CONFORMED COPY

SECURITIES ANDEXCHANGE COMMISSION

Washington, D.C.  20549

FORM10-K

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

  THESECURITIES EXCHANGE ACT OF 1934

  Forthe fiscal year ended December 31, 2004

  CommissionFile Number  000-50227

[]TransitionReport Pursuant to Section 13 or 15(d) of the Securities

 ExchangeAct of 1934 for the transaction period from         to          

PDC 2002-B LIMITEDPARTNERSHIP

(Exact name ofregistrant as specified in its charter)

|   West Virginia          

(State or other  jurisdiction of

incorporation or  organization) |   38-3648762    

(I.R.S. Employer 

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

103 East Main Street, Bridgeport, West Virginia  26330

(Address ofprincipal executive offices)     (zip code)

Registrant's telephonenumber, 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  X    No     

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

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

There is no tradingmarket for the registrant's securities.

PART I

ITEM 1.  BUSINESS.

General

     PDC 2002-B LimitedPartnership ("the Partnership") is a limited partnership formed on September 9, 2002 pursuant to the West Virginia Uniform Limited Partnership Act. Petroleum Development Corporation ("PDC") serves as Managing GeneralPartner of the Partnership.

     Since the commencement ofoperations on September 9, 2002, the Partnership has been engaged in onshore,domestic oil and natural gas exploration exclusively in the Rocky MountainRegion.  A total of 7 limited partners contributed initial capital of $430,000and a total of 521 additional general partners contributed initial capital of $10,750,426and PDC (Managing General Partner) contributed $2,431,743 in capital as aparticipant in accordance with contribution provisions of the LimitedPartnership Agreement (the Agreement). During 2003 in accordance with thePartnership Agreement, all Additional General Partners were converted toLimited Partners.

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

|                                                | Allocation

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

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

     Operating and direct costsare allocated and charged to the additional general and limited partners andthe Managing General Partner in the same percentages as revenues areallocated.  Leasehold, drilling and completion costs, and equipment costs areborne 80% by the Additional General and 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 has no employees;however, PDC has approximately 120 employees which include a staff of geologists,petroleum engineers, landsmen and accounting personnel who administer all ofthe partnership's operations.

Plan of Operations

     The Partnershipparticipated in the drilling of fourteen gross (12.79 net) wells and willcontinue to operate and produce its fourteen gross productive wells.  ThePartnership does not have unexpended initial capital and no additional drillingactivity 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 the Partnershipwells to and the capacity of natural gas pipelines, the availability and priceof competitive fuels, fluctuations in seasonal supply and demand, andgovernment regulation of supply and demand created by its pricing andallocation restrictions.  Oversupplies of gas can be expected to occur fromtime to time and may result in the Partnership's wells being shut-in orcurtailed.  Increased imports of oil and natural gas have occurred and areexpected to continue. The effects of such imports could adversely impact themarket for domestic oil and natural gas. All oil and natural gas is sold undercontracts based on market sensitive indexes that vary from month to month. Nofixed price contracts are in place. The Partnership sold oil and natural gas toseveral entities of which three customers accounted for 22.9%, 54.4% and 22.7%of the Partnership's total oil and natural gas sales for the year ended December 31, 2004 and 24.4%, 42.0% and 33.6% for the year ended 2003, respectively. 

2

Derivatives and Hedging Activities

     The Managing General Partner, through itssubsidiary Riley Natural Gas, has been in the gas marketing business since1986. During that time period, the Managing General Partner has utilized andcontinues to utilize commodity based derivativeinstruments as hedges to manage a portion of the Partnership's exposure toprice volatility stemming from natural gas production.  These instrumentsconsist of NYMEX-traded natural gas futures and option contracts for eastern Colorado production, and CIG (Colorado Interstate Gas Index)-based contracts for other Colorado production and NYMEX traded oil futures and option contracts for Colorado oilproduction.  The contracts hedge committed and anticipated natural gas sales,generally forecasted to occur within the next 2 year period. The ManagingGeneral Partner does not hold or issue derivatives for trading or speculativepurposes and permits utilization of hedges only if there is an underlyingphysical position.  See "Commodity Price Risk" under item 7A.

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

 

Competition

     The Partnership competes inmarketing its gas and oil with numerous companies and individuals, many ofwhich have financial resources, staffs and facilities substantially greaterthan 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 $1,934, $3,000, and $63,900 in 2004, 2003 and 2002, respectivelyto comply with federal and state regulations.

Federal Regulations

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

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

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

     Proposed Regulation. Numerous proposals concerning energy are being considered by the United StatesCongress, various state legislatures and regulatory agencies.  The possible outcomeand effect of these proposals cannot be accurately predicted.

     Environmental and SafetyRegulation.  The Partnership believes that it complies, in all materialrespects, with all legislation and regulations affecting its operations in thedrilling and production of oil and gas wells and the discharge of wastes.  Todate, compliance with such provisions and regulations has not had a materialeffect upon the Partnership's expenditures for capital equipment, itsoperations or its competitive position.  The cost of such compliance is notanticipated to be material in the future.

3

ITEM 2.  PROPERTIES.

Drilling Activity

     The following table sets forth theresults of the Partnership's drilling activity from September 9, 2002 (date of inception) to December 31, 2004.  All of the Partnership's wells drilled andproducing are located in Colorado.

|                                         Development  Wells                                                                   |
|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
|                 Gross Wells                                                                                                                                                                                                                                                                                                                                                                                                                        |                Net Wells                                           |
| Productive                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                     | Dry | Total | Productive | Dry | Total |
| 14                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                             | - | 14 | 12.79 | - | 12.79 |

     The Partnership has notparticipated in any exploratory wells.  No additional drilling activity isplanned.

Production 

See "Management's Discussion and Analysis" onpage 5 for Partnership production. 

Reserves

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

Productive Wells

     As outlined in the abovetable, the Partnership has a total of 14  gross productive wells (12.79 netwells) all of which are located in Colorado.

     A "productivewell" is a well producing, or capable of producing, oil and gas incommercial quantities.  For purposes of the above table, a "grosswell" is one in which the Partnership has a working interest and a"net well" is a gross well multiplied by the Partnership's workinginterest to which it is entitled under its drilling agreement.

Title to Properties

     The Partnership's interestsin producing acreage are in the form of assigned direct interests in leases.Such properties are subject to customary royalty interests generally contractedfor in connection with the acquisition of properties and could be subject toliens incident to operating agreements, liens for current taxes and otherburdens.  The Partnership believes that none of these burdens materiallyinterfere with the use of such properties in the operation of the Partnership'sbusiness.

     As is customary in the oiland gas industry, little or no investigation of title is made at the time ofacquisition of undeveloped properties (other than a preliminary review of localmineral records).  Investigations are generally made, including in most casesreceiving a title opinion of legal counsel, before commencement of drillingoperations.  A thorough examination of title has been made with respect to allof the Partnership's producing properties and the Partnership believes that ithas generally satisfactory title to such properties.

ITEM 3.  LEGAL PROCEEDINGS.

     The Managing Generalpartner as driller/operator is not party to any legal action that it believes wouldhave a materially adverse affect on the Managing General Partner's orPartnership's business, financial condition, results of operation or liquidity.

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

     NON-APPLICABLE

4

 

PART II

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

     At December 31, 2002, PDC 2002-BLimited Partnership had one Managing General Partner and a total of 7 LimitedPartners who paid for 21.5 units at $20,000 per unit of limited partnershipinterest, a total of 521 Additional General Partners who paid for 537.52 unitsat $20,000 per unit of additional general partnership interests.  During 2003in accordance with the Partnership Agreement, all Additional General Partnerswere converted to Limited Partners. At December 31, 2004, the Partnership had one Managing General Partner and 528 limited partners who paid for 559.02 units at$20,000 per unit. No established public trading market exists for theinterests.

     Limited and additionalgeneral partnership interests are transferable; however no assignee of aninterest 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 selected financial datapresented below has been derived from audited financial statements of thePartnership appearing elsewhere herein.

|                                                                    | Year Ended

December31,2004 | Year Ended

December 31,2003 |   |     Period from

 September 9, 2002

(date of inception) to

  December 31, 2002 |
|--------------------------------------------------------------------|-----------------------------|------------------------------|--------|-----------------------------------------------------------------------------------------------------------|
| Oil and Gas Sales                                                  | $2,281,199             | $2,929,055              |        | $182,705                                                                                             |
| Costs and Expenses                                                 | 1,600,743              | 2,144,741               |        | 427,857                                                                                              |
| Cumulative effect  of change in accounting principle               | -       | (647)                        |        | -                                                                                     |
| Net income (loss)                                                  | 681,454                | 784,334                 |        | (237,221)                                                                                                 |
| Allocation of Net income (loss):                                   |                             |                              |        |                                                                                                           |
|    Managing General Partner                         | 136,291                | 156,867                 |        | 8,458                                                                                                |
|    Limited and Additional General  Partners         | 545,163                | 627,467                 |        | (245,679)                                                                                                 |
|    Per Limited and Additional General  Partner Unit | 975                    | 1,122                   |        | (439)                                                                                                     |
| Total Assets                                                       | 9,739,838              | 10,996,652              |        | 12,214,343                                                                                           |
| Cash Distributions:                                                |                             |                              |        |                                                                                                           |
|    Managing General Partner                         | 394,447                | 401,792                 |        | -                                                                                          |
|    Limited and Additional General  Partners    | 1,577,787              | 1,607,169               |        | -                                                                                          |

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

Liquidity and Capital Resources

     ThePartnership was funded on September 9, 2002 with initial Limited and AdditionalGeneral Partner contributions of $11,180,426 and the Managing General Partner'scash contribution of $2,431,743 in accordance with the Agreement.  Afterpayment of syndication costs of $1,173,945 and a one-time management fee to themanaging general partner of $279,511 the Partnership had available cash of$12,158,713 for Partnership activities.

     ThePartnership began exploration and development activities subsequent to thefunding of the Partnership and completed these activities by December 31, 2002. Fourteen wells have been drilled, all of which have been completed asproducers.  No additional wells will be drilled.

     The Partnership had networking capital at December 31, 2004 of $356,226.

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

5

 

 

 

Results of Operations

2004 Results Compared to 2003 

     Oil and gas sales for the year ended December 31, 2004 were $2,281,199 compared to $2,929,055 for the year ended December 31, 2003.  For the year ended December 31, 2004, the Partnership sold 352,139 Mcfof gas and 14,814 barrels of oil at average sales prices of $4.89 and $37.68,respectively.  This compared with 535,506 Mcf of gas and 27,557 barrels of oilsold at average sales prices of $3.92 and $30.21, respectively for the yearended December 31, 2003. Lifting cost per Mcfe in 2004 amounted to $1.06 ascompared to $0.68 for 2003. Depreciation,depletion and amortization decreased from $1,652,547 for the year ended December 31, 2003 to $1,120,305 for the year ended December 31, 2004.  Cash distributions to the partners amounted to $1,972,234 in 2004.

     

2003 Results Compared to 2002

     Oiland gas sales for the year ended December 31, 2003 were $2,929,055 compared to $182,705 for the period ended December 31, 2002.  For the year ended December 31, 2003, the Partnership sold 535,506 Mcf of gas and 27,557 barrels ofoil at average sales prices of $3.92 and $30.21, respectively.  This comparedwith 17,514 Mcf of gas and 4,538 barrels of oil sold at average sales prices of$3.35 and $27.33, respectively for the period ended December 31, 2002. Lifting cost per Mcfe in 2003 amounted to $0.68 as compared to $0.70 for 2002. Depreciation, depletion and amortization increasedfrom $103,284 for the period ended December 31, 2002 to $1,652,547 for the year ended December 31, 2003 as a result of higher volumes of natural gas and oilsold. Cash distributions to the partners amounted to $2,008,961 in 2003.

The Partnership's revenues from oil and natural gas saleswill be affected by changes in prices.  As a result of changes in federalregulations, gas prices are highly dependent on the balance between supply anddemand. The Partnership's gas sales prices are subject to increase and decreasebased on various market sensitive indices.

 

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. In applyingthose policies, our management uses its judgment to determine the appropriateassumptions to be used in the determination of certain estimates. Thoseestimates are based on our historical experience, our observance of trends inthe industry, and information available from other outside sources, asappropriate. For a more detailed discussion on the application of these andother accounting policies, see "Note 1 - Summary of significant accountpolicies" in our financial statements and related notes. The Partnership'scritical accounting policies and estimates are as follows:

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.

6

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 in theoil industry.

Accounting forDerivatives Contracts at Fair Value

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

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

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

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

Use of Estimates inLong-Lived Asset Impairment Testing

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

Oil and Gas Properties 

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

       

     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 is basedon estimated fair value which would consider future discounted cash flows.

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

7

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 $5,579 and a related liability of $6,226 (usinga 6% discount rate) and a cumulative effect of change in accounting principleon prior years of $647.

Item 7 A.  Quantitative and QualitativeDisclosure about Market Risk.

Market-Sensitive Instruments and Risk Management

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

Commodity Price Risk

     The Managing General Partner utilizescommodity-based derivative instruments as hedges to manage a portion of itsexposure to price risk from its oil and natural gas sales.  These instrumentsconsist of CIG-based contracts traded by JP Morgan for Colorado 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 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 tablessummarize the open futures and options contracts for the Partnership as of December 31, 2004 and 2003.

| Commodity                                                   | Type     | Quantity    | Weighted | Total                     | Fair                      |
|-------------------------------------------------------------|----------|-------------|----------|---------------------------|---------------------------|
|                                                             |          | Gas-Mmbtu   | Average  | Contract                  | Market                    |
|                                                        |     | Oil-Barrels | Price    | Amount                    | Value                     |
| Total Contracts as of December 31, 2004                     |
|  Natural  Gas                                          | Floors   | 147,487     | 3.85     | -     | 26,055               |
| Natural  Gas                                                | Ceilings | 73,744      | 5.05     | -     | (58,866)                  |
| Oil                                                         | Floors   | 8,312       | 32.30    | 268,483                   | 7,082                |
| Oil                                                         | Ceilings | 4,156       | 40.00    | 166,243                   | (22,481)                  |
|                                                             |          |             |          |                           |                           |
| Contracts maturing in 12 months following December 31, 2004 |
| Natural  Gas                                                | Floors   | 147,487     | 3.85     | -     | 26,055               |
| Natural  Gas                                                | Ceilings | 73,744      | 5.05     | -     | (58,866)                  |
| Oil                                                         | Floors   | 8,312       | 32.30    | 268,483                   | 7,082                |
| Oil                                                         | Ceilings | 4,156       | 40.00    | 166,243                   | (22,481)                  |
|                                                             |          |             |          |                           |                           |
| 8

Prior Year Total Contracts as of December 31, 2003       |
| Natural  Gas                                                | Floors   | 88,874      | 3.28     | -     | -     |
| Natural  Gas                                                | Ceilings | 88,874      | 4.84     | -     | (1,354)                   |

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

ITEM 9.  CHANGES IN AND DISAGREEMENTS WITHACCOUNTANTS 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 9B.  OTHERINFORMATION

 

NONE

 

 

 

 

9

 

 

 

 

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THEREGISTRANT.

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

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

ITEM 11.  EXECUTIVE COMPENSATION.

        NON-APPLICABLE.

ITEM 12.  SECURITY OWNERSHIP OF CERTAIN 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 years ended December 31, 2004, 2003 and  the period from September 9, 2002 (date of inception) to December 31, 2002.

|                               | 2004                                      |    | 2003                                     | 2002    |
|-------------------------------|----------------------------------------------------------|--------------|---------------------------------------------------------|-------------------|
| Drilling and completion costs | $    -      |              |     -      | 12,158,713        |
| Lifting costs                 | 469,338                                                  |              | 479,974                                                 | 31,516            |
| Syndication cost *            | -                                    |              | -                                   | 1,173,945         |
| Management fee                | -                                    |              | -                                   | 279,511           |
| Tax return preparation        | 4,925                                                    |              | 4,938                                                   | 3,600             |
| Direct administrative cost    | 1,958                                                    |              | 2,241                                                   | 2,206             |

* Consists of broker dealer commission paid to PDC SecuritiesIncorporated (100% subsidiary of the Managing General Partner and Dealer Managerof the drilling program) which was reallowed or paid to the Soliciting BrokerDealers of the drilling program.

ITEM 14.  PRINCIPAL ACCOUNTANT FEES ANDSERVICES 

     For the years endedDecember 31, 2004 and 2003 the Partnership paid  KPMG LLP $3,413 and $3,314,respectively for professional services for the audit of the Partnership'sfinancial statements in its Form 10-K and review of the financial statementsincluded in the Partnership's Form 10-Qs. In the year 2002, KPMG LLP providedincome tax services in the amount of $1,000. 

 

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 authorized membersof the Committee. The Partnership does not have an Audit Committee; theManaging General Partner's Audit Committee also serves for the Partnership. The Audit Committee has adopted policies and procedures for pre-approval of allaudit services and non-audit services to be provided by the Partnership'sindependent accountants. Services necessary to conduct the annual audit must bepre-approved by the Audit Committee or by the authorized Audit Committeemember. 

 

 

10

 

 

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

                            (1)       FinancialStatements

                                        See Index toFinancial Statements on F-2

                            (2)       Financial StatementSchedules

                                SeeIndex to Financial Statements on page F-2.  All financial statement schedulesare omitted because they are not required, inapplicable, or the information isincluded in the Financial Statements or Notes thereto.

                            (3)        Exhibits

| 4.1  | Form  of Limited Partnership Agreement (incorporated by reference to Appendix A to  Form S-1, SEC File No. 333-47622, and Rule 424 final prospectus, dated May 16, 2002, of PDC 2003 Drilling Program, filed with the SEC on May 21, 2002).       |
|------|---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| 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 2002-B Limited Partnership

By its Managing General Partner

Petroleum Development Corporation

 
By /s/ Steven R. Williams      

   Steven R. Williams, Chairman

April 14, 2005

     Pursuant to therequirements of the Securities Exchange Act of 1934, this report has 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 14, 2005

/s/ Darwin L. Stump 

    Darwin L. Stump

Chief Financial Officer and Treasurer

(principal financial and accounting officer)

April 14, 2005

 

/s/ Thomas E. Riley 

    Thomas E. Riley

President and Director

April 14, 2005

/s/ Donald B. Nestor

    Donald B. Nestor

Director

April 14, 2005

/s/ Vincent F. D'Annunzio

    Vincent F. D'Annunzio

Director

April 14, 2005

12

PDC 2002-B 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 

Period from September 9, 2002 (Date of Inception)

to December 31, 2002

(With Independent Registered Public Accountng Firm'sReport Thereon)

F-1

PDC 2002-B 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 

  Period from September 9, 2002 (Date of Inception) to December 31, 2002

  F-5

Statements of Partners' Equity and Comprehensive Income  (Loss) -

Years Ended December 31, 2004, 2003 and 

  Period from September 9, 2002 (Date of Inception) to December 31, 2002

  F-6

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

  Period from September 9, 2002 (Date of Inception) to December 31, 2002

  F-7

Notes to Financial Statements

F-8

All financial statement schedules have been omittedbecause they are not applicable or not required or the required information isshown in the financial statements or notes thereto.

F-2

Reportof Independent Registered Public Accounting Firm

To the Partners

PDC 2002-BLimited Partnership:

Wehave audited the accompanying balance sheets of PDC 2002-B Limited Partnership(a West Virginia limited partnership) as of December 31, 2004 and 2003, and therelated statements of operations, partners' equity and comprehensive income(loss), and cash flows for the years ended December 31, 2004 and 2003, and forthe period from September 9, 2002 (date of inception) to December 31, 2002.These financial statements are the responsibility of the Partnership'smanagement. Our responsibility is to express an opinion on these financialstatements based on our audits.

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

Inour opinion, the financial statements referred to above present fairly, in allmaterial respects, the financial position of PDC 2002-B Limited Partnership asof December 31, 2004 and 2003, and the results of its operations and its cashflows for the years ended December 31, 2004 and 2003, and for the period fromSeptember 9, 2002 (date of inception) to December 31, 2002, in conformity withU.S. generally accepted accounting 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. 

                                                                                                                                                                    KPMGLLP

Pittsburgh, Pennsylvania 

April 15, 2005

F-3

PDC 2002-B LIMITEDPARTNERSHIP

(A West VirginiaLimited Partnership)

Balance Sheets

December 31, 2004 and 2003

Assets

 

 

 

 

 

Current assets:

2004

2003

  Cash

 $   1,889

 961

  Accounts receivable - oil and gas revenues

449,793

587,230

          Total  current assets

451,682

588,191

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

12,164,586

12,164,586

          Less  accumulated depreciation, depletion and amortization

2,876,430

1,756,125

9,288,156

10,408,461

$9,739,838

10,996,652

 

 

Liabilities and Partners' Equity

Current liabilities:

  Accrued expenses

$95,456

15,030

          Total  current liabilities

95,456

15,030

Asset retirement obligation

6,996

6,600

 

 

Partners' equity

9,637,386

10,975,022

$9,739,838

10,996,652

See accompanying notes to financial statements.

F-4

PDC 2002-B LIMITEDPARTNERSHIP

(A West VirginiaLimited Partnership)

Statements ofOperations

Years Ended December31, 2004, 2003 and

Period from September 9, 2002 (Date of Inception) to December 31, 2002

2004

 

2003

 

2002

Revenues:

  Sales of oil and gas

$2,281,199 

2,929,055 

182,705 

  Interest income

          998 

 

       667 

    7,931 

2,282,197 

2,929,722 

190,636 

Expenses (note 3):

  Management fee

-    

-    

279,511 

  Lifting costs

469,338 

479,974 

31,516 

  Independent engineering fee

408 

1,353 

3,000 

  Independent audit fee

3,413 

3,314 

3,740 

  Tax return preparation

4,925 

4,938 

4,600 

  Direct administrative cost

2,354 

2,615 

2,206 

  Depreciation, depletion and amortization

1,120,305 

 

1,652,547 

103,284 

1,600,743 

 

2,144,741 

427,857 

Income (loss) before cumulative effect of 

    change in accounting principle

681,454 

784,981 

(237,221)

Cumulative effect of change in accounting principle

     -      

 

   (647)

        -     

  Net income (loss) 

$ 681,454 

 784,334 

 (237,221)

 

 

  Net income (loss) per limited and  additional 

    general partner unit before  cumulative effect of 

    change in accounting principle

  $        975 

          1,123 

      (439)

 

 

Cumulative effect of change in accounting principle

         -    

 

      (1)

        -    

 

 

 

 

 

Net income (loss) per limited and additional                 general  partner unit

  $        975 

      1,122 

       (439)

See accompanying notes to financial statements.

F-5

PDC 2002-B LIMITED PARTNERSHIP

(A West VirginiaLimited Partnership)

Statements ofPartners' Equity

And otherComprehensive Income (Loss)

Years Ended December31, 2004, 2003 and 

Period from September 9, 2002 (Date of Inception) to December 31, 2002

Limited 

Partners       

Managing 

General 

Partner     

Accumulated

Other

Comprehensive
Income (Loss)  
 

          Total     

Partners' initial  capital contributions

$11,180,426 

$2,431,743 

          -          

$13,612,169 

Syndication costs

(1,173,945)

-    

(1,173,945)

Net income (loss)

(245,679)

8,458 

          -         

(237,221)

 

 

 

Balance December 31, 2002

9,760,802 

2,440,201 

          -    

12,201,003 

 

 

 

Distribution to partners

(1,607,169)

(401,792)

(2,008,961)

Comprehensive  income:

 

 

 

Net income

627,467 

156,867 

 

784,334 

Change in fair  value of  outstanding 

 hedging   positions

 

(1,354)

 

Reclassification  adjustment  for settled 

 contracts  included in net income

 

          -          

 

Other  comprehensive income (loss)

 

(1,354)

    (1,354)

Comprehensive  income

                      

                  

                    

 782,980 

 

 

 

Balance December 31, 2003

$8,781,100

  2,195,276 

    (1,354)

 10,975,022 

Distribution to  partners

(1,577,787)

(394,447)

(1,972,234)

Comprehensive  income:

 

 

 

Net income

545,163 

136,291 

 

681,454 

Change in fair  value of  outstanding 

 hedging   positions

 

(109,056) 

 

Reclassification  adjustment  for settled 

 contracts  included in net income 

 

       62,200     

 

Other  comprehensive income (loss)

 

(46,856)

  (46,856)

Comprehensive  income

                  

                  

                  

 634,598 

 

 

 

Balance December 31, 2004

$7,748,476

  1,937,120 

    (48,210)

 9,637,386 

See accompanyingnotes to financial statements.

F-6

PDC 2002-B LIMITEDPARTNERSHIP

(A West VirginiaLimited Partnership)

Statements of CashFlows

Years Ended December31, 2004, 2003 and 

Period from September 9, 2002 (Date of Inception) to December 31, 2002

2004  

 

2003  

  

2002  

Cash flows from operating activities:

     Net income (loss)

$681,454 

784,334 

(237,221)

     Adjustments to reconcile  net income (loss) to 

      net cash provided  from operating activities:

         Depreciation,  depletion and amortization

1,120,305 

1,652,547 

103,284 

         Cumulative  effect of accounting change

-     

647 

-    

         Accretion  of asset retirement obligation

396 

374 

-    

         Changes  in operating assets and liabilities:

          Decrease (increase) in accounts receivable - oil & gas revenues

170,574 

(436,041)

(151,189)

         Increase  in accrued expenses

    433 

 

     336 

13,340 

               Net  cash provided from (used by) operating activities

1,973,162 

 

2,002,197 

(271,786)

Cash flows from investing activities:

     Expenditures for oil and  gas properties

          -    

          -    

(12,158,713)

     Net cash used by  investing activities

          -    

          -    

(12,158,713)

Cash flows from financing activities:

     Limited and additional  general partner contributions

-    

-    

11,180,426 

     Managing General Partner  contribution

-    

-    

2,431,743 

     Syndication cost paid

-    

-    

(1,173,945)

     Distributions to partners

(1,972,234)

 

(2,008,961)

 

          -    

               Net  cash (used by) provided from financing activities

(1,972,234)

 

(2,008,961)

 

12,438,224  

Net (decrease) increase in cash

928 

(6,764)

7,725 

Cash at beginning of period

           961 

 

7,725 

      -    

Cash at end of period

$        1,889 

     961 

      7,725 

See accompanying notes to financial statements.

F-7

PDC 2002-B LIMITEDPARTNERSHIP

(A West VirginiaLimited Partnership)

Notes to FinancialStatements

December 31, 2004

(1)    Summary of SignificantAccounting 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 2002-B Limited Partnership(the Partnership).  The statements do not include any assets, liabilities,revenues or expenses attributable to any of the partners' other activities.

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, 2003 and 2002 by an independent petroleum engineer, Wright& Company, Inc.  At December 31, 2004, the estimated proved developedreserves were determined by the Managing General Partner's petoleum engineers. If a determination is made that an exploratory well has not discoveredeconomically producible reserves, then its costs are expensed as dry holecosts.

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

Revenue Recognition

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

The Managing General Partner currentlyuses the "Net-Back" method of accounting for transportation arrangements ofnatural gas sales.  The Managing General Partner sells gas at the wellhead 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 

(Continued)

F-8

PDC 2002-B LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Notes to Financial Statements, Continued

produce under existing sales contractswith petroleum refiners and marketers.  The Partnership does not refine any ofits oil production.  The Partnership's crude oil production is sold topurchasers at or near the Partnership's wells under short-term purchasecontracts at prices and in accordance with arrangements that are customary inthe oil industry. 

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 CIG (Colorado Interstate Gas Index). Thecostless collars and option contracts hedge committed and anticipated naturalgas sales generally forecasted to occur within a 24 month period. ThePartnership does not hold or issue derivatives for trading or speculativepurposes.

All derivatives arerecognized on the Partnership 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 designated as a hedging instrument, because it is probablethat a forecasted transaction will not occur, or the Partnership determinesthat designation of the derivative as a hedging instrument is no longerappropriate, hedge accounting will be discontinued.

By using derivative financial instruments to hedge exposuresto changes in commodity prices, the Managing General Partner exposes thePartnership to credit risk. Credit risk is the failure of the counterparty toperform under the terms of the derivative contract. When the fair value of aderivative contract is positive, the counterparty owes the Partnership, whichcreates credit risk. The Managing General Partner minimizes the credit risk inderivative instruments by entering into transactions with high-qualitycounterparties.

F-9

PDC 2002-B LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Notes to Financial Statements, Continued

 

 

Use of Estimates

The Partnership hasmade a number of estimates and assumptions relating to the reporting of assetsand liabilities and revenues and expenses and the disclosure of contingentassets and liabilities to prepare these financial statements in conformity withaccounting principles generally accepted in the United States of America.Actual results could differ from those estimates. Estimates which areparticularly significant to the financial statements include estimates of oiland gas reserves and future cash flows from oil and gas properties which areused in assessing impairment of long-lived assets.

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 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 $5,579 and a related liability of $6,226(using a 6% discount rate) and a cumulative effect of change in accountingprinciple on prior years of $647.

(2)    Organization

The Partnership wasorganized as a limited partnership on September 9, 2002, in accordance with the laws of the State of West Virginia for the purpose of engaging in thedrilling, completion and operation of oil and gas development and exploratorywells in the Rocky Mountain Region.

Purchasers ofpartnership units subscribed to and fully paid for 21.5 units of limitedpartner interest and 537.52 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 partnerinterests in the Partnership.

In accordance withthe terms of the Limited Partnership Agreement (the Agreement), the ManagingGeneral Partner manages all activities of the Partnership and acts as theintermediary for substantially all Partnership transactions.

(3)    Transactions with ManagingGeneral Partner 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 and 2003 and period from September 9, 2002 (date of inception) to December 31, 2002.

F-10

PDC 2002-B LIMITED PARTNERSHIP

(A West VirginiaLimited Partnership)

Notes to FinancialStatements, Continued

  Year Ended

December 31, 2004

Year Ended

December 31, 2003

 

Period from

September 9, 2002

(date of  inception)  to

December 31,    2002

 
 
Drilling and  completion costs

$  -

$  -

12,158,713

 
Syndication cost*

-

-

1,173,945

 
Management fee

-

-

279,511

 
Lifting costs

469,338

479,974

31,516

 
Tax return  preparation

4,925

4,938

3,600

 
Direct  administrative cost

1,958

2,241

2,206

* Consists of brokerdealer commission paid to PDC Securities Incorporated (100% subsidiary of theManaging General Partner and Dealer Manager of the drilling program) which wasreallowed or paid to the Soliciting Broker Dealers of the drilling program.

 (4)     Allocation

Thetable below summarizes the participation of the Managing General Partner andthe Investor Partners, taking account of the Managing General Partner's capitalcontribution equal to a minimum of 20% of the initial capital, in the costs andrevenues of the Partnership.

  Partnership Costs

          Investor

        Partners(5)(6)

        Managing

        General

        Partner  (5)(6)

Broker-dealer  Commissions and Expenses(1)

100%

 0%

Management Fee(2)

100%

 0%

Lease Costs

 0%

100%

Tangible Well  Costs

 0%

100%

Intangible  Drilling and Development Costs

100%

 0%

Total Drilling and  Completion Costs

80%

20%

Operating Costs(3)

80%

20%

Direct Costs(4)

80%

20%

Administrative  Costs

 0%

100%

Partnership  Revenues

Sale of Oil and Gas  Production

80%

20%

Sale of Productive  Properties

80%

20%

Sale of Equipment 

 0%

100%

Sale of Undeveloped Leases.  

80%

20%

Interest Income

80%

20%

____________________

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

F-11

PDC 2002-B LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Notes to Financial Statements, Continued

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

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

(4)   TheManaging General Partner receives monthly reimbursement from the Partnershipfor its 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)  Theallocation of profits, losses and cash distributions of the Managing GeneralPartner might be increased, and the allocation of profits, losses, and cashdistributions of the Investor Partners might be decreased in the event that theManaging General Partner were to invest more than the Managing GeneralPartner's minimum required Capital Contribution to cover tangible equipment andlease costs. The Managing General Partner will pay for the Partnership's shareof all Leases and tangible well equipment. The entire Capital Contribution ofthe Investor Partners, after payment of brokerage commissions, due diligencereimbursement, and the Management Fee, was utilized to pay for intangible drillingcosts. In the event that the Intangible Drilling Costs exceed the funds of theInvestor Partners available for payment of Intangible Drilling Costs (herein"excess IDC"), a portion of the Capital Contribution of the ManagingGeneral 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)  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 and 2003 there were no units purchased byPDC. 

(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 CIG-based contracts traded by JP Morgan for Colorado 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 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.

  

   F-12

PDC 2002-B LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Notes to Financial Statements, Continued

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

Commodity

Type

Quantity

Weighted  

Total

Fair

Gas-Mmbtu

Average

Contract

Market

 

 

Oil-Barrels

Price

Amount

Value

Total Contracts as of December 31, 2004

 Natural  Gas

Floors

147,487

3.85

-    

26,055 

Natural  Gas

Ceilings

73,744

5.05

-    

(58,866)

Oil

Floors  

8,312

32.30

268,483

7,082 

Oil

Ceilings

4,156

40.00

166,243

(22,481)

Contracts maturing in 12 months following December 31, 2004 

Natural  Gas

Floors

147,487

3.85

-    

26,055 

Natural  Gas

Ceilings

73,744

5.05

-    

(58,866)

Oil

Floors

8,312

32.30

268,483

7,082 

Oil

Ceilings

4,156

40.00

166,243

(22,481)

Prior Year Total Contracts as of December 31, 2003

Natural  Gas

Floors

88,874

3.28

-    

-    

Natural  Gas

Ceilings

88,874

4.84

-    

(1,354)

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 andGas Activities

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 acquisitions at cost

$414,114 

414,114 

414,114 

 
 
Intangible development costs

9,726,970 

9,726,970 

9,726,970 

 
 
Well equipment

2,017,629 

2,017,629 

 2,017,629 

 
 
Capitalized asset retirement cost

        5,873 

        5,873 

           -    

 
 
$12,164,586 

12,164,586 

12,158,713 

 
The following costswere incurred for the Partnership's oil and gas activities:

  Year Ended 

December 31, 2004

  Year Ended 

December 31, 2003

Period from April  30,

2002(date of  inception) to 

December 31, 2002

Costs incurred:

  Property  acquisition costs

$     -    

     -    

  414,114 

  Development  costs

     -    

     -    

11,744,599 

$     -    

     -    

12,158,713 

   F-13

PDC 2002-B LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Notes to Financial Statements, Continued

 (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 $1,158,513 and $1,456,272, respectively.

(8)    Supplemental ReserveInformation (Unaudited)

Proved oil and gasreserves of the Partnership have been estimated at December 31, 2004 by the Managing General Partner's petroleum engineers and at December 31, 2003 and 2002 by an independent petroleum engineer, Wright & Company, Inc. These reserveshave been prepared in compliance with the Securities and Exchange Commissionrules based on year end prices. A copy of the reserve report has been madeavailable to all partners. All of the partnership's reserves are proveddeveloped. 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

162,000  

144,000 

-    

Revisions of previous estimates

(1,000) 

46,000 

-    

New Discoveries and extensions

    Rocky Mountain Region

-    

-    

149,000 

Production

(15,000)

(28,000)

   (5,000)

End of Year

146,000 

162,000 

144,000 

Gas  (MCF)

2004

2003

2002

Proved developed reserves:

Beginning of year

3,830,000 

4,751,000  

-    

Revisions of previous estimates

(341,000)

 (385,000) 

-    

New Discoveries and extensions

     Rocky Mountain Region

-    

-    

4,769,000 

Production

(352,000)

(536,000)

(18,000)

End of Year

3,137,000 

3,830,000 

4,751,000 

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

        andGas Reserves (Unaudited)

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

F-14

PDC 2002-B LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Notes to Financial Statements, Continued

As of  December 31,

2004

2003

2002

 
Future estimated revenues

 $   24,552,000 

   25,911,000 

19,350,000 

 
Future estimated production costs

(6,688,000)

(6,375,000)

(3,475,000)

 
Future estimated development costs

(912,000)

(912,000)

(912,000)

 
Future net cash flows

16,952,000 

18,624,000 

14,963,000 

 
10%  annual discount for estimated timing of cash flows

(8,295,000)

(9,430,000)

(7,065,000)

 
Standardized measure of discounted future

 
   estimated net cash flows

$8,657,000 

9,194,000 

7,898,000 

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

Years  Ended December 31,

Period  from September 9, 2002 (date of 

inception  to 

December  31, 

 
2004

2003

2002

 
Sales of oil and gas production, net of  production costs

$(1,812,000) 

(2.449,000)

 (151,000)

Net changes in prices and production costs

1,493,000 

5,944,000 

-    

Extensions,  discoveries, and improved recovery,     less related cost

  -    

  -    

  15,114,000 

Revisions of previous quantity estimates

(1,353,000)

166,000 

-    

Accretion of discount

 1,135,000 

(2,365,000)

 

(7,065,000)

 $(537,000) 

  1,296,000 

7,065,000 

It isnecessary to emphasize that the data presented should not be viewed as representingthe expected cash flow from, or current value of, existing proved reservessince the computations are based on a large number of estimates and arbitraryassumptions.  Reserve quantities cannot be measured with precision and theirestimation requires many judgmental determinations and frequent revisions.  Therequired projection of production and related expenditures over time requiresfurther estimates with respect to pipeline availability, rates of demand andgovernmental control. Actual future prices and costs are likely to besubstantially 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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