jpCONFORMED COPY

SECURITIES ANDEXCHANGE COMMISSION

Washington, D.C.  20549

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

   THESECURITIES EXCHANGE ACT OF 1934

   Forthe fiscal year ended December 31, 2004

   CommissionFile Number  333-41977-08

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

PDC 1999-D LIMITEDPARTNERSHIP

(Exact name ofregistrant as specified in its charter)

| West Virginia

(State or other  jurisdiction of

incorporation or  organization) | 55-0768545

(I.R.S. Employer 

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

103 East Main Street, Bridgeport, West Virginia  26330                 

(Address ofprincipal executive offices)     (zip code)     

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

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

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

General and LimitedPartnership Interests

(Title of class)

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

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

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

There is no tradingmarket for the registrant's securities.

PART I

ITEM 1.  BUSINESS.

General

      PDC 1999-D LimitedPartnership ("the Partnership") is a limited partnership formed on December 31, 1999 pursuant to the West Virginia Uniform Limited Partnership Act. Petroleum Development Corporation ("PDC") serves as Managing GeneralPartner of the Partnership.

      Since thecommencement of operations on December 31, 1999, the Partnership has beenengaged in onshore, domestic gas exploration exclusively in the northernAppalachian and Michigan Basins and the Rocky Mountain Region. A total of 9limited partners contributed initial capital of $245,000 and a total of 841additional general partners contributed initial capital of $18,464,342 and PDC(Managing General Partner) contributed $4,069,282 in capital as a participantin accordance with contribution provisions of the Limited Partnership Agreement(the Agreement). During 2000 in accordance with the Partnership Agreement, allAdditional General Partners were converted to Limited Partners.

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

|                                                            | Allocation

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

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

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

Employees

      The Partnership hasno employees, however, PDC has approximately 120 employees which include astaff of geologists, petroleum engineers, landmen and accounting personnel whoadminister all of the Partnership's operations.

Plan of Operations

      The Partnershipparticipated in the drilling of 52 gross wells (41.12 net wells) and will continueto operate and produce its 52 gross productive wells. The Partnership does nothave unexpended 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 oil and natural gas have occurred and areexpected to continue.  The effects of such imports could adversely impact themarket for domestic oil and natural gas. All oil and natural gas is sold undercontracts based on market sensitive indexes that vary from month to month. Nofixed price contracts are in place. The Partnership sold oil and natural gas toseveral entities of which two customers accounted for 42.2% and 36.7% of thePartnership's total oil and natural gas sales for the year ended December 31,2004, 42.8% and 35.4% for the year ended December 31, 2003, and 39.7% and 35.5%for the year ended December 31, 2002.

2

 

 

Derivatives and Hedging Activities

     The Managing GeneralPartner, through its subsidiary Riley Natural Gas (RNG) has been in the gasmarketing business since 1986.  During that time period, the Managing GeneralPartner has utilized and continues to utilize commodity-based derivativeinstruments as hedges to manage a portion of the Partnership's exposure toprice volatility stemming from its natural gas production. These instrumentsconsist of CIG (Colorado Interstate Gas Index)-based contracts for Colorado production and costless collars and option contracts traded on the New YorkMercantile Exchange for Michigan and Appalachian production. The contractshedge committed and anticipated natural gas purchases and sales, generallyforecasted to occur within the next two year period. The Managing GeneralPartner does not hold natural gas futures or options for speculative purposesand permits utilization of hedges only if there is an underlying physicalposition.  See "Commodity Price Risk" under item 7A.

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

   

Competition

      The Partnershipcompetes in marketing its gas and oil with numerous companies and individuals,many of which have financial resources, staffs and facilities substantiallygreater than those of the Partnership or Petroleum Development Corporation. 

State Regulations

      State regulatoryauthorities have established rules and regulations requiring permits for welloperations, reclamation bonds and reports concerning operations.  States alsohave statutes and regulations concerning the spacing of wells, environmentalmatters and conservation, and have established regulations concerning theunitization and pooling of oil and gas properties and maximum rates ofproduction from oil and gas wells.  The Partnership believes it has complied inall material respects with applicable state regulations. The Partnership estimates it has spentapproximately $3,400, $4,700 and $6,000 in 2004, 2003 and 2002, respectively tocomply 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 GasRegulation.  Sale of natural gas by the Partnership is subject toregulation of production, transportation and pricing by governmental regulatoryagencies.  Generally, the regulatory agency in the state where a producing wellis located regulates production activities and, in addition, the transportationof gas sold intrastate.  The Federal Energy Regulatory Commission (FERC)regulates the operation and cost of interstate pipeline operators who transportgas.  Currently the price of gas to be sold by the Partnership is not regulatedby any state or federal agency.

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      ProposedRegulation.  Numerous proposals concerning energy are being considered bythe United States Congress, various state legislatures and regulatoryagencies.  The possible outcome and effect of these proposals cannot beaccurately predicted.

      Environmental andSafety 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 the partnership's drilling activity from December 31, 1999(date of inception) to December 31, 2004 The Partnership's wells drilled andproducing are located in the Rocky Mountain Region, Michigan and Pennsylvania. 

|                   Development  Wells                   |
|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
|      Gross Wells                                                                                                                                                          |         Net Wells                     |
| Productive                                                                                                                                                                                                                                 | Dry | Total | Productive | Dry | Total |
| 52                                                                                                                                                                                                                                         |  - | 52 | 41.12 |  -  | 41.12 |

      The Partnership hasnot participated in any exploratory wells. No additional drilling activity isplanned.

Production 

See "Management's Discussion and Analysis" on page6 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

     The table below shows thenumber of the Partnership's gross and net wells by state as of December 31, 2004.

|                    |  Natural Gas Wells |
|--------------------|-------------------------|
| Location           | Gross                   | Net |
| Colorado           | 20                      | 19.69 |
| Michigan           | 16                      | 5.48 |
| Pennsylvania       | 16                      | 15.95 |
|    Total | 52                      | 41.12 |

      A "productive well"is a well producing, or capable of producing, oil and/or gas in commercialquantities.  For purposes of the above table, a "gross well" is onein which the Partnership has a working interest and a "net well" is agross well multiplied by the Partnership working interest to which it isentitled under its drilling agreement.

 

Title to Properties

      The Partnership'sinterests in producing acreage are in the form of assigned direct interests inleases.  Such properties are subject to customary royalty interests generallycontracted for in connection with the acquisition of properties and could besubject to liens incident to operating agreements, liens for current taxes andother burdens.  The Partnership believes that none of these burdens materiallyinterfere with the use of such properties in the operation of the Partnership'sbusiness.

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      As is customary inthe oil and gas industry, little or no investigation of title is made at thetime of acquisition of undeveloped properties (other than a preliminary reviewof local mineral records).  Investigations are generally made, including inmost cases receiving a title opinion of legal counsel, before commencement ofdrilling operations.  A thorough examination of title has been made with respectto all of the Partnership's producing properties and the Partnership believesthat it has generally satisfactory title to such properties.

ITEM 3.  LEGAL PROCEEDINGS.

      The Managing GeneralPartner as driller/operator is not party to any legal action that wouldmaterially affect the Managing General Partner's or Partnership's operations orfinancial statements.

 

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

      NON-APPLICABLE.  

PART II

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

      At December 31, 1999,PDC 1999-D Limited Partnership had one Managing General Partner, 9 LimitedPartners who fully paid for 12.25 units at $20,000 per unit of limitedpartnership interests and a total of 841 Additional General Partners who fullypaid for 923.2171 units at $20,000 per unit of additional general partnershipinterests. During 2000 in accordance with the Partnership Agreement, allAdditional General Partners were converted to Limited Partners. At December 31, 2004, the Partnership had one Managing General Partner and 850 LimitedPartners who paid for 935.4671 units at $20,000 per unit. No established publictrading market exists for the interests.

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

ITEM 6.  SELECTED FINANCIAL DATA.

      The selectedfinancial data presented below has been derived from audited financialstatements of the Partnership appearing elsewhere herein.

|                                                     |          Years  Ended December 31,        |
|-----------------------------------------------------|---------------------------------------------------------------------------------------------------------------------------|
|                                                     | 2004                                                                                                                      | 2003 |  2002 |
| Oil and Gas Sales                                   | $3,166,473                                                                                                           | $2,885,528  | 2,291,816  |
| Costs and Expenses                                  | 1,550,553                                                                                                            | 2,177,372  | 1,791,242  |
| Impairment                                          |             -                                                      | 581,815 |                        - |
| Cumulative effect of change in accounting principle |           -                                                                  | (7,024) |                       -       |
| Net Income                                          | 1,617,038                                                                                                            | 702,334  | 502,912  |
| Allocation of Net Income:                           |                                                                                                                           |  |  |
| Managing General Partner                            | 323,408                                                                                                              | 140,467  | 100,582  |
| Limited and Additional General Partners             | 1,293,630                                                                                                            | 561,867  | 402,330  |
| Per Limited and Additional 

General Partner Unit   | 1,383                                                                                                                | 601  | 430  |
| Total Assets                                        | 12,002,827                                                                                                           | 12,596,501  | 14,167,055  |
| Cash Distributions:                                 |                                                                                                                           |  |  |
| Managing General Partner                            | 449,635                                                                                                              | 454,690  | 360,823  |
| Limited and Additional                              |                                                                                                                           |  |  |
|  General Partners                              | 1,798,541                                                                                                            | 1,818,762  | 1,443,290  |

 

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

         ANDRESULTS OF OPERATIONS.

Liquidity and Capital Resources

      The Partnership wasfunded on December 31, 1999 with initial Limited and Additional General Partnercontributions of $18,709,342 and the Managing General Partner's cashcontribution $4,069,282 in accordance with the Agreement. After payment ofsyndication costs of $1,964,481 and a one-time management fee to the ManagingGeneral Partner of $467,734, the Partnership had available cash of $20,346,409for Partnership activities.

      The Partnership beganexploration and development activities subsequent to the funding of thePartnership and completed these activities by December 31, 2001. Fifty-two wells have been drilled, all of which have been completed as producers. Noadditional wells will be drilled.

      The Partnership hadworking capital at December 31, 2004 of $540,017.

      Operationsare expected to be conducted with available funds and revenues generated fromoil and gas activities.  No bank borrowings are anticipated.

Resultsof Operations

2004 Results Compared to 2003

**     **Oil and gas sales for the year ended December 31, 2004 were $3,166,473 compared to $2,885,528 for the year ended December 31, 2003.  For the year ended December 31, 2004, the Partnership sold 558,652 Mcfof gas and 7,198 barrels of oil at average sales prices of $5.17 and $38.79,respectively.  This compared with 623,723 Mcf of gas and 10,021 barrels of oilat average sales prices of $4.15 and $29.44, respectively for the year ended December 31, 2003. Lifting cost per Mcfe in 2004 amounted to $1.20 as compared to $0.97for 2003. This increase is partially attributed to the increase in severanceand property taxes. The fixed costs of operations and well maintenance areallocated to lower production volumes, therefore increasing the lifting costper Mcfe. Depreciation, depletion andamortization decreased from $908,183 for the year ended December 31, 2003 to $810,898 for the year ended December 31, 2004 as a result of lower volumes ofnatural gas and oil sold. Cash distributions to the partners amounted to$2,248,176 in 2004.

2003 Results Compared to 2002

     Oiland gas sales for the year ended December 31, 2003 were $2,885,528 compared to $2,291,816 for the year ended December 31, 2002.  For the year ended December 31, 2003, the Partnership sold 623,723 Mcf of gas and 10,021 barrels ofoil at average sales prices of $4.15 and $29.44, respectively.  This comparedwith 873,829 Mcf of gas and 15,221 barrels of oil sold at average sales pricesof $2.22 and $23.10, respectively for the year ended December 31, 2002. Lifting cost per Mcfe in 2003 amounted to $.97 as compared to $0.60 for 2002. Thisincrease is partially attributed to the increase in severance and propertytaxes. The fixed costs of operations and well maintenance are allocated tolower production volumes, therefore increasing the lifting cost per Mcfe. Depreciation, depletion and amortization decreasedfrom $1,193,269 for the year ended December 31, 2002 to $908,183 for the year ended December 31, 2003 as a result of lower volumes of natural gas and oilsold. Cash distributions to the partners amounted to $2,273,452 in 2003.

     The Partnership's revenuesfrom oil and natural gas sales will be affected by changes in prices.  As aresult of changes in federal regulations, gas prices are highly dependent onthe balance between supply and demand. The Partnership's gas sales prices aresubject to increase and decrease based on various market sensitive indices.

 

 

 

 

 

 

 

6

 

Critical Accounting 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. Inapplying those policies, our management uses its judgment to determine theappropriate assumptions to be used in the determination of certain estimates.Those estimates are based on our historical experience, our observance oftrends in the industry, and information available from other outside sources,as appropriate. For a more detailed discussion on the application of these andother accounting policies, see "Note 1 - Summary of significant accountingpolicies" in our financial statements and related notes. The Partnership'scritical accounting policies and estimates are as follows:

Revenue Recognition

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

7

Use of Estimates inLong-Lived Asset Impairment Testing

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

Oil and Gas Properties 

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

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

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

Unproved 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.

New Accounting Standards

      In June 2001, theFinancial Accounting Standard Board issued FASB No. 143, "Accounting forAsset Retirement Obligations" that requires entities to record the fairvalue of a liability for an asset retirement obligation in the period in whichit is incurred and a corresponding increase in the carrying amount of therelated long-lived asset. This statement is effective for fiscal yearsbeginning after June 15, 2002. The Partnership adopted FASB No. 143 on January 1, 2003 and recorded a net asset of $11,859 and a related liability of $18,883(using a 6% discount rate) and a cumulative effect of change in accountingprinciple on prior years of $7,024.

Item 7A.  Quantitative and QualitativeDisclosure About Market Risk.

Market-Sensitive Instruments and Risk Management

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

Commodity Price Risk

        TheManaging General Partner utilizes commodity-based derivative instruments ashedges to manage a portion of its exposure to price risk from its oil andnatural gas sales.  These instruments consist of NYMEX-traded natural gasfutures contracts and option contracts for Appalachian and Michigan productionand CIG-based contracts traded 

8

byJP Morgan for Colorado production.  These hedging arrangements have the effectof locking in for specified periods (at predetermined prices or ranges ofprices) the prices the Managing General Partner will receive for the volume towhich 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 andoptions 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 | 3,647       | 6.63     | 24,196                    | (1,388)  |
|  Natural Gas                                            | Floors   | 215,156     | 4.27     | -     | 31,315   |
| Natural Gas                                                  | Ceilings | 107,578     | 5.36     | -     | (92,146) |
| Oil                                                          | Floors   | 3,850       | 32.30    | 124,344                   | 3,280    |
| Oil                                                          | Ceilings | 1,925       | 40.00    | 76,993                    | (10,412) |
|                                                              |          |             |          |                           |          |
| Contracts  maturing in 12 months following December 31, 2004 |
| Natural Gas                                                  | Purchase | 3,647       | 6.63     | 24,196                    | (1,388)  |
| Natural Gas                                                  | Floors   | 215,156     | 4.27     | -     | 31,315   |
| Natural Gas                                                  | Ceilings | 107,578     | 5.36     | -     | (92,146) |
| Oil                                                          | Floors   | 3,850       | 32.30    | 124,344                   | 3,280    |
| Oil                                                          | Ceilings | 1,925       | 40.00    | 76,993                    | (10,412) |
| Prior  year Total Contracts as of December 31, 2003          |
| Natural Gas                                                  | Sale     | 4,372       | 5.40     | 23,607                    | (3,274)  |
| Natural Gas                                                  | Purchase | 3,747       | 4.77     | 17,874                    | 2,487    |
| Natural Gas                                                  | Floors   | 171,872     | 3.62     | -     | 752      |
| Natural Gas                                                  | Ceilings | 158,757     | 5.10     | -     | (11,660) |

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.  The average NYMEX closing price for oil for the years 2004,  2003 and2002 was $41.44 per bbl, $30.98 per bbl and $26.98 per bbl. The average CIGclosing price for natural gas for the years 2004, 2003 and 2002 was $5.17 perMmbtu, $4.04 per Mmbtu and $1.97 per Mmbtu.  Future near-term gas prices willbe affected by various supply and demand factors such as weather, governmentand environmental regulations 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 thisItem is set forth herein in a separate section of this Report, beginning onPage F-1.

 

 

9

ITEM 9.  CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND

         FINANCIALDISCLOSURE.

         NONE.

 ITEM 9A. CONTROLS AND PROCEDURES

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

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.

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

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

ITEM 11.  EXECUTIVE COMPENSATION.

         NON-APPLICABLE.

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

         NON-APPLICABLE.

 

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.

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

|                            | 2004           | 2003           | 2002          |   |   |
|----------------------------|----------------|----------------|---------------|--------|--------|
| Lifting costs              | $719,166  | $666,461  | 575,517  |        |        |
| Tax return preparation     | 9,530     | 9,530     | 11,675   |        |        |
| Direct administrative cost | 3,291     | 3,827     | 4,595    |        |        |
|                            |                |                |               |        |        |  |

ITEM 14.  PRINCIPAL ACCOUNTANT FEES ANDSERVICES 

     For the years endedDecember 31, 2004 and 2003 the Partnership paid KPMG LLP $6,457 and $6,269 forprofessional services for the audit of the Partnership's financial statementsin its form 10-K and review of financial statements included in thePartnership's Form 10-Qs.   

                                                                                          10

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 Audit Committeemember. 

 

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

 

                (1) Financial Statements

See Index toFinancial Statements on F-2

              (2) Financial Statement Schedules

See Index toFinancial Statements on page F-2.  All financial statement schedules areomitted 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 2, 1999, of PDC 2000 Drilling Program, filed with the SEC on June 4, 1999).       |
|------|---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| 14   | Code  of Ethics of Petroleum Development Corporation (incorporated by reference to  the posted code on the web site of Petroleum Development Corporation at www.petd.com).                                                                        |
| 31.1 | Rule  13a-14(a)/15d-14(c) Certification of Chief Executive Officer of Petroleum  Development Corporation, the managing general partner of the Limited  Partnership.                                                                               |
| 31.2 | Rule 13a-14(a)/15d-14(c)  Certification of Chief Financial Officer of Petroleum Development  Corporation, the managing general partner of the Limited Partnership.                                                                                |
| 32.1 | Title 18  U.S.C. Section 1350 (Section 906 of Sarbanes-Oxley Act of 2002)  Certifications by Chief Executive Officer and Chief Financial Officer of  Petroleum Development Corporation, the Managing General Partner of the  Limited Partnership. |

11

CONFORMED COPY

SIGNATURES

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

|  
PDC 1999-D Limited Partnership

By its Managing General Partner

Petroleum Development Corporation

 
By /s/ Steven R. Williams      

   Steven R. Williams, Chairman

April 19, 2005

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

Signature

Title

Date

/s/ Steven R. Williams

    Steven R. Williams

Chairman, Chief Executive Officer and

 Director 

April 19, 2005

/s/ Darwin L. Stump 

    Darwin L. Stump

Chief Financial Officer and Treasurer

(principal financial and accounting officer)

April 19, 2005

 

/s/ Thomas E. Riley 

    Thomas E. Riley

President and Director

April 19, 2005

/s/ Donald B. Nestor

    Donald B. Nestor

Director

April 19, 2005

/s/ Vincent F. D'Annunzio

    Vincent F. D'Annunzio

Director

April 19, 2005

12

PDC 1999-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 1999-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 1999-D Limited Partnership:

We have audited the financial statements of PDC 1999-DLimited Partnership (a West Virginia limited partnership) as of December 31, 2004 and 2003, and the related statements of operations, partners' equity andcomprehensive income (loss), and cash flows for each of the years in thethree-year period ended December 31, 2004.  These financial statements are theresponsibility of the Partnership's management.  Our responsibility is toexpress an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standardsof the Public Company Accounting Oversight Board (United States).  Thosestandards require that we plan and perform the audit to obtain reasonableassurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amountsand disclosures in the financial statements.  An audit also includes assessingthe accounting principles used and significant estimates made by management, aswell as evaluating the overall financial statement presentation.  We believethat our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred toabove present fairly, in all material respects, the financial position of PDC1999-D Limited Partnership as of December 31, 2004 and 2003 and the results ofits operations and its cash flows for each of the years in the three-yearperiod ended December 31, 2004 in conformity with U.S. generally acceptedaccounting principles.

As discussed in note 1 to the financial statements, thePartnership adopted the provisions of Statement of Financial AccountingStandards No. 143, "Accounting for Asset Retirement Obligations", in2003. 

KPMG LLP

Pittsburgh, Pennsylvania

April 19, 2005

F-3

PDC 1999-D LIMITEDPARTNERSHIP

(A West VirginiaLimited Partnership)

Balance Sheets

December 31, 2004 and 2003

     Assets

2004

2003

Current assets:

     Cash

$   4,878 

   3,813 

     Accounts  receivable - oil and gas revenues

   664,306 

   448,147 

          Total  current assets

 669,184 

 451,960 

Oil and gas  properties, successful

  efforts  method (note 3 and 6):

       Oil  and gas properties

17,641,966 

17,641,966 

       Less  accumulated depreciation, 

        depletion, and  amortization

   6,308,323 

   5,497,425 

11,333,643 

12,144,541 

$12,002,827 

12,596,501 

     Current  Liabilities and Partners' Equity

Current  liabilities:

     Accrued  expenses

$   129,167 

    35,258 

          Total  current liabilities

129,167 

35,258 

Asset retirement  obligation

21,384 

20,173 

Partners' equity

11,852,276 

12,541,070 

$12,002,827 

12,596,501 

See accompanying notes to financial statements.

F-4

PDC 1999-D LIMITEDPARTNERSHIP

(A West VirginiaLimited Partnership)

Statements ofOperations

Years Ended December 31, 2004, 2003 and 2002 

    2004    

    2003    

    2002    

 

 

Revenues:

     Sales of oil and gas

$3,166,473 

2,885,528 

2,291,816 

     Interest income

    1,119 

    1,202 

    2,338 

3,167,591 

2,886,730 

2,294,154 

Expenses (note 3):

     Lifting cost

719,166 

666,461 

575,517 

     Independent audit fee

6,457 

6,269 

6,086 

     Tax return preparation

9,530 

9,530 

11,675 

     Direct administrative  cost

4,502 

5,114 

4,595 

     Independent engineering cost

-    

-    

100 

     Loss on impairment of oil  

      and gas properties

                       -

  581,815 

  -    

     Depreciation, depletion

      and amortization

  810,898 

  908,183 

  1,193,269 

1,550,553 

2,177,372 

1,791,242 

Income before cumulative effect of 

    change in accounting principle

    1,617,038 

    709,358 

    502,912 

Cumulative effect of change in accounting 

   principle

          -    

     (7,024)

          -    

  Net income 

$  1,617,038 

  702,334 

  502,912 

 

 

  Net income per limited and additional 

    general partner unit before  cumulative effect of 

    change in accounting principle

  $       1,383 

         607 

         430 

 

 

 

Cumulative effect of change in accounting 

   Principle

        -    

      (6)

        -    

 

 

 

 

 

Net income per limited and additional 

   general partner unit

  $       1,383 

 

       601 

       430 

See accompanying notes to financial statements.

F-5

PDC 1999-D LIMITED PARTNERSHIP

(A West VirginiaLimited Partnership)

Statements ofPartners' Equity

And ComprehensiveIncome (Loss)

Years Ended December 31, 2004, 2003 and 2002

Limited and

Additional

General

Partners

  Managing 

General 

Partner

Accumulated

Other

Comprehensive
Income  (Loss)
    Total 

 

 

 

Balance December 31, 2001

$12,340,066 

3,085,018 

     -    

15,425,084 

 

 

 

Distribution to  partners

(1,443,290)

(360,823)

(1,804,113)

Comprehensive  income:

 

 

 

 Net income

402,330 

100,582 

 

502,912 

Change in fair  value of outstanding 

 hedging  positions

 

  (12,302)

 

Reclassification  adjustment for settled 

 contracts  included in net income (loss)

 

        -    

 

Other  comprehensive income (loss)

 

(12,302)

    (12,302)

Comprehensive  income

           

          

           

    490,610 

 

 

 

Balance December 31, 2002

11,299,106 

2,824,777 

   (12,302)

14,111,581 

 

 

 

Distribution to  partners

(1,818,762)

(454,690)

(2,273,452)

Comprehensive  income:

 

 

 

 Net income

561,867 

140,467 

 

702,334 

Change in fair  value of outstanding 

 hedging  positions

 

  3,222 

 

Reclassification  adjustment for settled 

 contracts  included in net income (loss)

 

      (2,615)

 

Other  comprehensive income (loss)

 

607 

    607 

Comprehensive  income

                   

                 

                  

    702,941 

 

 

 

Balance December 31, 2003

10,042,211 

2,510,554 

   (11,695)

12,541,070 

 

 

 

 

 

 

Distribution to  partners

(1,798,541)

(449,635)

(2,248,176)

Comprehensive  income:

 

 

 

 Net income

1,293,630 

323,408 

 

1,617,038 

Change in fair  value of outstanding 

 hedging  positions

 

         (156,346) 

 

Reclassification  adjustment for settled 

 contracts  included in net income (loss)

 

    98,690

 

Other  comprehensive income (loss)

 

(57,656) 

 (57,656) 

Comprehensive  income

                  

                  

              

    1,559,382

 

 

 

Balance December 31, 2004

$9,537,300 

2,384,327 

  (69,351)

11,852,276 

See accompanying notes to financial statements.

F-6

PDC 1999-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

$   1,617,038 

   702,334 

   502,912 

     Adjustments  to reconcile net income 

     to net  cash provided from  operating activities:

     Depreciation,  depletion and amortization

810,898 

908,183 

1,193,269 

     Cumulative effect of change in  accounting principle

-    

7,024 

-    

     Accretion of asset retirement  obligation

1,211

1,290 

-    

     Loss on  impairment of oil and gas properties

-    

581,815 

-    

     Changes  in operating assets and liabilities:

     (Increase)  decrease in accounts 

        receivable  - oil and gas revenues

  (182,316)

  74,353 

  99,225 

     Increase  (decrease) in accrued 

        expenses

       2,410

       (409)

       (222)

 

 

 

       Net  cash provided from

       operating  activities

  2,249,241 

  2,274,590 

  1,795,184 

Cash flows used by financing  activities:

     Distributions  to partners

(2,248,176)

(2,273,452)

(1,804,113)

       Net  cash used by financing activities

(2,248,176)

(2,273,452)

(1,804,113)

 

 

 

Net increase (decrease) in cash

1,065 

1,138 

(8,929)

Cash at beginning of period

    3,813 

    2,675 

    11,604 

Cash at end of period

$     4,878 

     3,813 

     2,675 

See accompanyingnotes to financial statements.

F-7

PDC 1999-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

The financialstatements include only those assets, liabilities and results of operations ofthe partners which relate to the business of PDC 1999-D Limited Partnership(the Partnership). The statements do not include any assets, liabilities, revenuesor expenses attributable to any of the partners' other activities.  PetroleumDevelopment Corporation ("PDC") serves as Managing General Partner ofthe Partnership.

Oil and GasProperties

The Partnershipfollows the successful efforts method of accounting for the cost of exploringfor and developing oil and gas reserves.  Under this method, costs ofdevelopment wells, including equipment and intangible drilling costs related toboth producing wells and developmental dry holes, and successful exploratorywells are capitalized and amortized on an annual basis to operations by theunits-of-production method using estimated proved developed reserves determinedat December 31, 2004, 2003, and 2002 by the Managing General Partner'spetroleum engineers.  If a determination is made that an exploratory well hasnot discovered economically producible reserves, then its costs are expensed asdry hole costs.  

The Partnershipassesses impairment of capitalized costs of proved oil and gas properties bycomparing net capitalized costs to undiscounted future net cash flows on afield-by-field basis using expected prices. Prices utilized in each year'scalculation for measurement purposes and expected costs are held constantthroughout the estimated life of the properties. If net capitalized costsexceed undiscounted future net cash flows, the measurement of impairment isbased on estimated fair value which would consider future discounted cashflows. During 2003 the loss on impairment of oil and gas properties as reflectedin the Statement of Operations amounted to $581,815.

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 reflected in the wellhead price.

.                                                                              F-8

PDC 1999-D LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

                                                                   Notesto Financial Statements

Sales of oil arerecognized when persuasive evidence of a sales arrangement exists, the oil isverified as produced and is delivered in a stock tank, collection of revenuefrom the sale is reasonably assured and the sales price is determinable.  ThePartnership is currently able to sell all the oil that it can produce underexisting sales contracts with petroleum refiners and marketers.  ThePartnership does not refine any of its oil production.  The Partnership's crudeoil production is sold to purchasers at or near the Partnership's wells undershort-term purchase contracts at prices and in accordance with arrangementsthat are customary in the oil industry. 

 

The Partnership soldoil and natural gas to several entities of which two customers accounted for42.2% and 36.7% of the Partnership's total oil and natural gas sales for theyear ended December 31, 2004, 42.8% and 35.4% for the year ended December 31,2003, and 39.7% and 35.5% for the year ended December 31, 2002.

 

Income Taxes

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

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

Derivative FinancialInstruments

The Managing GeneralPartner utilizes commodity based derivative instruments as hedges to manage aportion of the Partnership's exposure to price volatility stemming from naturalgas and oil production. These instruments consist of costless collars andoption contracts traded on the New York Mercantile Exchange and on the CIG(Colorado Interstate Gas Index).  The costless collars and option contractshedge committed and anticipated natural gas sales generally forecasted to occurwithin a 24 month period. The Partnership does not hold or issue derivativesfor trading or speculative purposes. 

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

Changes in fairvalue of a derivative that is highly effective and that is designated andqualifies as a cash-flow hedge are recorded in accumulated other comprehensiveincome (loss), until earnings are affected by the variability in cash flows ofthe designated hedged item. Changes in the fair value of non-hedgingderivatives are reported in current-period earnings. The Partnershipdiscontinues hedge accounting prospectively when it is determined that thederivative is no longer effective in offsetting changes in the cash flows ofthe hedged item, the derivative expires or is sold, terminated, or exercised. Additionally, if the derivative is dedesignated as a hedging instrument,because it is probable that a forecasted transaction will not occur, or thePartnership determines that designation of the derivative as a hedginginstrument is no longer appropriate, hedge accounting will be discontinued.

F-9

 

PDC 1999-D LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Notes to Financial Statements

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

 

Use of Estimates

The Partnership hasmade a number of estimates and assumptions relating to the reporting of assetsand liabilities and revenues and expenses and the disclosure of contingentassets and liabilities to prepare these financial statements in conformity withgenerally accepted accounting principles.  Actual results could differ from thoseestimates. Estimates which are particularly significant to the financialstatements include estimates of oil and gas reserves and future cash flows fromoil and gas properties which are used in assessing impairment of long-livedassets.

New AccountingStandards

In June 2001, theFinancial Accounting Standard Board issued FASB No. 143, "Accounting forAsset Retirement Obligations" that requires entities to record the fairvalue of a liability for an asset retirement obligation in the period in which itis incurred 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 $11,859 and a related liability of $18,883 (using a 6% discountrate) and a cumulative effect of change in accounting principle on prior yearsof $7,024.

 (2)  Organization

The Partnership wasorganized as a limited partnership on December 31, 1999 in accordance with the laws of the State of West Virginia for the purpose of engaging in the drilling,completion and operation of oil and gas development and exploratory wells inthe Northern Appalachian, Michigan and Rocky Mountain Regions.

Purchasers ofpartnership units subscribed to and fully paid for 12.25 units of limitedpartner interests and 923.2171 units of additional general partner interests at$20,000 per unit (Investor Partners).  Petroleum Development Corporation hasbeen designated the Managing General Partner of the Partnership. Althoughcosts, revenues and cash distributions allocable to the limited and additionalgeneral partners are shared pro rata based upon the amount of theirsubscriptions, including the Managing General Partner to the extent of itscapital contributions, there are significant differences in the federal incometax effects and liability associated with these different types of units in thePartnership.

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

In accordance with the terms of theLimited Partnership Agreement (the Agreement), the Managing General Partnermanages all activities of the Partnership and acts as the intermediary forsubstantially all Partnership transactions.

F-10

PDC 1999-D LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Notes to Financial Statements

(3)  Transactions with Managing GeneralPartner and Affiliates

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

                                                                                                 

 

2004

2003  

2002          

Lifting costs

$719,166

$666,461

$575,517

 
Tax return preparation

9,530

9,530

11,675

 
Direct  administrative cost

3,291

3,827

4,595

 
(4)  Allocation

The following tablesummarizes the participation of the Managing General Partner and the InvestorPartners, taking account of the Managing General Partner's capital contributionequal to a minimum of 20% of the initial operating capital, in the costs andrevenues of the Partnership.

** **

  Investor

Partners(5)(6)

Managing

General

Partner(5)(6)

** **

** **

** **

Partnership Costs

** **

** **

Broker-dealer Commissions and Expenses(1)

100%

0%

Management Fee(2)

100%

0%

Lease Costs

0%

100%

Tangible Equipment

0%

100%

Intangible Drilling and Development Costs

100%

0%

Total Drilling and Completion Costs

80%

20%

Operating Costs(3)

80%

20%

Direct Costs(4)

80%

20%

Administrative Costs

0%

100%

** **

** **

** **

Partnership Revenues

** **

** **

Sale of Oil and Gas Production

80%

20%

Sale of Productive Properties

80%

20%

Sale of Equipment

0%

100%

Sale of Undeveloped Leases

80%

20%

Interest Income

80%

20%

                    

(1)     Organization andoffering costs, net of the dealer manager commissions, discounts, due diligence           expenses, and wholesaling fees of the Partnership were paid by theManaging General Partner and           not from Partnership funds.  Inaddition, organization and offering costs in excess of 10-1/2% of             Subscriptions,if any, were paid by the Managing General Partner, without recourse to thePartnership.

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

      

F-11

PDC 1999-D LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Notes to Financial Statements

(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 their direct costs incurred by the Managing General Partner on behalf ofthe Partnership.

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

(6)   Theallocation of profits, losses and cash distributions of the Managing GeneralPartner might be increased, and the allocation of profits, losses, and cashdistributions of the Investor Partners might be decreased in the event that theManaging General Partner were to invest more than the Managing GeneralPartner's minimum required Capital Contribution to cover tangible equipment andlease costs. The Managing General Partner will pay for the Partnership's shareof all Leases and tangible well equipment. The entire Capital Contribution of theInvestor Partners, after payment of brokerage commissions, due diligencereimbursement, and the Management Fee, was utilized to pay for intangibledrilling costs. In the event that the Intangible Drilling Costs exceed thefunds of the Investor Partners available for payment of Intangible DrillingCosts (herein "excess IDC"), a portion of the Capital Contribution ofthe Managing 

               General Partner may be used to pay such excess IDC. If the cost of Leases andtangible well equipment were to exceed the Managing General Partner's CapitalContribution of 21-3/4% of the aggregate Capital Contribution of the InvestorPartners, then the Managing General Partner will increase its CapitalContribution 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)   In accordance with the repurchaseprovision of the partnership prospectus, PDC may repurchase units from theinvestor partners which is entirely voluntary on the part of the partners.  During2004 PDC purchased 1.75 units of partnership interest for a total ownership of 7.85units as of December 31, 2004 which represents a 0.84% ownership of theoriginal Investor Partners share of limited and additional general partnershipunits.  Therefore, costs and revenues and distributions for these purchasedunits are allocated to PDC in accordance with the Investor Partners allocationpercentages disclosed in this table.

(5)  Derivative Financial Instruments

The Managing General Partner utilizescommodity-based derivative instruments as hedges to manage a portion of itsexposure to price risk from its oil and natural gas sales.  These instrumentsconsist of NYMEX traded natural gas futures contracts and option contracts forAppalachian and Michigan production and CIG-based contracts traded by JP Morganfor Colorado production.  These hedging arrangements have the effect of lockingin for specified periods (at predetermined prices or ranges of prices) theprices the Managing General Partner will receive for the volume to which thehedge relates.  As a result, while these hedging arrangements are structured toreduce the Partnership's exposure to changes in price associated with thehedged commodity, they also limit the benefit the Partnership might otherwisehave received from price changes associated with the hedged commodity.  The Partnership'spolicy prohibits the use of natural gasfuture and option contracts for speculative purposes.

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

F-12

PDC 1999-D LIMITEDPARTNERSHIP

(A West VirginiaLimited Partnership)

Notes to FinancialStatements

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

3,647

6.63

24,196

(1,388)

 Natural Gas

Floors

215,156

4.27

-    

31,315

Natural Gas

Ceilings

107,578

5.36

-    

(92,146)

Oil

Floors 

3,850

32.30

124,344

3,280

Oil

Ceilings

1,925

40.00

76,993

(10,412)

Contracts  maturing in 12 months following December 31, 2004 

Natural Gas

Purchase

3,647

6.63

24,196

(1,388)

Natural Gas

Floors

215,156

4.27

-    

31,315

Natural Gas

Ceilings

107,578

5.36

-    

(92,146)

Oil

Floors

3,850

32.30

124,344

3,280

Oil

Ceilings

1,925

40.00

76,993

(10,412)

Prior  year Total Contracts as of December 31, 2003

Natural Gas

Sale

4,372

5.40

23,607

(3,274)

Natural Gas

Purchase

3,747

4.77

17,874

2,487

Natural Gas

Floors

171,872

3.62

-    

752

Natural Gas

Ceilings

158,757

5.10

-    

(11,660)

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

(6)  Costs Relating to Oil and GasActivities

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

               December  31,               

2004

2003

2002

Lease acquisition costs

$   846,270 

   846,270 

846,270 

Intangible development costs

16,261,127 

16,261,127 

16,261,127 

Impairment charge

(2,700,298)

(2,700,298)

(2,118,483)

Capitalized asset retirement cost

15,855 

15,855 

            -

Well equipment

          3,219,012 

          3,219,012 

3,219,012 

$ 17,641,966 

 17,641,966 

 18,207,926 

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

F-13

PDC 1999-D LIMITEDPARTNERSHIP

(A West VirginiaLimited Partnership)

Notes to FinancialStatements

(7)  Income Taxes

As a result of thedifferences in the treatment of certain items for income tax purposes asopposed to financial reporting purposes, primarily depreciation, depletion andamortization of oil and gas properties and the recognition of intangibledrilling costs as an expense or capital item, the income tax basis of oil andgas properties differs from the basis used for financial reporting purposes. At December 31, 2004 and 2003, the income tax basis of the partnership's oil andgas properties was $1,593,136 and $1,879,693, respectively.

(8)  Supplemental Reserve Information(unaudited)

Proved oil and gasreserves of the Partnership have been estimated by the Managing GeneralPartners petroleum engineers at December 31, 2004, 2003 and 2002.   These reserves have been prepared in compliance with the Securities and ExchangeCommission rules based on year end prices. A copy of the reserve report hasbeen made available to all partners.  All of the partnership's reserves areproved developed. An analysis of the change in estimated quantities of proveddeveloped oil and gas reserves is shown below:

Oil (Bbls)

2004

2003

2002

Proved  developed reserves:

Beginning  of year

171,000

186,000 

168,000 

Revisions  of previous estimates

(10,000)

(5,000)

33,000 

Production

(7,000)

(10,000)

(15,000)

End  of year

154,000 

171,000 

186,000 

Gas (MCF)

2004

2003

2002

Proved  developed reserves:

Beginning  of year

9,429,000 

10,623,000 

12,125,000 

Revisions  of previous estimates

(776,000)

(570,000)

(628,000)

Production

(559,000)

(624,000)

(874,000)

End  of year

8,094,000 

9,429,000 

10,623,000 

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

        and 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

$ 54,164,000 

 55,761,000 

42,644,000 

Future  estimated production costs

(16,389,000)

(13,544,000)

(10,300,000)

Future  estimated development costs

(1,124,000)

(1,124,000)

(1,124,000)

   Future  net cash flows

36,651,000 

41,093,000 

31,220,000 

10%  annual discount for estimated timing of cash flows

(18,237,000)

(22,568,000)

(16,779,000)

Standardized  measure of discounted future

   estimated  net cash flows

$18,414,000 

18,525,000 

14,441,000 

F-14

PDC 1999-D LIMITEDPARTNERSHIP

(A West VirginiaLimited Partnership)

                                                                 Notes to Financial Statements

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

  Years Ended December 31, 

2004

2003

2002

 
Sales  of oil and gas production, net of production costs

$(2,447,000)

 (2,219,000)

(1,716,000)

 
Net  changes in prices and production costs

1,290,000 

13,603,000 

14,791,000 

 
Extensions,  discoveries, and improved recovery,     less related cost

  -    

  -    

  -    

 
Revisions  of previous quantity estimates

(3,285,000)

(1,512,000)

(379,000)

 
Accretion  of discount

4,331,000

(5,789,000)

(7,063,000)

 
 $(111,000)

 4,083,000 

 5,633,000 

 
 

 

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

F-15 |
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