore, costsand revenues and distributions for these purchased units are allocated to PDCin accordance with the Investor Partners allocation percentages disclosed inthis table.

(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 natural gassales.  These instruments consist of NYMEX-traded natural gas futures contractsand option contracts for Appalachian and Michigan production. These hedgingarrangements have the effect of locking in for specified periods (atpredetermined prices or ranges of prices) the prices the Managing GeneralPartner will receive for the volume to which the hedge relates.  As a result,while these hedging arrangements are structured to reduce the Partnership'sexposure to changes in price associated with the hedged commodity, they alsolimit the benefit the Partnership might otherwise have received from pricechanges associated with the hedged commodity.  The Partnership's policyprohibits the use of natural gas future and option contracts for speculativepurposes.

The following tablessummarize the open futures and options 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

Purchase

7,092

6.63

47.054

(2,700)

Natural Gas

Floors

195,038

4.79

-

22,351 

Natural Gas

Ceilings

97,519

5.73

-

(88,866)

F-12

                                                     PDC 1998-D LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

                                                                      Notes to Financial Statements, Continued

Contracts maturing in 12 months following December 31, 2004

Natural Gas

Purchase

7,092

6.63

47.054

(2,700)

 
Natural Gas

Floors

195,038

4.79

-

22,351 

 
Natural Gas

Ceilings

97,519

5.73

-

(88,866)

 
Prior Year Total Contracts as of December 31, 2003

Natural Gas

Sale

8,210

5.40

44,334

(6,149)

Natural Gas

Purchase

7,037

4.77

33,567

4,672 

Natural Gas

Floors

131,360

4.12

-    

1,412 

Natural Gas

Ceilings

106,730

5.55

-    

(18,982)

Themaximum term over which the Partnership is hedging exposure to the variabilityof cash flows for commodity price risk is 12 months.

(6)  Costs Relating to Oil and GasActivities

ThePartnership is engaged solely in oil and gas activities, all of which arelocated in the continental United States.  Information regarding aggregatecapitalized costs and results of operations for these activities is located inthe basic financial statements.  Costs capitalized for these activities are asfollows:

                December  31,             

2004

2003

2002

Lease acquisition costs

$  460,141 

 460,141 

460,141 

Intangible development  costs

16,510,178 

16,510,178 

16,510,178 

Well  equipment

3,917,618 

3,917,618 

3,917,618 

Impairment  charge

(10,764,226)

(10,764,226)

(10,764,226)

Capitalized  asset retirement cost

     22,568 

     22,568 

            -    

$ 10,146,279 

 10,146,279 

 10,123,711 

Therewere no costs incurred for the Partnership's oil and gas activities for theyears ended December 31, 2004, 2003 and 2002.

(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 $1,116,527 and $1,426,382,respectively.

(8)  SupplementalReserve Information (Unaudited)

Provedoil and gas reserves of the Partnership have been estimated by the ManagingGeneral Partner's petroleum engineer at December 31, 2004, 2003 and 2002. These reserves have been prepared in compliance with the Securities andExchange Commission rules based on year end prices. A copy of the reservereport has been made available to all partners. All of the partnership'sreserves are proved developed.  An analysis of the change in estimatedquantities of proved developed oil and gas reserves is shown below:

F-13

                                                 PDC 1998-D LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Notes to Financial Statements, Continued

Gas  (MCF)

 
2004

2003

2002

 
Proved developed reserves:

Beginning of year

6,057,000 

6,248,000 

5,746,000 

 
Revisions of previous estimates

453,000 

327,000 

1,100,000 

 
Production

(472,000)

(518,000)

(598,000)

 
End of year

6,038,000 

6,057,000 

6,248,000 

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

        andGas Reserves (Unaudited)

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

As of  December 31,

2004

2003

2002

Future estimated revenues

$  36,988,000 

 32,492,000 

24,688,000 

Future estimated production costs

(14,657,000)

(12,459,000)

(10,263,000)

Future estimated development costs

(30,000)

(30,000)

(30,000)

   Future net cash flows

22,301,000 

20,003,000 

14,395,000 

10% annual discount for estimated timing of cash flows

(11,403,000)

(10,194,000)

(7,008,000)

Standardized measure of discounted future

   estimated net cash flows

$10,898,000 

$9,809,000 

7,387,000 

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

$(1,960,000)

(1,674,000)

   (1,005,000)

Net changes in prices and production costs

2,762,000 

6,530,000 

7,450,000 

Revisions of previous quantity estimates

1,496,000   

752,000  

1,276,000 

Accretion of discount

(1,209,000)

(3,186,000)

(4,037,000)

 $    1,089,000 

$    2,422,000 

     3,684,000 

It isnecessary to emphasize that the data presented should not be viewed asrepresenting the expected cash flows 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.

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