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 fiscal yearended December 31, 2004

   Commission File Number  033-63635-04

 

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

PDC 1996-D LIMITED PARTNERSHIP

(Exact name ofregistrant as specified in its charter)

| West Virginia                                                     | 55-0751154                             |
|-------------------------------------------------------------------|----------------------------------------|
| (State or other jurisdiction of  

incorporation or organization) | (I.R.S. Employer 

Identification No.) |

103 East Main Street, Bridgeport, West Virginia 26330

Address of principalexecutive offices) (zip code)

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

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

SECURITIES REGISTEREDPURSUANT TO SECTION 12(g) OF THE ACT:

General andLimited Partnership Interests

(Title of class)

Indicate by check mark whetherthe registrant (1) has filed all reports required to be filed by Section 13 or15(d) of the Securities Exchange Act of 1934 during the preceding 12 months and(2) has been subject to such filing requirements for the past 90days.   Yes  X    No     

 

Indicate by check mark ifdisclosure of delinquent filers pursuant to Item 405 of Regulation S-K is notcontained herein, and will be contained, to the best of registrant's knowledge,in definitive proxy or information statements incorporated by reference in PartIII of this Form 10-K or any amendment to this Form 10-K. [ ]

Indicateby check mark whether the registrant is an accelerated filer (as definition inRule 12b-2 of the Exchange Act). Yes   No X 

Thereis no trading market for the registrant's securities.

PART I

 

ITEM 1. BUSINESS.

General

     PDC 1996-D Limited Partnership ("thePartnership") is a limited partnership formed on December 31, 1996 pursuant to the West Virginia Uniform Limited Partnership Act. PetroleumDevelopment Corporation ("PDC") serves as Managing General Partner ofthe Partnership.

     Since the commencement of operations on December 31, 1996, the Partnership has been engaged in onshore, domestic gas explorationexclusively in the Northern Appalachian and Michigan Basins. A total of 9limited partners contributed initial capital of $324,250; a total of 921additional general partners contributed initial capital of $14,977,476; and PDC(Managing General Partner) contributed $3,328,126 in capital as a participantin accordance with contribution provisions of the Limited Partnership Agreement(the Agreement). During 1997 in accordance with Partnership Agreement alladditional general partners were converted to limited partners.

     Underthe terms of the Agreement, the allocation of revenues is as follows:

|                                          | Allocation

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

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

     Operatingand direct costs are allocated and charged to the additional general andlimited partners and the Managing General Partner in the same percentages asrevenues are allocated. Leasehold, drilling and completion costs, and equipmentcosts are borne 80% by the Additional General and Limited Partners and 20% bythe Managing General Partner. See Footnote 4 of financial statements for acomplete description of the allocation of Partnership revenue and costs.

Employees

     ThePartnership has no employees; however, PDC has approximately 120 employees,including 17 in finance and data processing, 8 in administration, 12 inexploration and development, 78 in production and 5 in natural gas marketing. 

 

Plan of Operations

     ThePartnership participated in the drilling of 85 gross wells and will continue tooperate and produce its 80 gross productive wells. The Partnership does nothave unexpended initial capital and no additional drilling activity is planned.

     SeeItem 2 herein for information concerning the Partnership's gas wells.

Markets for Oil and Gas

 

     Theavailability of a market for any oil and gas produced from the operations ofthe Partnership will depend upon a number of factors beyond the control of thePartnership which cannot be accurately predicted. These factors include theproximity of the Partnership wells to and the capacity of natural gaspipelines, the availability and price of competitive fuels, fluctuations inseasonal supply and demand, and government regulation of supply and demandcreated by its pricing and allocation restrictions. Oversupplies of gas can beexpected to occur from time to time and may result in the Partnership's wellsbeing shut-in or curtailed. Increased imports of oil and natural gas haveoccurred and are expected to continue. The effects of such imports couldadversely impact the market for domestic oil and natural gas.  All oil and gasis sold under contracts based on market sensitive indexes that vary from monthto month. No fixed price contracts are in place. The Partnership sold oil andnatural gas to two customers which accounted for 90.53% and 9.04% of thePartnership's total oil and natural gas sales for the year ended December 31, 2004 and 89.57% and 10.43% for the year ended December 31, 2003.

2

Derivatives and Hedging Activities

     TheManaging General Partner, through its subsidiary Riley Natural Gas, has been inthe gas marketing business since 1986. During that time period, the ManagingGeneral Partner has utilized and continues to utilize commodity based derivative instruments as hedges to manage a portion ofthe Partnership's exposure to price volatility stemming from natural gasproduction.  These instruments consist of NYMEX-traded natural gas futures andoption contracts for eastern Colorado production, and CIG (Colorado InterstateGas Index)-based contracts for other Colorado production and NYMEX traded oil futuresand option contracts for Colorado oil production.  The contracts hedgecommitted and anticipated natural gas sales, generally forecasted to occurwithin the next 2 year period. The Managing General Partner does not hold orissue derivatives for trading or speculative purposes and permits utilizationof hedges only if there is an underlying physical position.  See "CommodityPrice Risk" under Item 7A.

     Notwithstandingthe measure taken by the Managing General Partner to attempt to control price risk,the Partnership remains subject to price fluctuations for natural gas and oilsold in the spot market.  The Managing General Partner continues to evaluatethe potential 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

     ThePartnership competes in marketing its gas with numerous companies andindividuals, many of which have financial resources, staffs and facilitiessubstantially greater than those of the Partnership or Petroleum DevelopmentCorporation. 

State Regulations

 

     Stateregulatory authorities have established rules and regulations requiring permitsfor well operations, reclamation bonds and reports concerning operations.States also have statutes and regulations concerning the spacing of wells,environmental matters and conservation, and have established regulationsconcerning the unitization and pooling of oil and gas properties and maximum ratesof production from oil and gas wells. The Partnership believes it has compliedin all material respects with applicable state regulations. The Partnershipestimates it has spent approximately $0, $1,050, and $650 in 2004, 2003 and2002, respectively to comply with federal and state regulations.

Federal Regulations

 

     Regulationof Liquid Hydrocarbons. Liquid hydrocarbons (including crude oil andnatural gas liquids) were subject to federal price and allocation controlsuntil January 1981 when controls were effectively eliminated by executive orderof the President. As a result, to the extent the Partnership sells oil producedfrom its properties, those sales are at unregulated market prices.

     Althoughit appears unlikely under present circumstances that controls will be reimposedupon liquid hydrocarbons, it is possible Congress may enact such legislation ata future date. 

     NaturalGas Regulation. 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.

     ProposedRegulation. Numerous proposals concerning energy are being considered bythe United States Congress, various state legislatures and regulatory agencies.The possible outcome and effect of these proposals cannot be accuratelypredicted.

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

 

     Thefollowing table sets forth the results of drilling activity of the Partnershipwhich was conducted in the Continental United States.

|                   Development  Wells                   |  
    Gross Wells    

 

      Net Wells      

 
 
Productive

Dry

Total

Productive

Dry

Total

 
80

5

85

 

62.474

4.912

67.386

     ThePartnership has not participated in any exploratory wells. No additionaldrilling activity is planned.

Production 

See"Management's Discussion and Analysis" on page 5 for Partnershipproduction. 

Reserves

See"Footnote 8" to the Partnership's financial statements forinformation related to the Partnership's oil and gas reserves.

 

Summary of Productive Wells

 

     During2002 the Partnership plugged 12 wells in the Angel Unite in Michigan. The tablebelow shows the number of the Partnership's gross and net wells by state as of December 31, 2004. 

Natural Gas  Wells

Location

Gross

Net

Michigan

 9

3.622

Pennsylvania

47

41.955

West Virginia

12

11.910

____

______

Total

68

57.487

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

 

Title to Properties

     ThePartnership's interests in producing acreage are in the form of assigned directinterests in leases. Such properties are subject to customary royalty interestsgenerally contracted for in connection with the acquisition of properties andcould be subject to liens incident to operating agreements, liens for currenttaxes and other burdens. The Partnership believes that none of these burdensmaterially interfere with the use of such properties in the operation of thePartnership's business.

     Asis customary in the oil and gas industry, little or no investigation of titleis made at the time of acquisition of undeveloped properties (other than apreliminary review of local mineral records). Investigations are generallymade, including in most cases receiving a title opinion of legal counsel,before commencement of drilling operations. A thorough examination of title hasbeen made with respect to all of the Partnership's producing properties and thePartnership believes that it has generally satisfactory title to suchproperties.

4

ITEM 3. LEGAL PROCEEDINGS.

     TheManaging General partner as driller/operator is not party to any legal action thatit believes would have a materially adverse affect on the Managing GeneralPartner's or Partnership's business, financial condition, results of operationsor liquidity.

ITEM 4. SUBMISSION OF MATTERSTO A VOTE OF SECURITY HOLDERS.

     NotApplicable.

PART II

 

ITEM 5.  MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDERMATTERS.

     AtDecember 31, 2004, PDC 1996-D Limited Partnership had one Managing GeneralPartner, 9 Limited Partners who fully paid for 16.2125 units at $20,000 perunit of limited partnership interests and a total of 1049 Additional GeneralPartners who fully paid for 748.8738 units at $20,000 per unit of additionalgeneral partnership interests. During 1997in accordance with the Partnership Agreement all Additional General Partnerswere converted to Limited Partners. No established public trading marketexists for the interests.

     Limitedand additional general partnership interests are transferable, however noassignee of an interest in the Partnership can become a substituted partnerwithout the written consent of the transferor and the Managing General Partner. There is no established trading market for thesecurities of the Partnership.

ITEM 6. SELECTED FINANCIALDATA.

     Theselected financial 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

$1,389,859 

$1,278,115 

829,395 

Costs and Expenses

705,293 

743,370 

753,955 

Cumulative effect of change in accounting principle

-    

(21,123)

-    

Net Income 

685,084 

514,129 

76,247 

Allocation of Net Income:

     Managing General Partner

137,017 

102,826 

15,249 

     Limited and Additional  General Partners

548,067 

411,303 

60,998 

     Per Limited and Additional  General Partner Unit

716 

538 

80 

Total Assets

2,724,130 

2,781,746 

2,975,356 

Distributions:

Managing General Partner

78,489 

86,518 

22,316 

Limited and Additional General Partners

675,121 

651,527 

284,275 

 

ITEM7.  MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION ANDRESULTS OF OPERATIONS.

 

Liquidity and CapitalResources

 

     ThePartnership was funded with initial Limited and Additional General Partnercontributions of $15,301,726 and the Managing General Partner contributed$3,328,126 in accordance with the Agreement. Syndication and management feecosts of $1,989,224 were incurred leaving available cash of $16,640,628 forPartnership activities.

     ThePartnership began exploration and development activities subsequent to thefunding of the Partnership and completed these activities by December 31, 1997. Eighty-five wells have been drilled, 80 of which have been completed asproducers.  Currently the Partnership has 68 producing wells. No additionalwells will be drilled.

5

     ThePartnership had working capital at December 31, 2004 of $196,488.

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

Results of Operations

 

2004 Results Compared to 2003 

     Oiland gas sales for the year ended December 31, 2004 were $1,389,859 compared to $1,278,115 for the year ended December 31, 2003.  The volume of natural gas sold for the year ended December 31, 2004, was 241,010 Mcf at an averagesales price of $6.04 per Mcf compared to 260,912 Mcf at an average sales priceof $4.90 per Mcf for the year ended December 31, 2003. The lifting costs for the year ended December 31, 2004 was $2.13 per Mcfe compared to $1.95 per Mcfefor the year ended December 31, 2003.  Depreciation, depletion and amortizationdecreased from $207,905 for the year ended December 31, 2003 to $167,834 for the year ended December 31, 2004 as a result of lower volumes of natural gasand oil sold.  Cash distributions to the partners amounted to $753,610 in 2004.

 

2003 Compared to 2002

 

     Oiland gas sales for the year ended December 31, 2003 were $1,278,115 compared to $829,395 for the year ended December 31, 2002. The volume of natural gassold for the year ended December 31, 2003, was 260,912 Mcf at an average salesprice of $4.90 per Mcf compared to 279,201 Mcf at an average sales price of$2.97 per Mcf for the year ended December 31, 2002. The lifting costs for the year ended December 31, 2003 was $1.95 per Mcfe compared to $1.82 per Mcfefor the year ended December 31, 2002.  This increase is partially attributed tothe increase in severance and property taxes. The fixed costs of operations andwell maintenance are allocated to lower production volumes, thereforeincreasing the lifting cost per Mcfe. Cash distributions to the partnersamounted to $738,045 in 2003.

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

 

Critical Accounting Policiesand 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 judgments. In applying those policies, our management uses its judgmentto determine the appropriate assumptions to be used in the determination ofcertain estimates. Those estimates are based on our historical experience, ourobservance of trends in the industry, and information available from otheroutside sources, as appropriate. For a more detailed discussion on theapplication of these and other accounting policies, see "Note 1 - Summary ofsignificant accounting policies" in our financial statements and related notes.The Partnership's critical accounting policies and estimates are as follows:

Revenue Recognition

      Sales of natural gas arerecognized when natural gas has been delivered to a custody transfer point,persuasive evidence of a sales arrangement exists, the rights and responsibilityof ownership pass to the purchaser upon delivery, collection of revenue fromthe sale is reasonably assured and the sales price is fixed or determinable. Natural gas is sold by the Managing General Partner under contracts with termsranging from one month to three years.  Virtually all of the Managing GeneralPartner's contracts pricing provisions are tied to a market index, with certainadjustments based on, among other factors, whether a well delivers to agathering or transmission line, quality of natural gas and prevailing supplyand demand conditions, so that the price of the natural gas fluctuates toremain competitive with other available natural gas supplies.  As a result, thePartnership's revenues from the sale of natural gas will suffer if marketprices decline and benefit if they increase.  The Partnership believes that thepricing provisions of its natural gas contracts are customary in the industry.

The ManagingGeneral Partner currently uses the "Net-Back" method of accounting for transportationarrangements of natural gas sales.  The Managing General Partner sells gas atthe wellhead 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.

                                                                                         6 

Sales of oilare recognized when persuasive evidence of a sales arrangement exists, the oilis verified 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.

                                 

Accounting for Derivatives Contracts at Fair Value

     The Partnership usesderivative instruments to manage its commodity and financial market risks.Accounting requirements for derivatives and hedging activities are complex;interpretation of these requirements by standard-setting bodies is ongoing. 

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

    The measurement of fairvalue is based on actively quoted market prices, if available. Otherwise, thePartnership seeks indicative price information from external sources, includingbroker quotes and industry publications. If pricing information from externalsources is not available, measurement involves judgment and estimates. Theseestimates are based on valuation methodologies considered appropriate by thePartnership's management. 

     For individual contracts,the use of different assumptions could have a material effect on the contract'sestimated fair value. In addition, for hedges of forecasted transactions, thePartnership must estimate the expected future cash flows of the forecastedtransactions, as well as evaluate the probability of the occurrence and timingof such transactions. Changes in conditions or the occurrence of unforeseenevents could affect the timing of recognition in earnings for changes in fairvalue of certain hedging derivatives.

Use of Estimates in Long-Lived Asset ImpairmentTesting

Impairment testing for long-livedassets and intangible assets with definite lives is required when circumstancesindicate those assets may be impaired.  In performing the impairment test, thePartnership would estimate the future cash flows associated with individualassets or groups of assets.  Impairment must be recognized when theundiscounted estimated future cash flows are less than the related asset'scarrying amount.  In those circumstances, the asset must be written down to itsfair value, which, in the absence of market price information, may be estimatedas the present value of its expected future net cash flows, using anappropriate discount rate.  Although cash flow estimates used by thePartnership are based on the relevant information available at the time theestimates are made, estimates of future cash flows are, by nature, highlyuncertain and may vary significantly from actual results.

Oiland Gas Properties 

     Exploration and developmentcosts are accounted for by the successful efforts method.

       

     ThePartnership assesses impairment of capitalized costs of proved oil and gasproperties by comparing net capitalized costs to estimated undiscounted futurenet cash flows on a field-by-field basis using expected prices. Prices utilizedin each year's calculation for measurement purposes and expected costs are heldconstant throughout the estimated life of the properties. If net capitalizedcosts exceed undiscounted future net cash flows, the measurement of impairmentis based 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 as incurred. The costs of drilling exploratory wells are capitalized pending determinationof whether the wells have discovered economically producible reserves.  Ifreserves are not discovered, such costs are expensed as dry holes.  Developmentcosts, including equipment and intangible drilling costs related to bothproducing wells and developmental dry holes, are capitalized.

Unproved properties or leases are written-off toexpense when it is determined that they will expire or be abandoned.

Costs of proved properties, including leaseholdacquisition, exploration and development costs and equipment, are depreciated ordepleted by the unit-of-production method based on estimated proved developedoil and gas reserves.

                                                                                          

                                                                                           

                                                                                               7 

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

New Accounting Standards

 

     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 $8,526 and a related liability of $29,649(using a 6% discount rate) and a cumulative effect of change in accountingprinciple on prior years of $21,123.

Item7A.  Quantitative and Qualitative Disclosure About Market Risk.

Market-SensitiveInstruments and Risk Management

     ThePartnership's primary market risk exposure is commodity price risk.  Thisexposure is discussed in detail below:

CommodityPrice 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 production. These hedging arrangements have the effect of locking in for specified periods(at predetermined 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'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 gas future and option contracts forspeculative purposes.

     

Thefollowing tables summarize the open futures and options contracts for thePartnership 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

2,389

6.63

15,849

(909)

Natural Gas

Floors

65,692

4.79

-    

7,528 

Natural Gas

Ceilings

32,846

5.73

-    

(29,933)

Contracts  maturing in 12 months following December 31, 2004 

 Natural Gas

Purchase

2,389

6.63

15,849

(909)

Natural Gas

Floors

65,692

4.79

-    

7,528 

Natural Gas

Ceilings

32,846

5.73

-    

(29,933)

Prior Year  Total Contracts as of December 31, 2003

Natural Gas

Sale

3,793

5.40

20,480

(2,840)

Natural Gas

Purchase

3,251

4.77

15,506

2,158 

Natural Gas

Floors

60,682

4.12

-    

652 

Natural Gas

Ceilings

49,304

5.55

-    

(8,770)

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

8

Theaverage NYMEX closing price for natural gas for the years 2004, 2003 and 2002was $6.14 per Mmbtu, $5.39 per Mmbtu, and $3.22 per Mmbtu. The average NYMEXclosing price for oil for the years 2004, 2003 and 2002, was $41.44 per bbl,$30.98 per bbl, and $26.98 per bbl. Future near-term gas prices will beaffected by various supply and demand factors such as weather, government andenvironmental regulations and new drilling activities within the industry.

Disclosureof Limitations

     Asthe information above incorporates only those exposures that exist at December 31, 2004, it does not consider those exposures or positions which could ariseafter that date. As a result, the Partnership's ultimate realized gain or losswith respect to commodity price fluctuations will depend on the exposures thatarise during the period, the Partnership's hedging strategies at the time andcommodity prices at the time.

PART III

ITEM 8. FINANCIAL STATEMENTSAND SUPPLEMENTARY DATA:

 

     Theresponse to this Item is set forth herein in a separate section of this Report,beginning on Page F-1.

ITEM 9. CHANGES IN ANDDISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND

        FINANCIALDISCLOSURE.

     NONE.

 

ITEM 9A. CONTROLS AND PROCEDURES

     Under thesupervision 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 be disclosedin reports filed or submitted under the Securities Exchange Act is recorded,processed, summarized, and reported, within the time periods specified in theCommission's rules and forms, and is accumulated and communicated tomanagement, including the Managing General Partner's Chief Executive Officerand Chief Financial Officer, as appropriate to allow for timely disclosure.There have been no significant changes in our internal controls or in otherfactors that could significantly affect these controls in the fourth quarterand subsequent to the date of their evaluation.

ITEM 9B.  OTHER INFORMATION

 

NONE

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.

     ThePartnership has no directors or executive officers.  The partnership is managedby Petroleum Development Corporation (the Managing General Partner).  PetroleumDevelopment Corporation's common stock is traded in the NASDAQ National Marketand Form 10-K for 2004 has been filed with the Securities and ExchangeCommission.  

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. EXECUTIVECOMPENSATION.

 

     NON-APPLICABLE.

ITEM 12. SECURITY OWNERSHIP OFCERTAIN BENEFICIAL OWNERS MANAGEMENT AND RELATED STOCKHOLDER MATTERS.

     NON-APPLICABLE.

 

9

ITEM 13. CERTAIN RELATIONSHIPSAND RELATED TRANSACTIONS.

     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 during the years listed below:

Years  Ended December 31,

     2004

     2003

     2002

Lifting costs

$512,525 

510,013 

509,166 

Tax return preparation

7,932 

7,932 

7,933 

Direct administrative cost

3,505 

4,089 

4,255 

ITEM 14.  PRINCIPAL ACCOUNTANT FEES AND SERVICES 

     Forthe years ended December 31, 2004 and 2003, the Partnership paid KPMG LLP $8,140and $8,133, respectively, for the professional services for the audit of thePartnership's financial statements in its Form 10K and review of financialstatements included in the Partnership's form 10-Qs.

Pre-Approval Policies and Procedures

 

     TheSarbanes-Oxley Act of 2002 requires that all services provided to thePartnership by its independent accountants be subject to pre-approval by theAudit Committee or authorized members of the Committee. Since the Partnershipdoes not have an Audit Committee, the Managing General Partner's AuditCommittee also serves for the Partnership.  The Audit Committee has adoptedpolicies and procedures for pre-approval of all audit services and non-auditservices to be provided by the Partnership's independent accountants. Servicesnecessary to conduct the annual audit must be pre-approved by the AuditCommittee or by the authorized Audit Committee member. 

ITEM 15. EXHIBITS andFINANCIAL STATEMENT SCHEDULES.

                                (1)   FinancialStatements

                                        SeeIndex to Financial Statements on F-2

                                (2)  Financial Statement Schedules

                                        See Index to FinancialStatements on page F-2. All financial statement schedules are omitted becausethey are not required, inapplicable, or the information is included in theFinancial 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.  033-63635, and Rule 424 final prospectus, dated June 14, 1996, of PDC 1996-1997 Drilling Program, filed with the SEC on June 14, 1996).

 14

Code of Ethics of Petroleum  Development Corporation (incorporated by reference to the posted code on the  web site of Petroleum Development Corporation at www.petd.com).

 31.1

Rule 13a-14(a)/15d-14(c) Certification of Chief Executive  Officer of Petroleum Development Corporation, the managing general partner of  the Limited Partnership.

 31.2

Rule 13a-14(a)/15d-14(c) Certification of Chief Financial  Officer of Petroleum Development Corporation, the managing general partner of  the Limited Partnership.

 32.1

Title 18 U.S.C. Section 1350 (Section 906 of  Sarbanes-Oxley Act of 2002) Certifications by Chief Executive Officer and  Chief Financial Officer of Petroleum Development Corporation, the managing  general partner of the Limited Partnership.

10

CONFORMED COPY

SIGNATURES

      Pursuantto the requirements of Section 13 or 15(d) of the Securities Exchange Act of1934, the Registrant has duly caused this report to be signed on its behalf bythe undersigned, thereunto duly authorized.

 
PDC 1996-D Limited Partnership

By its Managing General Partner

Petroleum Development Corporation

 
By /s/ Steven R. Williams      

   Steven R. Williams, Chairman

April 14, 2005

     Pursuantto the requirements of the Securities Exchange Act of 1934, this report hasbeen signed below by the following persons on behalf of the Registrant and inthe capacities and on the dates indicated:

Signature

Title

Date

/s/ Steven R. Williams

    Steven R. Williams

Chairman, Chief Executive Officer and

 Director 

April 14, 2005

/s/ Darwin L. Stump 

    Darwin L. Stump

Chief Financial Officer and Treasurer

(principal financial and accounting officer)

April 14, 2005

 

/s/ Thomas E. Riley 

    Thomas E. Riley

President and Director

April 14, 2005

/s/ Donald B. Nestor

    Donald B. Nestor

Director

April 14, 2005

/s/ Vincent F. D'Annunzio

    Vincent F. D'Annunzio

Director

April 14, 2005

11

PDC 1996-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 AccountingFirm's Report Thereon)

F-1

PDC 1996-D LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Index to Financial Statements

Report of Independent Registered Public Accounting Firm

F-3

Balance Sheets - December 31, 2004 and 2003 

F-4

Statements of Operations -  Years Ended December 31, 2004, 2003 and 2002

F-5

Statements of Partners' Equity and Comprehensive Income-

 Years Ended December 31, 2004, 2003 and 2002 

F-6

Statements of Cash Flows -  Years Ended December 31, 2004, 2003 and 2002

F-7

Notes to Financial Statements

F-8

Allfinancial statement schedules have been omitted because they are not applicableor not required or the required information is shown in the financialstatements or notes thereto.

F-2

Reportof Independent Registered Public Accounting Firm

To the Partners

PDC 1996-D Limited Partnership:

Wehave audited the accompanying balance sheets of PDC 1996-D Limited Partnership(a West Virginia limited partnership) as of December 31, 2004 and 2003, and the related statements of operations, partners' equity and comprehensiveincome (loss), and cash flows for each of the years in the three-year periodended December 31, 2004. These financial statements are the responsibility ofthe Partnership's management. Our responsibility is to express an opinion onthese financial statements based on our audits.

Weconducted our audits in accordance with the standards of the Public CompanyAccounting Oversight Board (United States).  Those standards require that weplan and perform the audit to obtain reasonable assurance about whether thefinancial statements are free of material misstatement.  An audit includesexamining, on a test basis, evidence supporting the amounts and disclosures inthe financial statements.  An audit also includes assessing the accountingprinciples used and significant estimates made by management, as well asevaluating the overall financial statement presentation.  We believe that ouraudits provide a reasonable basis for our opinion.

Inour opinion, the financial statements referred to above present fairly, in allmaterial respects, the financial position of PDC 1996-D Limited Partnership asof December 31, 2004 and 2003, and the results of its operations and its cashflows for each of the years in the three-year period ended December 31, 2004,in conformity with U.S. generally accepted accounting principles.

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

                                                                                                 KPMG LLP

                                                                                                                                                                                        

                                                                                                                                                                    KPMGLLP

Pittsburgh, Pennsylvania 

April 15, 2005

F-3

PDC 1996-D LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Balance Sheets

December 31, 2004 and 2003

     Assets

2004

2003

Cash

$        705 

     3,789 

Accounts receivable - 

  oil and gas revenues

   263,407 

   150,105 

          Total  current assets

264,112 

153,894 

Oil and gas properties, successful

  efforts method (notes 3 and 6):

  6,952,955 

  6,952,955 

       Less  accumulated depreciation, 

        depletion, and  amortization

  4,492,937 

  4,325,103 

2,460,018 

2,627,852 

$2,724,130 

2,781,746 

     Liabilities and  Partners' Equity

Current liabilities:

     Accrued expenses

$   67,624 

   44,086 

          Total  current liabilities

67,624 

44,086 

Asset retirement obligation

33,314 

31,428 

Partners' equity

2,623,192 

2,706,232 

$2,724,130 

2,781,746 

See accompanying notes to financial statements.

F-4

PDC 1996-D LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Statements of Operations

Years Ended December 31, 2004, 2003 and 2002

2004

2003

2002

2002

2001

Revenues:

     Sales of oil and  gas

$1,389,859 

1,278,115 

 829,395 

 829,395 

 1,265,406 

     Interest income

       518 

       507 

       807 

       807 

     4,276 

1,390,377 

1,278,622 

830,202 

830,202 

1,269,682 

Expenses (note 3):

     Lifting cost

512,525 

510,013 

509,166 

509,166 

532,160 

     Independent audit  fee

8,140 

8,133 

7,673 

7,673 

7,378 

     Franchise taxes

3,471 

3,519 

3,314 

3,314 

3,859 

     Tax return  preparation

7,932 

7,932 

7,933 

7,933 

7,932 

     Direct  administrative cost

5,391 

5,868 

4,255 

4,255 

2,874 

     Depreciation,  depletion and amortization

   167,834 

   207,905 

   221,614 

   221,614 

   390,588 

   705,293 

   743,370 

   753,955 

   753,955 

 1,464,272 

Income before cumulative effect of

  change in accounting principle

  685,084 

  535,252 

  76,247 

  76,247 

  (194,590)

Cumulative effect of change in accounting  principle

           -   

   (21,123)

        -    

        -    

        -    

Net income 

$   685,084 

   514,129 

    76,247 

    76,247 

  (194,590)

Net income per limited and additional

  general partner units before  cumulative effect of 

  change in accounting principle

  $        716 

          560 

           80 

           80 

         (203)

Cumulative effect of change in accounting  principle

        -    

        (22)

        -    

        -    

        -    

Net income per limited and additional

  general partner units

  $        716 

        538 

         80 

         80 

       (203)

See accompanying notes to financial statements.

F-5

PDC1996-D LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Statements of Partners' 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

$2,256,550 

912,742 

 3,169,292 

Distributions to partners

(284,275)

(22,316)

 

(306,591)

 

 

 

Comprehensive income:

 

 

 

 Net income 

60,998 

15,249 

 

76,247  

Change in fair value of outstanding 

  hedging positions

 

  (33,578)

 

Reclassification adjustment for settled 

  contracts included in net income  (loss)

 

               

 

Other comprehensive loss

 

(33,578)

   (33,578)

Comprehensive income

           

          

             

    42,669 

 

 

 

Balance December 31, 2002

2,033,273 

   905,675 

  (33,578)

 2,905,370 

Distributions to partners

(651,527)

(86,518)

 

(738,045)

 

 

 

Comprehensive income:

 

 

 

 Net income 

411,303 

102,826 

 

514,129 

Change in fair value of outstanding

  hedging positions

  20,725 

 

Reclassification adjustment for settled

 contracts included in net income

 

      4,053 

 

Other comprehensive income

 

24,778 

       24,778 

Comprehensive income

          

          

          

     538,907 

 

 

Balance December 31, 2003

1,793,049 

  921,983 

   (8,800)

     2,706,232 

Distributions to partners

(675,121)

(78,489)

 

(753,610)

 

 

 

Comprehensive income:

 

 

 

 Net income 

548,067 

137,017 

 

685,084 

Change in fair value of outstanding

  hedging positions

  (47,060) 

 

Reclassification adjustment for settled

 contracts included in net income (loss)

 

      32,546  

 

Other comprehensive income

 

(14,514) 

    (14,514) 

Comprehensive income

                     

                

               

     670,570 

 

 

Balance December 31, 2004

$1,665,995 

  980,511 

   23,314 

  2,623,192 

See accompanying notes to financial statements.

F-6

PDC 1996-D LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Statements of Cash Flows

Years Ended December 31, 2004, 2003 and 2002

2004

2003

2002

Cash flows from operating activities:

    Net income 

$685,084 

514,129 

 76,247 

    Adjustments to reconcile net income 

      to net cash provided from  operating activities:

      Depreciation, depletion and  amortization

167,834 

207,905 

221,614 

      Cumulative effect of change in  accounting principle

-     

21,123 

-    

      Accretion of asset retirement  obligation

1,886 

1,779 

-    

      Changes in operating assets and  liabilities:

       (Increase) decrease in  accounts receivable

        - oil and gas revenues

  (106,426)

  (10,888)

  6,163 

       Increase in accrued expenses

     2,148 

    4,434 

   3,086 

       Net cash provided from  operating activities

 750,526 

 738,482 

 307,110 

Cash flows from financing activities:

     Distributions to partners

(753,610)

(738,045)

(306,591)

       Net cash used by financing  activities

(753,610)

(738,045)

(306,591)

Net increase (decrease) in cash

(3,084)

437 

519 

Cash at beginning of year

    3,789 

   3,352 

   2,833 

Cash at end of year

$       705 

   3,789 

   3,352 

See accompanying notes to financial statements.

F-7

PDC 1996-D LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Notes to Financial Statements

Years Ended December 31, 2004, 2003 and 2002

(1)    Summaryof Significant Accounting Policies

Partnership Financial Statement Presentation Basis

The financial statements include only thoseassets, liabilities and results of operations of the partners which relate tothe business of PDC 1996-D Limited Partnership (the Partnership). Thestatements do not include any assets, liabilities, revenues or expensesattributable to any of the partners' other activities.  Petroleum DevelopmentCorporation ("PDC") serves as Managing General Partner of thePartnership.

Oil and Gas Properties

The Partnership follows the successful effortsmethod of accounting for the cost of exploring for and developing oil and gasreserves.  Under this method, costs of development wells, including equipmentand intangible drilling costs related to both producing wells and developmentaldry holes, and successful exploratory wells are capitalized and amortized on anannual basis to operations by the units-of-production method using estimatedproved developed reserves determined at year-end by the Managing GeneralPartner's petroleum engineers. If a determination is made that an exploratorywell has not discovered economically producible reserves, then its costs areexpensed as dry hole costs.

The Partnership assesses impairment of capitalizedcosts of proved oil and gas properties by comparing net capitalized costs toundiscounted future net cash flows on a field-by-field basis using expectedprices.  Prices utilized in each year's calculation for measurement purposesand expected costs are held constant throughout the estimated life of theproperties. If net capitalized costs exceed undiscounted future net cash flow,the measurement of impairment is based on estimated fair value which wouldconsider future discounted cash flows.

Revenue Recognition

Salesof natural gas are recognized when natural gas has been delivered to a custodytransfer point, persuasive evidence of a sales arrangement exists, the rightsand responsibility of ownership pass to the purchaser upon delivery, collectionof revenue from the sale is reasonably assured and the sales price is fixed ordeterminable.  Natural gas is sold by the Managing General Partner undercontracts with terms ranging from one month to three years.  Virtually all ofthe Managing General Partner's contracts pricing provisions are tied to amarket index, with certain adjustments based on, among other factors, whether awell delivers to a gathering or transmission line, quality of natural gas andprevailing supply and demand conditions, so that the price of the natural gasfluctuates to remain competitive with other available natural gas supplies.  Asa result, the Partnership's revenues from the sale of natural gas will sufferif market prices decline and benefit if they increase.  The Partnershipbelieves that the pricing provisions of its natural gas contracts are customaryin the industry.

TheManaging General Partner currently uses the "Net-Back" method of accounting fortransportation arrangements of natural gas sales.  The Managing General Partnersells gas at the wellhead and collects a price and recognizes revenues based onthe wellhead sales price since transportation costs downstream of the wellheadare incurred by the Managing General Partner's customers and reflected in thewellhead price.

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

(Continued)

F-8

PDC 1996-D LIMITEDPARTNERSHIP

(A West Virginia LimitedPartnership)

Notes to FinancialStatements, Continued

Income Taxes

Since the taxable income or loss of thePartnership is reported in the separate tax returns of the partners, noprovision has been made for income taxes on the Partnership's books.

Under federal income tax laws, regulations andadministrative rulings, certain types of transactions may be accorded varyinginterpretations.  Accordingly, the Partnership's tax return and, consequently,individual tax returns of the partners may be changed to conform to the taxtreatment resulting from a review by the Internal Revenue Service.

Derivative Financial Instruments

The Managing General Partner utilizes commoditybased derivative instruments as hedges to manage a portion of the Partnership'sexposure to price volatility stemming from natural gas production. Theseinstruments consist of costless collars and option contracts traded on the NewYork Mercantile Exchange. The costless collars and option contracts hedgecommitted 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 are recognized on the Partnershipbalance sheet at their fair value.  On the date the derivative contract isentered into, the Managing General Partner designates the derivative as eithera hedge of a forecasted transaction or the variability of cash flows to bereceived or paid related to a recognized asset or liability ("cash flow"hedge), or a non-hedging derivative. The Managing General Partner formallydocuments all relationships between hedging instruments and hedged items, aswell as its risk-management objective and strategy for undertaking varioushedge transactions.  This process includes linking all derivatives that aredesignated as cash-flow hedges to specific firm commitments.  The ManagingGeneral Partner also formally assesses, both at the hedge's inception and on anongoing basis, whether the derivatives that are used in hedging transactionsare highly effective in offsetting changes in cash flows of hedged items. Whenit is determined that a derivative is not highly effective as a hedge or thatit has ceased to be a highly effective hedge, the Partnership discontinueshedge accounting prospectively.  No hedging activities were discontinued during2004 or 2003.

Changes in fair value of a derivative that ishighly effective and that is designated and qualifies as a cash-flow hedge arerecorded in accumulated other comprehensive income (loss), until earnings areaffected by the variability in cash flows of the designated hedged item.Changes in the fair value of non-hedging derivatives are reported in current-periodearnings. The Partnership discontinues hedge accounting prospectively when itis determined that the derivative is no longer effective in offsetting changesin the cash flows of the hedged item, the derivative expires or is sold,terminated, or exercised.  Additionally, if the derivative is dedesignated as ahedging instrument, because it is probable that a forecasted transaction willnot occur, or the Partnership determines that designation of the derivative asa hedging instrument is no longer appropriate, hedge accounting will be discontinued.

Byusing derivative financial instruments to hedge exposures to changes incommodity prices, the Managing General Partner exposes the Partnership tocredit risk. Credit risk is the failure of the counterparty to perform underthe terms of the derivative contract. When the fair value of a derivativecontract is positive, the counterparty owes the Partnership, which createscredit risk. The Managing General Partner minimizes the credit risk inderivative instruments by entering into transactions with high-qualitycounterparties.

Use of Estimates

The Partnership has made a number of estimates andassumptions relating to the reporting of assets and liabilities and revenuesand expenses and the disclosure of contingent assets and liabilities to preparethese financial statements in conformity with accounting principles generallyaccepted in the United States of America. Actual results could differ fromthose estimates. 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.

(Continued)

F-9

PDC 1996-D LIMITEDPARTNERSHIP

(A West Virginia LimitedPartnership)

Notes to FinancialStatements, Continued

New Accounting Standards

In June 2001, the Financial Accounting StandardBoard issued FASB No. 143, "Accounting for Asset RetirementObligations" that requires entities to record the fair value of a liabilityfor an asset retirement obligation in the period in which it is incurred and acorresponding increase in the carrying amount of the related long-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 $8,526 and a related liability of $29,649 (using a 6% discountrate) and a cumulative effect of change in accounting principle on prior yearsof $21,123.

 (2)    Organization

The Partnership was organized as a limitedpartnership on December 31, 1996 in accordance with the laws of the State of West Virginia for the purpose of engaging in the drilling, completion and operation of oiland gas development and exploratory wells in the Northern Appalachian andMichigan Basins.

Purchasers of partnership units subscribed to andfully paid for 16.2125 units of limited partner interests and 748.8738 units ofadditional general partner interests at $20,000 per unit (Investor Partners). Petroleum Development Corporation has been designated the Managing GeneralPartner of the Partnership. Although costs, revenues and cash distributionsallocable to the limited and additional general partners are shared pro ratabased upon the amount of their subscriptions, including the Managing GeneralPartner to the extent of its capital contributions, there are significantdifferences in the federal income tax effects and liability associated withthese different types of units in the Partnership.

Upon completion of the drilling phase of thePartnership's wells, all additional general partners units are converted intounits of limited partner interests and thereafter become limited partners ofthe Partnership. Limited partners do not have any rights to convert their unitsof additional general interests in the Partnership.

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

(3)    Transactionswith Managing General Partner and Affiliates

Pursuant to the authorization contained in theAgreement, PDC receives fees for services rendered and reimbursement of certainexpenses from the Partnership.  See respective drilling prospectus for furtherinformation regarding the Agreement. The following table presents compensationor reimbursements by the Partnership to PDC or other related parties for yearsended December 31, 2004, 2003 and 2002.

Years Ended December 31,

2004

2003

2002

Lifting costs

$512,525

$510,013

509,166

Tax return preparation

7,932

7,932

7,933

Direct administrative cost

3,505

4,089

4,255

(4)    Allocation

The following table summarizes the participationof the Managing General Partner and the Investor Partners, taking account ofthe Managing General Partner's capital contribution equal to a minimum of 20%of the initial capital, in the costs and revenues of the Partnership.

(Continued)

F-10

PDC 1996-D LIMITEDPARTNERSHIP

(A West Virginia LimitedPartnership)

Notes to FinancialStatements, Continued

** **

**Investor**

**Partners**

**Managing**

**General**

**Partner**

**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)  Represents aone-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.

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

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

     

     (6)  Inthe event of the sale or other disposition of a productive well, a lease uponwhich such well is situated, or any equipment related to any such lease orwell, the proceeds from such sale or disposition shall be allocated andcredited to the Partners as oil and gas revenues are allocated.  The term"proceeds" above does not include revenues from a royalty, overridingroyalty, lease interest reserved, or other promotional consideration receivedby the  Partnership in connection with any sale or disposition, which revenuesshall be allocated to the Investor Partners and the Managing General Partner inthe same percentages that oil and gas revenues are allocated.  No such saleshave occurred.  In accordance with the drilling prospectus the investorpartners received preferred cash distributions of $72,231, $61,089, and $39,002in 2004, 2003 and 2002, respectively.

(Continued)

                                                                                                           F-11

PDC 1996-D LIMITED PARTNERSHIP

(A West Virginia LimitedPartnership)

Notes to Financial Statements,Continued

     (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 2.84 units ofpartnership interest for a total ownership of 24.25 units as of December 31, 2004 which represents a 3.17% ownership of the original Investor Partnersshare of limited and additional general partnership units.  Therefore, costsand revenues and distributions for these purchased units are allocated to PDCin accordance with the Investor Partners allocation percentages disclosed inthis table.

(5) Derivative Financial Instruments

TheManaging General Partner utilizes commodity-based derivative instruments ashedges to manage a portion of its exposure to price risk from its oil andnatural gas sales.  These instruments consist of NYMEX-traded natural gasfutures contracts and option contracts for Appalachian and Michigan production. These hedging arrangements have the effect of locking in for specified periods(at predetermined 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's exposure to changes in price associated with thehedged commodity, they also limit the benefit the Partnership might otherwisehave received from price changes associated with the hedged commodity.  ThePartnership's policy prohibits the use of natural gas future and optioncontracts for speculative purposes.

     

The following tables summarize the open futuresand 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

2,389

6.63

15,849

(909)

Natural Gas

Floors

65,692

4.79

-    

7,528 

Natural Gas

Ceilings

32,846

5.73

-    

(29,933)

Contracts  maturing in 12 months following December 31, 2004 

 Natural Gas

Purchase

2,389

6.63

15,849

(909)

Natural Gas

Floors

65,692

4.79

-    

7,528 

Natural Gas

Ceilings

32,846

5.73

-    

(29,933)

Prior Year  Total Contracts as of December 31, 2003

Natural Gas

Sale

3,793

5.40

20,480

(2,840)

Natural Gas

Purchase

3,251

4.77

15,506

2,158 

Natural Gas

Floors

60,682

4.12

-    

652 

Natural Gas

Ceilings

49,304

5.55

-    

(8,770)

The maximum term over which the Partnership ishedging exposure to the variability of cash flows for commodity price risk is12 months. 

F-12

PDC 1996-D LIMITEDPARTNERSHIP

(A West Virginia LimitedPartnership)

Notes to FinancialStatements, Continued

(6)    CostsRelating to Oil and Gas Activities

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

December 31,

  2004  

  2003  

  2002  

Lease acquisition costs

$   535,823 

   535,823 

   535,823 

Intangible development costs

13,632,238 

13,632,238 

13,632,238 

Well equipment

2,452,567 

2,452,567 

2,452,567 

Impairment charge

(9,688,575)

(9,688,575)

(9,688,575)

Capitalized asset retirement cost

    20,902  

    20,902 

           -    

$6,952,955  

6,952,955 

6,932,053 

There were no costs incurred for the Partnership'soil and gas activities for the years ended December 31, 2004, 2003 and 2002.

(7)    IncomeTaxes

As a result of the differences in the treatment ofcertain items for income tax purposes as opposed to financial reportingpurposes, primarily depreciation, depletion and amortization of oil and gasproperties and the recognition of intangible drilling costs as an expense orcapital item, the income tax basis of oil and gas properties differs from thebasis used for financial reporting purposes. At December 31, 2004 and 2003, the income tax basis of the partnership's oil and gas properties was $698,451 and $813,228,respectively.

(8)    SupplementalReserve Information (Unaudited)

Proved oil and gas reserves of the Partnershiphave been estimated by the Managing General Partner's petroleum engineers.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

 
Proved developed reserves:

Beginning  of year

3,926,000 

4,098,000 

3,883,000 

 
Revisions  of previous estimates

441,000 

89,000 

494,000 

 
Production

(241,000)

(261,000)

(279,000)

 
End of  year

4,126,000 

3,926,000 

4,098,000 

 
(9)    Standardized Measure ofDiscounted Future Net Cash Flows and Changes Therein Relating to Proved Oil

                and Gas Reserves(Unaudited)

Summarized in the following table isinformation for the Partnership with respect to the standardized measure ofdiscounted future net cash flows relating to proved oil and gas reserves. Future cash inflows are computed by applying year-end prices of oil and gasrelating to the Partnership proved reserves to the year-end quantities of thosereserves.  Future production, development, site restoration and abandonmentcosts are derived based on current costs assuming continuation of existingeconomic conditions. 

F-13

PDC 1996-D LIMITEDPARTNERSHIP

(A West Virginia LimitedPartnership)

Notes to FinancialStatements, Continued

As of  December 31,

2004

2003

2002

Future estimated revenues

$ 26,620,000 

 21,670,000 

16,720,000 

Future estimated production costs

(11,103,000)

(9,327,000)

(7,873,000)

Future estimated development costs

(404,000)

(404,000)

(404,000)

    Future net cash flows

15,113,000 

11,939,000 

8,443,000 

10% annual discount for estimated timing of cash flows

(9,012,000)

(6,972,000)

(4,748,000)

Standardized measure of discounted future

   estimated net cash flows

$6,101,000 

4,967,000 

3,695,000 

The following table summarizes theprincipal sources of change in the standardized measure of discounted futureestimated net cash flows:

Years Ended December 31,

2004

2003

2002

Sales of oil and gas production, net of production  costs

$(877,000)

(768,000)

(320,000)

Net changes in prices and production costs

2,711,000 

4,081,000 

4,074,000 

Revisions of previous quantity estimates

1,341,000 

183,000 

529,000 

Accrection of discount

(2,040,000)

(2,224,000)

(2,783,000)

$1,135,000 

1,272,000 

1,500,000 

It is necessary to emphasize that thedata presented should not be viewed as representing the expected cash flowsfrom, or current value of, existing proved reserves since the computations arebased on a large number of estimates and arbitrary assumptions.  Reservequantities cannot be measured with precision and their estimation requires manyjudgmental determinations and frequent revisions.  The required projection ofproduction and related expenditures over time requires further estimates withrespect to pipeline availability, rates of demand and governmental control. Actual future prices and costs are likely to be substantially different fromthe current prices and costs utilized in the computation of reported amounts. Any analysis or evaluation of the reported amounts should give specificrecognition to the computational methods utilized and the limitations inherenttherein.

F-14 |
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