CONFORMED COPY

SECURITIES ANDEXCHANGE COMMISSION

Washington, D.C. 20549

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

 THE SECURITIESEXCHANGE ACT OF 1934

 For the fiscalyear ended December 31, 2004

 Commission FileNumber  033-63635-08

[]Transition ReportPursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 for thetransaction period from          to          

PDC 1997-D LIMITEDPARTNERSHIP

(Exact name ofregistrant as specified in its charter)

|                                 |                     |
|---------------------------------|---------------------|
| West Virginia                   | 31-1514713          |
| (State or other jurisdiction of | (I.R.S. Employer    |
| incorporation or organization)  | Identification No.) |
|                                 |                     |

103 East Main  Street, Bridgeport, West Virginia  26330

(Address ofprincipal executive offices)     (zip code)

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

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

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

General and LimitedPartnership Interests

(Title of class)

Indicate by check mark whether the registrant (1) 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 __   No    X 

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's securities.

PART I

ITEM 1.  BUSINESS.

General

     PDC 1997-D LimitedPartnership ("the Partnership") is a limited partnership formed on December 30, 1997 pursuant to the West Virginia Uniform Limited Partnership Act. Petroleum Development Corporation ("PDC") serves as Managing GeneralPartner of the Partnership.

     Since the commencement ofoperations on December 30, 1997, the Partnership has been engaged in onshore,domestic gas exploration exclusively in the Northern Appalachian and Michigan Bas  ins.  A total of 11 limited partners contributed initial capital of $159,000;a total of 1,050 additional general partners contributed initial capital of$18,360,579; and PDC (Managing General Partner) contributed $4,028,009 incapital as a participant in accordance with contribution provisions of theLimited Partnership Agreement (the Agreement). During 1998 in accordance withthe Partnership Agreement, all Additional General Partners were converted toLimited Partners.

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

|                                         | Allocation

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

     Operating and direct costsare allocated and charged to the additional general and limited partners and theManaging General Partner in the same percentages as revenues are allocated. Leasehold, drilling and completion costs, and equipment costs are borne 80% bythe additional general and limited partners and 20% by the Managing GeneralPartner. See Footnote 4 of financial statements for a complete description ofthe allocation of Partnership revenue and costs.

Employees

     The Partnership has 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 101 gross wells (94 gross productive wells) andwill continue to operate and produce its productive wells.  The Partnershipdoes not have unexpended initial capital and no additional drilling activity isplanned.

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

Markets for Oil and Gas

     The availability of a marketfor any oil and gas produced from the operations of the Partnership will dependupon a number of factors beyond the control of the Partnership which cannot beaccurately predicted.  These factors include the proximity of the Partnershipwells to and the capacity of natural gas pipelines, the availability and priceof competitive fuels, fluctuations in seasonal supply and demand, andgovernment regulation of supply and demand created by its pricing andallocation restrictions.  Oversupplies of gas can be expected to occur fromtime to time and may result in the Partnership's wells being shut-in orcurtailed.  Increased imports of oil and natural gas have occurred and areexpected to continue. The effects of such imports could adversely impact themarket for domestic oil and natural gas. All oil and natural gas is sold undercontracts based on market sensitive indexes that vary from month to month. Nofixed price contracts are in place. The Partnership sold oil and natural gas toone customer which accounted for 100% of the Partnership's total oil andnatural gas sales for the years ended December 31, 2004, 2003 and 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 contracts. The contracts hedge committed and anticipated natural gas sales, generallyforecasted to occur within a 12 month period. The Managing General Partner doesnot hold or issue derivatives for trading or speculative purposes and permitsutilization of hedges only if there is an underlying physical position.  See"Commodity Price Risk" under Item 7A.

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

Competition

     The Partnership competes inmarketing its gas 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, $3,100 and $2,000 in 2004, 2003 and2002, 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 energyare being considered by the United States Congress, various state legislaturesand regulatory agencies.  The possible outcome and effect of these proposalscannot be accurately predicted.

3

          Environmentaland Safety Regulation.  The Partnership believes that it complies, in allmaterial respects, with all legislation and regulations affecting itsoperations in the drilling and production of oil and gas wells and thedischarge of wastes.  To date, compliance with such provisions and regulationshas not had a material effect upon the Partnership's expenditures for capitalequipment, its operations or its competitive position.  The cost of suchcompliance is not anticipated to be material in the future.

ITEM 2.  PROPERTIES.

Drilling Activity

     The following table setsforth the results of drilling activity of the Partnership which was conductedin the Continental United States.

|                                                    Development  Wells                                               |
|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
|         Gross  Wells                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                          |         Net  Wells       |
| Productive                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                               | Dry | Total | Productive | Dry | Total |
|                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                          |  |  |  |  |  |
| 94                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                       | 7 | 101 | 70.37 | 4.64 | 75.01 |

The Partnership has not participated in any exploratorywells.  No additional drilling activity is planned.

Production 

See "Management's Discussion and Analysis" onpage 6 for Partnership production. 

Reserves

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

Summary of Productive Wells

     During 2002 the Partnershiptransferred title to nine wells in the Paxton Quarry Antrim Unit in Michigan to an unrelated third party and received no proceeds and incurred no costs.  Thetable below shows the number of the Partnership's gross and net wells by stateas of December 31, 2004.

|                    |  Natural Gas Wells       |
|--------------------|---------------------------------------------------|
| Location           | Gross                                             | Net    |
| Michigan           | 27                                                | 12.69 |
| Pennsylvania       | 55                                                | 50.73 |
| West Virginia      |  3                                           |  2.99 |
|    Total | 85                                                | 66.41 |

     A "productive well" is a wellproducing, or capable of producing, oil and gas in commercial quantities. Forpurposes of the above table, a "gross well" is one in which thePartnership has a working interest and a "net well" is a gross wellmultiplied by the Partnership's working interest to which it is entitled underits 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 oiland gas industry, little or no investigation of title is made at the time ofacquisition of undeveloped properties (other than a preliminary review of localmineral records).  Investigations are generally made, including in most casesreceiving a title opinion of legal counsel, before commencement of drillingoperations. A thorough examination of title has been made with respect to allof the Partnership's producing properties and the Partnership believes that ithas generally satisfactory title to such properties.

ITEM 3.  LEGAL PROCEEDINGS.

     The Managing GeneralPartner as driller/operator is not party to any legal action that it believeswould have a materially adverse affect on the Managing General Partner's orPartnership's business, financial condition, results of operations orliquidity.

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

     Not Applicable.

PART II

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

     At December 31, 1997, PDC1997-D Limited Partnership had one Managing General Partner, 11 LimitedPartners who fully paid for 7.95 units at $20,000 per unit of limitedpartnership interests and a total of 1,050 Additional General Partners whofully paid for 918.02895 units at $20,000 per unit of additional generalpartnership interests.  During 1998 in accordance with the PartnershipAgreement, all Additional General Partners were converted to Limited Partners.No established public trading market exists for theinterests.  Limited and additional general partnership interests aretransferable, however no assignee of an interest in the Partnership can becomea substituted partner without the written consent of the transferor and theManaging General Partner. There is no established trading market for thesecurities 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                                                       | $1,624,890                    | 1,507,746            | 1,083,570  |
| Costs and Expenses                                                      | 900,422                       | 979,218              | 1,049,310  |
| Cumulative effect of change in accounting 

   principle | -              | (18,847)        | -     |
| Net Income                                                              | 725,005                       | 510,311         | 35,343  |
| Allocation of Net Income:                                               |                                         |                           |  |
|                                                                         | Managing General Partner                | 145,001         | 102,062   | 7,069  |
|                                                                         | Limited and Additional General Partners | 580,004         | 408,249   | 28,274  |
|                                                                         | Per Limited and Additional General      |                           |  |  |
|                                                                         |  Partner Unit                      | 626             | 441  | 31  |
| Total Assets                                                            |     3,524,446            | 3,615,547                 | 3,882,471  |
| Distributions:                                                          |                                         |                           |  |
|                                                                         | Managing General Partner                | 85,575                    | 89,795 | 23,794  |
|                                                                         | Limited and Additional General Partner  | 750,047                   | 708,616 | 294,098  |

 

 

 

 

 

5

 

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

Liquidity and Capital Resources

     The Partnership was funded withinitial Limited and Additional General Partner contributions of $18,519,579 andthe Managing General Partner contributed $4,028,009 in accordance with theAgreement.  Syndication and management fee costs of $2,407,545 were incurredleaving available cash of $20,140,043 for Partnership activities.

     The Partnership beganexploration and development activities subsequent to the funding of thePartnership and completed these activities by December 31, 1998.  One hundred and one wells have been drilled, 94 of which have been completed as producers,currently the Partnership has 85 producing wells.  No additional wells will bedrilled.

     The Partnership had workingcapital at December 31, 2004 of $232,328.

     Operations are expected tobe conducted with available funds and revenues generated from oil and naturalgas activities.  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 $1,624,890 compared to $1,507,746 for the year ended December 31, 2003. The volume of natural gas sold for the year ended December 31, 2004 was 287,142 Mcf at an average sales price of $5.65 per Mcf compared to 313,240 Mcfat an average sales price of $4.81 per Mcf for the year ended December 31, 2003.  The lifting cost for the year ended December 31, 2004, was $2.25 per Mcf compared to $2.22 per Mcf for the year ended December 31, 2003.  This increase is partially attributed to the increase in severance and property taxes.  Thefixed costs of operations and well maintenance are allocated to lowerproduction volumes, therefore increasing the lifting cost per Mcf. Depreciation,depletion and amortization decreased from $259,938 for the year ended December 31, 2003 to $227,438 for the year ended December 31, 2004.  Cash distributions to the partners amounted to $835,622 in 2004.

2003 Compared to 2002

     Oiland gas sales for the year ended December 31, 2003 were $1,507,746 compared to $1,083,570 for the year ended December 31, 2002. The volume of natural gas sold for the year ended December 31, 2003, was 313,240 Mcf at an averagesales price of $4.81 per Mcf compared to 366,668 Mcf at an average sales priceof $2.96 per Mcf for the year ended December 31, 2002. The lifting cost for the year ended December 31, 2003 was $2.22 per Mcf compared to $2.02 per Mcf forthe year ended December 31, 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 Mcf. Cash distributions to the partnersamounted to $798,411 in 2003.

     The Partnership's revenuesfrom oil and gas will be affected by changes in prices. As a result of changesin federal regulations, gas prices are highly dependent on the balance betweensupply and demand. The Partnership's gas sales prices are subject to increaseand decrease based on various market sensitive indices.

 

CriticalAccounting Policies and Estimates

     Certain accountingpolicies are very important to the portrayal of the Partnership's financialcondition and results of operations and require management's most subjective orcomplex judgements. In applying those policies, our management uses itsjudgment 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:

                                                                                  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 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 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 of derivativesthat are not designated as accounting hedges are recorded in earnings. 

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

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

Use of Estimates inLong-Lived Asset Impairment Testing

Impairmenttesting for long-lived assets and intangible assets with definite lives isrequired when circumstances indicate those assets may be impaired.  In performingthe impairment test, the Partnership would estimate the future cash flowsassociated with individual assets or groups of assets.  Impairment must berecognized when the undiscounted estimated future cash flows are less than therelated 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 Partnership assessesimpairment of capitalized costs of proved oil and gas properties by comparingnet capitalized costs to estimated undiscounted future net cash flows on afield-by-field basis using expected prices. Prices utilized in each year'scalculation for measurement purposes and expected costs are held constantthroughout the estimated life of the properties. If net capitalized costsexceed undiscounted future net cash flow, the measurement of impairment isbased on estimated fair value which would consider future discounted cashflows.

Property acquisition costs are capitalized whenincurred.  Geological and geophysical costs and delay rentals are expensed asincurred.  The costs of drilling exploratory wells are capitalized pendingdetermination of whether the wells have discovered economically produciblereserves.  If reserves are not discovered, such costs are expensed as dryholes.  Development costs, including equipment and intangible drilling costsrelated to both producing wells and developmental dry holes, are capitalized.

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

Costs of provedproperties, including leasehold 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 $12,102 and a related liability of $30,949 (using a 6% discountrate) and a cumulative effect of change in accounting principle on prior yearsof $18,847.

Item 7A.  Quantitative and QualitativeDisclosure About Market Risk.

Market-Sensitive Instruments and Risk Management

     ThePartnership's primary market risk exposure is commodity price risk.  Thisexposure is discussed in detail 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 theeffect of locking in for specified periods (at predetermined prices or rangesof prices) the prices the Managing General Partner will receive for the volumeto which the hedge relates.  As a result, while these hedging arrangements arestructured to reduce Partnership's exposureto changes in price associated with the hedged commodity, they also limit thebenefit the Partnership might otherwise have received from price changesassociated with the hedged commodity.  The Partnership's policy prohibits theuse of natural gas future and option contracts for speculative purposes.

     

The following tables summarize the open futures and optionscontracts 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                                                  | Purchase | 4288        | 6.63     | 28,448                    | (1,632)   |
|  Natural Gas                                            | Floors   | 117,914     | 4.79     | -     | 13,513    |
| Natural Gas                                                  | Ceilings | 58,957      | 5.73     | -     | (53,725)  |
|                                                              |          |             |          |                           |           |
| Contracts  maturing in 12 months following December 31, 2004 |
| Natural Gas                                                  | Purchase | 4288        | 6.63     | 28,448                    | (1,632)   |
|  Natural Gas                                            | Floors   | 117,914     | 4.79     | -     | 13,513    |
| Natural Gas                                                  | Ceilings | 58,957      | 5.73     | -     | (53,725)  |
|                                                              |
| Prior  Year Total Contracts as of December 31, 2003          |
| Natural Gas                                                  | Sale     | 5,102       | 5.40     | 27,552                    | (3,821)   |
| Natural Gas                                                  | Purchase | 4,373       | 4.77     | 20,861                    | 2,903     |
| Natural Gas                                                  | Floors   | 81,635      | 4.12     | -     | 878  |
| Natural Gas                                                  | Ceilings | 66,328      | 5.55     | -     | (11,796)  |

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 naturalgas for the years 2004, 2003 and 2002 was $6.14 per Mmbtu, $5.39 per Mmbtu and$3.22 per Mmbtu.  Future near-term gas prices will be affected by varioussupply and demand factors such as weather, government and environmentalregulations and new drilling activities within the industry.

Disclosure of Limitations

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

Part III

ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA:

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

ITEM 9.  CHANGES IN AND DISAGREEMENTS 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 disclosure controls and procedures are effective inall material respects, including those to ensure that information required tobe disclosed in reports filed or submitted under the Securities Exchange Act isrecorded, processed, summarized, and reported, within the time periodsspecified in the Commission's rules and forms, and is accumulated andcommunicated to management, including the Managing General Partner's 

                                                                                9

Chief Executive Officer and Chief Financial Officer, asappropriate 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 the Partnership,has a Code of Ethics that applies to its senior executive officers.  The Codeof Ethics is posted on the website of Petroleum Development Corporation at www.petd.com.

ITEM 11.  EXECUTIVE COMPENSATION.

        NON-APPLICABLE.

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

        NON-APPLICABLE.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.

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

|                            | Years  Ended  December 31, |
|----------------------------|---------------------------------|
|                            | 2004                            | 2003 | 2002 |
| Lifting costs              | $646,065                        | 695,140 | 738,953  |
| Tax return preparation     | 9,013                           | 8,862 | 8,960  |
| Direct administrative cost | 4,337                 | 4,171 | 4,739  |
|                            |                                 |  |  |  |  |

ITEM 14.  PRINCIPAL ACCOUNTANT FEES ANDSERVICES 

     For the years endedDecember 31, 2004 and 2003, the Partnership paid KPMG LLP $7,381 and $7,166,respectively for professional services for the audit of the Partnership'sfinancial statements in its Form 10-K and the review of financial statements inthe 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. 333-28535, and Rule 424 final prospectus, dated June 11, 1997, of PDC 1996-1997 Drilling Program, filed with the SEC on June 12, 1997). |
|------|----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| 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.  |
|      |                                                                                                                                                                                                                                                    |

11CONFORMED 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 1997-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 the requirements of theSecurities Exchange Act of 1934, this report has been signed below by thefollowing persons on behalf of the Registrant and in the capacities and on thedates 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 1997-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 1997-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

Report ofIndependent Registered  Public Accounting Firm

To the Partners

PDC 1997-D Limited Partnership:

We have audited theaccompanying balance sheet of PDC 1997-A Limited Partnership (a West Virginia limited partnership) as of December 31, 2004 and 2003, and the relatedstatements of operations, partners' equity and comprehensive income (loss), andcash flows for each of the years in the three-year period ended December 31, 2004. These financial statements are the responsibility of the Partnership'smanagement. Our responsibility is to express an opinion on these financialstatements based on our audits.

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

In our opinion, thefinancial statements referred to above present fairly, in all materialrespects, the financial position of PDC 1997-D Limited Partnership as ofDecember 31, 2004 and 2003, and the results of its operations and its cashflows for each of the years in the three-year period ended December 31, 2004,in conformity with U.S. generally accepted accounting principles.

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

Pittsburgh, Pennsylvania

April 19, 2005

F-3

PDC 1997-D LIMITEDPARTNERSHIP

(A West VirginiaLimited Partnership)

Balance Sheets

December 31, 2004 and 2003

Assets

2004  

2003  

Cash

$      983

  532 

Accounts receivable - oil and gas revenues

  317,821

  181,935 

     Total current assets

318,804

182,467 

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

7,057,624

7,057,624 

  Less accumulated depreciation, depletion,  and amortization

3,851,982

3,624,544 

3,205,642

3,433,080 

$3,524,446

3,615,547 

Liabilities and Partners' Equity

Current liabilities:

  Accrued expenses

$   86,476

    38,920 

     Total current liabilities

86,476

38,920 

Asset retirement obligation

34,774

32,806 

Partners' equity

3,403,196

3,543,821 

$3,524,446 

3,615,547 

See accompanying notes to financial statements.

F-4

PDC 1997-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

$1,624,890 

1,507,746 

1,083,570 

   Interest income

      557 

      630 

    1,083 

1,625,447 

1,508,376 

1,084,653 

Expenses (note 3):

   Lifting cost

646,065 

695,140 

738,953 

   Independent audit fee

7,381 

7,166 

6,957 

   Franchise taxes

4,240 

2,084 

2,125 

   Tax return preparation

9,013 

8,862 

8,960 

   Direct administrative cost

6,305 

6,028 

4,739 

   Depreciation, depletion and  amortization

  227,438 

  259,938 

  287,576 

  900,442 

  979,218 

1,049,310 

Income before cumulative effect of 

  change in accounting principle

725,005 

  529,158 

  35,343 

Cumulative effect of change in accounting 

  principle

 

            -                            

     (18,847)

         -    

Net income 

$   725,005 

   510,311 

   35,343 

Net income per limited and additional 

  general partner unit before cumulative  effect of change in accounting principle

  $      626 

        457 

         31 

Cumulative effect of change in accounting 

  principle

        -

        (16)

         -    

Net income per limited and additional 

  general partner unit

  $      626 

      441 

       31 

See accompanying notes to financial statements.

F-5

PDC 1997-D LIMITED PARTNERSHIP

(A West VirginiaLimited Partnership)

Statements ofPartners' Equity and Comprehensive Income (Loss)

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

$2,998,859 

$1,127,447 

-     

$4,126,306 

Distributions to  partners

(294,098)

(23,794)

(317,892)

Comprehensive  loss:

  Net  income 

28,274 

7,069 

35,343 

  Change  in fair value of 

   outstanding  hedging positions

  (40,121)

   Reclassification adjustment for  settled 

      contracts included in net income 

                -    

  Other  comprehensive income (loss)

(40,121)

   (40,121)

  Comprehensive  loss

                  

                   

                  

    (4,778)

Balance December 31, 2002

2,733,035 

 1,110,722 

   (40,121)

 3,803,636 

Distributions to  partners

(708,616)

(89,795)

(798,411)

Comprehensive  income:

Net income 

408,249 

102,062 

510,311 

  Change  in fair value of outstanding 

   hedging  positions

  22,832    

  Reclassification adjustment for settled

    contracts  included in net income 

  5,453 

  Other  comprehensive income (loss)

(28,285)

          28,285 

  Comprehensive  income

                  

                  

                  

     538,596 

Balance December 31, 2003

      2,432,668 

      1,122,989

(11,836)

         3,543,821

Distributions to  partners

(750,047)

(85,575)

(835,622)

Comprehensive  income:

Net income 

580,004 

145,001

725,005

  Change  in fair value of outstanding 

   hedging  positions

(88,427)

  Reclassification adjustment for settled

    contracts  included in net income

58,419 

  Other  comprehensive income (loss)

(30,008)

(30,008)

  Comprehensive  income

________

_________

________

    694,997

Balance December 31, 2004

      $2,262,625 

$1,182,415 

 $(41,844)

        $3,403,196

See accompanyingnotes to financial statements.

F-6

PDC 1997-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 

$725,005 

510,311 

35,343 

   Adjustments  to reconcile net income to net cash 

     provided  from operating activities:

       Depreciation,  depletion and amortization

227,438 

259,938 

287,576 

       Cumulative  effect of change in accounting principle

-     

18,847 

-    

       Accretion  of asset retirement obligation

1,968 

1,857 

-    

       Changes  in operating assets and liabilities:

       (Increase)  decrease in accounts receivable 

         -  oil and gas revenues

  (123,251)

  9,007 

  (10,551)

        Decrease (increase) in accrued expenses

  4,913

  (5,091)

   6,334 

 

 

 

        Net  cash provided from operating activities

 836,073 

 794,869 

 318,702 

 

 

 

Cash flow from  financing activities:

 

 

 

    Distributions  to partners

(835,622)

(798,411)

(317,892)

 

 

 

          Net  cash used by financing activities

(835,622)

(798,411)

(317,892)

Net increase (decrease)  in cash

451

(3,542)

810 

Cash at beginning  of year

   532 

   4,074 

   3,264 

Cash at end of  year

$     983 

     532 

   4,074 

See accompanyingnotes to financial statements.

F-7

PDC 1997-D LIMITEDPARTNERSHIP

(A West VirginiaLimited Partnership)

Notes to FinancialStatements

Years Ended December 31, 2004, 2003 and 2002

(1)  Summaryof Significant Accounting Policies

PartnershipFinancial Statement Presentation Basis

Thefinancial statements include only those assets, liabilities and results ofoperations of the partners which relate to the business of PDC 1997-D LimitedPartnership (the Partnership).  The statements do not include any assets,liabilities, revenues or expenses attributable to any of the partners' otheractivities.  Petroleum Development Corporation ("PDC") serves asManaging General Partner of the Partnership.

Oiland Gas Properties

ThePartnership follows the successful efforts method of accounting for the cost ofexploring for 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 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.  

ThePartnership assesses impairment of capitalized costs of proved oil and gas propertiesby comparing 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 is reasonablyassured and the sales price is fixed or determinable.  Natural gas is sold bythe Managing General Partner under contracts with terms ranging from one monthto three years.  Virtually all of the Managing General Partner's contractspricing provisions are tied to a market index, with certain adjustments basedon, among other factors, whether a well delivers to a gathering or transmissionline, quality of natural gas and prevailing supply and demand conditions, sothat the price of the natural gas fluctuates to remain competitive with otheravailable natural gas supplies.  As a result, the Partnership's revenues fromthe sale of natural gas will suffer if market prices decline and benefit ifthey increase.  The Managing General Partner believes that the pricingprovisions of its natural gas contracts are customary in the industry.

The Managing GeneralPartner currently uses the "Net-Back" method of accounting for transportationarrangements of natural gas sales.  The Managing General Partner sells gas at thewellhead and collects a price and recognizes revenues based on the wellheadsales price since transportation costs downstream of the wellhead are incurredby the Managing General Partner's customers and reflected in the wellheadprice.

F-8

PDC 1997-D LIMITEDPARTNERSHIP

(A West VirginiaLimited Partnership)

Notes to Financial Statements

Sales of oil are recognizedwhen persuasive 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 not refineany of its oil production.  The Partnership's crude oil production is sold topurchasers at or near the Partnership's wells under short-term purchasecontracts at prices and in accordance with arrangements that are customary inthe oil industry. 

ThePartnership sold oil and natural gas to one customer which accounted for 100%of the Partnership's total oil and natural gas sales for the years ended December 31, 2004, 2003 and 2002.

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.  Thisprocess includes linking all derivatives that are designated as cash-flowhedges to specific firm commitments. The Managing General Partner also formallyassesses, both at the hedge's inception and on an ongoing basis, whether thederivatives that are used in hedging transactions are highly effective inoffsetting changes in cash flows of hedged items.  When it is determined that aderivative is not highly effective as a hedge or that it has ceased to be ahighly effective hedge, the Partnership discontinues hedge accountingprospectively.  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 othercomprehensive income (loss), until earnings are affected by the variability incash flows of the designated hedged item. Changes in the fair value ofnon-hedging derivatives are reported in current-period earnings. ThePartnership discontinues hedge accounting prospectively when it is determinedthat the derivative is no longer effective in offsetting changes in the cashflows of the hedged item, the derivative expires or is sold, terminated, orexercised.  Additionally, if the derivative is designated as a hedginginstrument, because it is probable that a forecasted transaction will notoccur, or the Partnership determines that designation of the derivative as ahedging instrument is no longer appropriate, hedge accounting will be discontinued.

F-9

PDC 1997-D LIMITEDPARTNERSHIP

(A West VirginiaLimited 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 thePartnership, which creates credit risk. The Managing General Partner minimizesthe credit risk in derivative instruments by entering into transactions withhigh-quality counterparties.

 

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. 

 

NewAccounting 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 $12,102 and a related liability of $30,949(using a 6% discount rate) and a cumulative effect of change in accountingprinciple on prior years of $18,847.

 (2)  Organization

ThePartnership was organized as a limited partnership on December 30, 1997 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 7.95 units of limitedpartner interests and 918.02895 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.

Inaccordance with the terms of the Partnership Agreement (the Agreement), theManaging General Partner manages all activities of the Partnership and acts asthe intermediary for substantially all Partnership transactions.

F-10

PDC 1997-D LIMITEDPARTNERSHIP

(A West VirginiaLimited Partnership)

Notes to FinancialStatements

(3)  Transactions with Managing GeneralPartner and Affiliates

Pursuantto the authorization contained in the Limited Partnership Agreement, PDCreceives fees for services rendered and reimbursement of certain expenses fromthe Partnership.  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 years ended December 31, 2004, 2003 and 2002.

              Years  Ended December31,                   

2004  

2003  

2002  

Lifting costs

$646,065

695,140

738,953

Tax return preparation

9,013

8,862

8,960

Direct administrative cost

4,337

4,171

4,739

 

(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

Managing

General

Partners

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(5)

80%

20%

Sale of Productive Properties(6)

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 Partnership isfunded 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 1997-D LIMITEDPARTNERSHIP

(A West VirginiaLimited Partnership)

Notes to FinancialStatements

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

(5) To theextent 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 $81,547, $69,885, and $39,783 in 2004, 2003,and 2002, respectively.

(6) In theevent of the sale or other disposition of a productive well, a lease upon whichsuch well is situated, or any equipment related to any such lease or well, theproceeds from such sale or disposition shall be allocated and credited to thePartners as oil and gas revenues are allocated.  The term "proceeds"above does not include revenues from a royalty, overriding royalty, leaseinterest reserved, or other promotional consideration received by thePartnership in connection with any sale or disposition, which revenues shall beallocated to the Investor Partners and the Managing General Partner in the samepercentages that oil and gas revenues are allocated.  No such sales haveoccurred.

(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 7.09 units ofpartnership interest for a total ownership of 42.17 units as of December 31, 2004 which represents a 4.55% 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

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 and options contracts.   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 policy prohibits the use of natural gas future andoption contracts for speculative purposes.

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

Commodity

Type

Quantity

Weighted 

Total

Fair

Gas-Mmbtu

Average

Contract

Market

Oil-Barrels

Price

Amount

Value

Total  Contracts as of December 31, 2004

Natural Gas

Purchase

4288

6.63

28,448

(1,632)

 Natural Gas

Floors

117,914

4.79

-    

13,513

Natural Gas

Ceilings

58,957

5.73

-    

(53,725)

F-12

PDC 1997-D LIMITED  PARTNERSHIP

(A West Virginia  Limited Partnership)

Notes to Financial  Statements

Contracts  maturing in 12 months following December 31, 2004 

Natural Gas

Purchase

4288

6.63

28,448

(1,632)

 Natural Gas

Floors

117,914

4.79

-    

13,513

Natural Gas

Ceilings

58,957

5.73

-    

(53,725)

Prior  Year Total Contracts as of December 31, 2003

Natural Gas

Sale

5,102

5.40

27,552

(3,821)

Natural Gas

Purchase

4,373

4.77

20,861

2,903

Natural Gas

Floors

81,635

4.12

-    

878 

Natural Gas

Ceilings

66,328

5.55

-    

(11,796)

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

(6) CostsRelating to Oil and Gas Activities

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

$   520,022 

   520,022 

520,022 

Intangible development costs

16,216,034 

16,216,034 

16,216,034 

Well equipment

3,383,987 

3,383,987 

3,383,987 

Impairment charge

(13,085,546)

(13,085,546)

(13,085,546)

Capitalized asset retirement cost

     23,127 

     23,127 

       -    

$ 7,057,624 

7,057,624 

 7,034,497 

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

(7)  Income Taxes

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 reporting purposes.  At December 31, 2004 and 2003, the income tax basis of the partnership's oiland gas properties was $913,540 and $1,183,998, respectively.

F-13

PDC 1997-D LIMITEDPARTNERSHIP

(A West VirginiaLimited Partnership)

Notes to FinancialStatements

(8)  SupplementalReserve Information (Unaudited)

Provedoil and gas reserves of the Partnership have been estimated by the ManagingGeneral Partner's petroleum engineers 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:

Gas (MCF)

2004

2003

2002

Beginning  of year

4,096,000 

4,396,000 

3,698,000 

Revisions  of previous estimates

118,000 

13,000 

1,065,000 

Production

(287,000)

(313,000)

(367,000)

End  of Year

3,927,000 

4,096,000 

4,396,000 

(9)  Standardized Measureof Discounted Future Net Cash Flows and Changes Therein Relating to Proved 

        Oiland Gas Reserves (Unaudited)

Summarized inthe 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

 $ 25,290,000 

 22,543,000 

18,026,000 

Future  estimated production costs

(9,804,000)

(9,580,000)

(7,926,000)

Future  estimated development costs

(144,000)

(144,000)

(144,000)

      Future net cash flows

15,342,000 

12,819,000 

9,956,000 

10%  annual discount for estimated timing of cash flows

(8,500,000)

(6,910,000)

(5,472,000)

Standardized  measure of discounted future

   estimated  net cash flows

 $   6,842,000 

    5,909,000 

4,484,000 

Thefollowing table summarizes the principal sources of change in the standardizedmeasure of discounted future estimated net cash flows:

Years Ended December 31,

2004

2003

2002

Sales  of oil and gas production, net of production costs

 $  (979,000)

    (813,000)

(345,000)

Net  changes in prices and production costs

3,132,000  

3,647,000 

4,268,000 

Revisions  of previous quantity estimates

370,000 

29,000 

1,353,000 

Accretion  of discount

(1,590,000)

(1,438,000)

(3,121,000)

$     933,000     

 1,425,000 

2,155,000 

F-14

PDC 1997-DLIMITEDPARTNERSHIP

(A West VirginiaLimited Partnership)

Notes to FinancialStatements

It is necessary to emphasize that the data presented should not beviewed as representing the expected cash flows from, or current value of,existing proved reserves since the computations are based on a large number ofestimates and arbitrary assumptions.  Reserve quantities cannot be measuredwith precision and their estimation requires many judgmental determinations andfrequent revisions.  The required projection of production and relatedexpenditures over time requires further estimates with respect to pipelineavailability, rates of demand and governmental control. Actual future pricesand costs are likely to be substantially different from the current prices andcosts utilized in the computation of reported amounts.  Any analysis or evaluationof the reported amounts should give specific recognition to the computationalmethods utilized and the limitations inherent therein.

F-15 |
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