UNITED STATES

SECURITIES AND EXCHANGECOMMISSION

Washington, D.C.  20549

FORM 10-K

ANNUAL REPORT 

PURSUANT TO SECTIONS 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACTOF 1934

                        (MarkOne)

[X]ANNUAL REPORT PURSUANT TO SECTION 13 or 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended **December31, 2005**

OR

[ ] TRANSITION REPORT PURSUANTTO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934 

Forthe transition period from                 to

CommissionFile Number  000-51218

**PDC 2004-A LIMITED PARTNERSHIP**

(Exact name of registrant asspecified in its charter)

|                                                                                                                                       |                                                                                    |
|---------------------------------------------------------------------------------------------------------------------------------------|------------------------------------------------------------------------------------|
|         West Virginia             |       20-0545296       |
| (State or other jurisdiction of                                                                                                       | (I.R.S. Employer                                                                   |
| incorporation or organization)                                                                                                        | Identification No.)                                                                |

 

103 East Main Street, Bridgeport, West Virginia  26330

(Address of principal executiveoffices)     (zip code)

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

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

SECURITIES REGISTERED PURSUANTTO SECTION 12(g) OF THE ACT:

General and Limited PartnershipInterest

(Title of class)

----

Indicate by check mark if the registrant is a well-knownseasoned issuer, as defined in Rule 405 of the Securities Act.  Yes      No   X  

Indicate by check mark if registrant is not required tofile reports pursuant to Section 13 or Section 15(d) of the Act. Yes      No   X  

Indicate by check mark whether the registrant (1) hasfiled all reports required to be filed by Section 13 or 15(d) of the SecuritiesExchange Act of 1934 during the preceding 12 months and (2) has been subject tosuch filing requirements for the past 90 days.  Yes        No    X      

Indicate by check mark if disclosure of delinquentfilers pursuant to Item 405 of Regulation S-K is not contained herein, and willbe contained, to the best of registrant's knowledge, in definitive proxy orinformation statements incorporated by reference in Part III of this Form 10-Kor any amendment to this Form 10-K.  [ X ]

Indicate by check mark whether the registrant is a largeaccelerated filer, an accelerated filer, or non-accelerated file. Seedefinition of "accelerated filer and larger accelerated filer" inRule 12b-2 of the Exchange Act. (Check one):

Large Accelerated Filer   [ ]                              AcceleratedFiler  [  ]                             Non-AcceleratedFiler [ X ]

Indicate by check mark whether the registrant is a shellcompany (as defined in Rule 12b-2 of the Exchange Act).  

Yes        No   X  

There is no trading marketfor the registrant's securities.

-2-

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**TABLE OF CONTENTS**

**PART I**

Item1        Business

Item1A     Risk Factors

Item1B      Unresolved Staff Comments

Item2        Properties

Item3        Legal Proceedings

Item4        Submission of Matters to a Vote of Security Holders

**PART II**

Item5        Market for Registrant's Common Equity and Related Stockholder Matters

Item6        Selected Financial Data

Item7        Management's Discussion and Analysis of Financial Condition andResults of Operations

Item7A     Quantitative and Qualitative Disclosures About Market Risk

Item8        Financial Statements and Supplementary Data

Item9        Changes in and Disagreement with Accountants on Accounting andFinancial Disclosure

Item9A     Controls and Procedures

Item9B      Other Information

**PART III**

Item10      Directors and Executive Officers of the Registrant

Item11      Executive Compensation

Item12      Security Ownership of Certain Beneficial Owners and Management andRelated Stockholders Matters

Item13      Certain Relationships and Related Transactions

Item14      Principal Accountant Fees and Services

**PART IV**

Item15      Exhibits and Financial Statement Schedules

Signatures

FinancialStatements

-3-

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**PART I**

**ITEM 1.  BUSINESS**

 

Restatement of HistoricalFinancial Statements

*Overview*

PetroleumDevelopment Corporation ("PDC" or the "Company") is the Managing GeneralPartner for PDC 2004-A Limited Partnership (the "Partnership").  The ManagingGeneral Partner manages all of the Partnership's exploration and productionactivities, accounting, and reporting requirements.  The Partnership has noemployees and all accounting and reporting has been performed by thePartnership's Managing General Partner and its staff.  For disclosures in thisForm 10-K, the management and officers of the Partnership refers to managementand officers of the Managing General Partner.

This Annual Report on Form 10-K for the year endedDecember 31, 2005, includes the financial statements of the Partnership for theyear ended December 31, 2005, and amends and restates the previously filedfinancial statements as of and for the period from April 30, 2004 (date ofinception) through December 31, 2004, and the financial statements for each ofthe quarters since inception in 2004 through the quarter ended March 31, 2005.  As previously announced in a Current Report on Form 8-K as filedwith the Securities and Exchange Commission ("SEC") on November 14, 2005, andAugust 24, 2005, and in an update included in Form 12b-25 filed with the SEC onApril 3, 2006, the Company identified that the Partnership's accounting forderivatives, asset retirement obligations and certain aspects of its accountingfor oil and gas properties, were accounted for improperly and needed to berestated. 

Inlight of this restatement, readers should no longer rely on our previouslyfiled financial statements and other financial information for 2004 and each ofthe quarters since inception in 2004 through the quarter ended March 31, 2005. 

Ourrestatement of the financial statements for the periods identified above ispresented in a comprehensive format within this Form 10-K for the year endedDecember 31, 2005, and in the financial statements included in Item 8"Financial Statements and Supplementary Data."  Substantially all of theinformation for the quarters and year-to-date periods ended June 30, 2005, andSeptember 30, 2005, that are normally contained in Quarterly Reports on Form10-Q have instead been incorporated and presented in this Form 10-K.  We intendto file our Form 10-Q reports for the quarters ended March 31, June 30, andSeptember 30, 2006, as soon as practicable after the filing of this Form 10-K. 

Thefollowing tables set forth a summary of the adjustments for the restatement andtheir impact on net income for the period from April 30, 2004 through December31, 2004, and for the three months ended March 31, 2005.

| This restatement resulted  in the following adjustments to Net Income: |                                                                                                                                                           |          |
|------------------------------------------------------------------------|-----------------------------------------------------------------------------------------------------------------------------------------------------------|----------|
|                                                                        | * *                                                                                                                                                  |          |  |  |  |
|                                                                        | * *                                                                                                                                                  |          |  |  | Period from |
|                                                                        |                                                                                                                                                           |          | Quarter |  | April 30, 2004 |
| Income / (expense)                                                     | Ended                                                                                                                                                     |          | (date of inception) to |
|                                                                        |                                                                                                                                                           |          | March 31, 2005 |  | December 31, 2004 |
|                                                                        |                                                                                                                                                           |          | (Unaudited) |  |  |
|                                                                        |                                                                                                                                                           |          |  |  |  |
| Depreciation, depletion and  amortization                              |  $                     (89,681)                       |          |  $                   (847,815) |
| Disqualification of the use  of hedge accounting                       |                       (903,715)                       |          |                      (121,012) |
| Asset retirement  obligations                                          |                           (1,735) |          |                           (1,300) |
| Net decrease in reported  net income                                   |  $                   (995,131)                                  |          |  $                   (970,127) |
|                                                                        |                                                                                                                                                           | * * |  |  |  |  
-4-

*Material Weaknesses andAccounting Issues*

ThePartnership has evaluated the effectiveness of the design and operation of itsdisclosure and control procedures.  During 2005, the Partnership determinedthat there were errors in previously filed financial statements which requireda restatement of the financial statements.  As a result of this review ofaccounting procedures and policies, the Partnership concluded that, as ofDecember 31, 2005, disclosure controls and procedures were not effective toensure that information required to be disclosed in the reports filed under theExchange Act are recorded, processed, summarized, and reported within the timeperiods specified in the SEC's rules and forms.  

During2005, the Partnership identified materialweaknesses related to its policies and procedures andtechnical expertise in U.S. generally accepted accounting principles to ensurethe preparation of accurate and reliable interim and annual financialstatements. Specifically, the Partnership lacked personnel with sufficient technicalaccounting and financial reporting expertise and also lacked policies andprocedures in place to determine and document the appropriate application ofaccounting principles. These deficiencies impacted the Partnership's accountingfor derivatives, asset retirement obligations and depreciation, depletion andamortization, and resulted in more than a remote likelihood that a materialmisstatement of the annual or interim financial statements would not beprevented or detected.  

Toaddress the material weaknesses, we performed additional analyses and otherpost-closing procedures to ensure that the financial statements were preparedin accordance with generally accepted accounting principles.  Accordingly,management of the Partnership believes that the financial statements includedin this report fairly present in all material respects the Partnership'sfinancial position, results of operations and cash flows for the periodspresented.  See Item 9A. "Controls and Procedures" for information concerning thesematerial weaknesses.

Foradditional information relating to the effect of our restatement, see thefollowing items:

          ●  Item 6.  Selected Financial Data

          ●  Item 7 and 7A.  Management's Discussionand Analysis of Financial Condition and Results of Operation

          ●  Item 8.  Financial Statements andSupplementary Data

General

The Partnership was organizedas a limited partnership pursuant to the West Virginia Uniform LimitedPartnership Act for the purpose of aggregating funds for the exploration and productionof oil and natural gas.  Business operations of the Partnership commenced onApril 30, 2004, upon the closing of the offering for the sale of thepartnership units. 

Pursuantto a registration statement filed with the Securities and Exchange Commission,limited and general partnership interests were registered for an offering underthe PDC 2004-2006 Drilling Program for the formation of a series of limitedpartnerships.  The Partnership was formed with total capital contributions of$29,030,865 from limited partners and additional general partners(collectively, the "Investor Partners") and $6,419,029 in capital contributedby the Managing General Partner. Total funding of the Partnership was $35,449,894. The capital contributions from the Investor Partners consisted of 1,451.54partnership units at a unit price of $20,000 each. After syndication costs of$2,919,286 and a one time management fee to the Managing General Partner of$435,463, the Partnership had available cash of $32,095,145 to commencePartnership activities for the drilling of natural gas and oil wells. During2005, all additional general partners were converted to limited partners underprovisions of the Partnership Agreement. 

Underthe terms of the Partnership Agreement, the allocation of production revenuesamong the Investor Partners and the Managing General Partner is as follows:

 Allocation 

of Revenues

Investor Partners

    80%

Managing General Partner

    20%

-5-

Operatingand direct costs are allocated and charged to the Investor Partners and theManaging General Partner in the same percentages as revenues are allocated. See "Note 4 - Allocation of Partners' Interests" in the Notes to the FinancialStatements for a complete description of the allocation of all Partnershiprevenues and costs.

Drilling Activities

Sinceits formation, the Partnership has been engaged in onshore, domestic oil andnatural gas exploration and production exclusively in the Rocky MountainRegion. The Partnership participated in drilling only development wells. Due tonatural gas being the predominant production, all wells are classified as gaswells although significant amounts of oil can be produced in association withthe gas.  The following table summarizes the Partnership's drilling activitiesduring 2004 related to its thirty-seven wells:

Wattenberg Field (DJ Basin)

Grand Valley Field  (Piceance Basin)

Total

Drilled, completed and  producing

26

11

37

 
Drilled but not completed

   -

   -

   -

 
Dry holes

   -

   -

   -

 
Totals

26

11

37

 
Thethirty-seven wells in the table above are the only wells the Partnership willdrill and all of the capital contributions provided by the partnership offeringwere utilized during 2004. 

Additional information concerning the Partnership'sgas wells is contained in "Item 2 - Properties" below.

Plan of Operations

Under agreement with the Investor Partners, the ManagingGeneral Partner serves as operator for the drilling of the Partnership's wellsand for the production and sale of natural gas and oil from the wells. Once producing, the Partnership's wells will beproduced until they are depleted or until they are uneconomical to produce. PDC plans to recomplete the Codell formation in most of the wells in theWattenberg Field after 5 or more years of production because these wells willusually have experienced a significant decline in production in that timeperiod.  These Codell recompletions typically increase the production rates andrecoverable reserves.  Prior experience of PDC and other producers with Codellrecompletions has resulted in significant production increases for most wells,although not all recompletions have been successful. The cost of aCodell recompletion is about one-third of the cost of a new well (currentlyabout $180,000).  The Managing General Partner will arrange for contractors toperform the work, the cost of which will be paid out of overall revenues of thePartnership.  PDC will pay its proportionate share of costs based on theoperating costs sharing ratios of the Partnership.

Employees

ThePartnership has no employees.  Services to the Partnership are provided by PDC,which has a total of approximately 170 employees including personnel inaccounting and finance, administration, engineering, geology, field operations,and natural gas marketing. 

Markets for Oil and Gas

Theavailability of a market for any oil and natural gas produced from theoperation of the Partnership's wells will depend upon a number of factorsbeyond the control of the Partnership which cannot be accurately predicted. These factors include the proximity of the Partnership wells to and thecapacity of natural gas pipelines, the availability and price of competitivefuels, fluctuations in seasonal supply and demand, and government regulation ofsupply and demand created by its pricing and allocation restrictions. Oversupplies of gas can be expected to occur from time to time and may resultin the Partnership's wells being shut-in or production being curtailed. Increased imports of oil and natural gas have occurred and are expected tocontinue.  The effects of such imports could adversely impact the market fordomestic oil and natural gas. 

-6-

PDCutilizes the services of its wholly-owned subsidiary, Riley Natural Gas (RNG),in marketing the oil and natural gas produced from Partnership wells.  RNG hasbeen in the gas marketing business since 1986. All oil and natural gas is sold under contracts based on marketsensitive indexes that vary from month to month. No fixed price contracts arein place.  Purchase contracts for thesale of oil are cancelable on 30 days notice, whereas purchase contracts forthe sale of natural gas may range from spot market sales of short duration tocontracts with a term of a number of years and that may require the dedicationof the gas from a well for a period ranging up to the life of the well.  PDCwill not make any commitment of future production that does not primarilybenefit the Partnership.  RNG is entitled to charge reasonable fees for itsservices, including out-of-pocket costs, which will be equal to or less thanfees charged to non-affiliated producers for similar services.  The Partnership sold its oil and natural gas to threecustomers which accounted for 58%, 28% and 14% of the Partnership's total oiland natural gas sales in 2005 and 57%, 25% and 18% in 2004.

Derivatives and HedgingActivities

Historically, PDC and RNGhave utilized commodity based derivative instruments to manage a portion of theexposure to price volatility stemming from natural gas and crude oilproduction.  In order to provide a more predictable cash flow stream, PDCexpects to continue the use of derivative instruments including thePartnership's production of natural gas and oil, and will enter into derivativecontracts on behalf of the Partnership.  PDC may use financial hedges, putoptions, call options, and other derivative instruments to offset variations inprices.  The contracts hedge committed and anticipated natural gas and oilsales generally forecasted to occur within the next two-year period. TheManaging General Partner does not hold or issue derivatives for trading orspeculative purposes and permits utilization of hedges only if there is anunderlying physical position.  See "Commodity Price Risk" under Item 7A inthis Form 10-K.

Competition

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

Governmental Regulations

Federaland state regulatory authorities have established rules and regulationsrequiring permits for well operations, reclamation bonds and reports concerningoperations.  States also have statutes and regulations concerning the spacingof wells, environmental matters and conservation, and have establishedregulations concerning the unitization and pooling of oil and gas propertiesand maximum rates of production from oil and gas wells. 

Natural Gas Regulation.  Sale of natural gas by the Partnership is subjectto regulation of production, transportation and pricing by governmentalregulatory agencies.  Generally, the regulatory agency in the state where aproducing well is located regulates production activities and, in addition, thetransportation of gas sold intrastate.  The Federal Energy RegulatoryCommission (FERC) regulates the operation and cost of interstate pipelineoperators who transport gas.  Currently, the price of gas sold by thePartnership is not regulated by any state or federal agency.

Environmental and Safety Regulations.  The Partnership believes that it complies, in allmaterial respects, with all legislation and regulations relating toenvironmental and safety matters in the drilling and production of oil and gaswells and the discharge of wastes.  Compliance with such provisions andregulations is significant during well development but 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.

ThePartnership believes it has complied in all material respects with applicablestate and federal regulations.  The Partnership spent approximately $176,000 in2004 for expenditures related primarily to environmental permitting andcompliance; the amounts spent in 2005 are deemed not material.  

-7-

**ITEM 1A.  RISK FACTORS**

In the course of its normal business, thePartnership is subject to a number of risks that could adversely impact itsbusiness, operating results, financial condition, and cash distributions.  Thefollowing risk factors should be considered carefully in addition to the otherinformation included in this report.

Drilling natural gas and oil wells isspeculative and may be unprofitable or result in the total loss of investment. The drilling and completion operations undertakenby the Partnership for the development of natural gas and oil reserves areinherently speculative and involve a high degree of risk and the possibility ofa total loss of investment. Drilling activities may result in unprofitable welloperations, not only from non-productive wells, but also from wells that do notproduce natural gas or oil in sufficient quantities or quality to return a profiton the amounts expended.  Consequently, Partnership wells may not producesufficient natural gas and oil for investors to receive a profit or even torecover their initial investment.  Only three of the prior Partnershipssponsored by PDC have, to date, generated cash distributions in excess ofinvestor subscriptions without tax savings.  PDC cannot predict whether anyprospect will produce commercial quantities of natural gas or oil.  PDC cannotpredict the life and the ultimate production of any wells, and the actual livescould differ from those anticipated.

There will be no public market forthe units.  The investment in the Partnership is illiquid, and as a result anInvestor Partner may not be able to sell his or her units.  There is and will be no public market for theunits nor will a public market develop for the units.  Investor Partners maynot be able to sell their Partnership interests or may be able to sell themonly for less than fair market value.  A sale or transfer of units by an investorrequires PDC's prior written consent.  For these and other reasons, an investormust anticipate that he or she will have to hold his or her Partnershipinterests indefinitely and will not be able to liquidate his or her investmentin the Partnership.  Consequently, an investor must be able to bear theeconomic risk of investing in the Partnership for an indefinite period of time.

The additional general partners willbe individually liable for Partnership obligations and liabilities that aroseprior to conversion to limited partners (which can occur only after thedrilling completion operations are finished) that are beyond the amount oftheir subscriptions, Partnership assets, and the assets of the Managing GeneralPartner.  Under West Virginia law, the statein which the Partnership has organized, general partners of a limitedpartnership have unlimited liability with respect to the Partnership. Therefore, the additional general partners of the Partnership will be liableindividually and as a group for all obligations and liabilities of creditorsand claimants, whether arising out of contract or tort or in the conduct of thePartnership's operations, until such time as the additional general partnersare converted to limited partners.  Under the Partnership Agreement, thisconversion is not scheduled to occur until the drilling and completionoperations are finished.  Irrespective of conversion, the additional generalpartners will remain fully liable for obligations and liabilities that aroseprior to conversion.  Investors as additional general partners may be liablefor amounts in excess of their subscriptions, the assets of the Partnershipincluding insurance coverage, and the assets of the Managing General Partner. 

The Partnership may retain Partnershiprevenues if needed for Partnership operations to fully develop thePartnership's wells; if full development of the Partnership's wells provescommercially unsuccessful, an investor might anticipate a reduction in cashdistributions.  The Partnership utilizedsubstantially all available capital raised in the offering for the drilling andcompletion of wells.  In the future, PDC may wish to rework or recompletePartnership wells but PDC has not held money from the initial investment forthat future work.  There is no assurance that future development of thePartnership's wells will prove commercially successful and that thefurther-developed Partnership wells will generate sufficient funds fromproduction to increase distributions to the investors to cover revenuesretained.  If future development of the Partnership's wells is not commerciallysuccessful, the use of funds retained from production revenues could result ina reduction of cash distributions to the Investor Partners. 

Increases in prices of oil andnatural gas have increased the cost of drilling and development and may affectthe performance of the Partnership in both the short and long term.  In the current high price environment, most oiland gas companies have increased their expenditures for drilling new wells. This has resulted in increased demand and higher cost for leases, oilfieldservices and well equipment.  Because of these higher costs, the risk to thePartnership of decreased profitability from future decreases in oil and naturalgas prices is increased.

-8-

Reductions in prices of oil andnatural gas reduce the profitability of the Partnership's productionoperations.  Global economic conditions,political conditions, and energy conservation have created unstable prices. Revenues of the Partnership are directly related to natural gas and oil pricesfor which PDC cannot predict.  The prices for domestic natural gas and oilproduction have varied substantially over time and by location, and are likelyto remain extremely unstable.  Revenue from the sale of oil and natural gasincreases when prices for these commodities increase and declines when pricesdecrease.  These unpredictable price changes can occur rapidly and are notwithin the control of the Partnership.  A decline in natural gas and/or oilprices would result in lower revenues for the Partnership and a reduction ofcash distributions to the partners of the Partnership.

The high level of drilling activitycould result in an oversupply of natural gas on a regional or national level,resulting in much lower commodity prices. Recently, the natural gas market has been characterized by excess demandcompared to the supplies available, leading in general to higher prices fornatural gas.  The high level of drilling, combined with a reduction in demandresulting from higher prices, could result in an oversupply of natural gas.  Inthe Rocky Mountain region, rapid growth of production and increasing suppliesmay result in lower prices and production curtailment due to limitations on availablepipeline facilities or markets not developed to utilize or transport the newsupplies.  In both cases, the result would probably be lower prices for thenatural gas the Partnership produces, reduced profitability for the Partnershipand reduced cash distributions to the Investor Partners.

Sufficient insurance coverage may notbe available for the Partnership, thereby increasing the risk of loss for theInvestor Partners.  It is possible that someor all of the insurance coverage which the Partnership has available may becomeunavailable or prohibitively expensive.  In that case, PDC might elect tochange the insurance coverage.  The additional general partners could beexposed to additional financial risk due to the reduced insurance coverage anddue to the fact that additional general partners would continue to beindividually liable for obligations and liabilities of the Partnership. Investor Partners could be subject to greater risk of loss of their investmentbecause less insurance would be available to protect the Partnership fromcasualty losses.  Moreover, should the Partnership's cost of insurance becomemore expensive, the amount of cash distributions to the investors will bereduced.

Throughtheir involvement in Partnership and other non-partnership activities, theManaging General Partner and its affiliates have interests which conflict withthose of the Investor Partners; actions taken by the Managing General Partnerin furtherance of its own interests could result in the Partnership being lessprofitable and a reduction in cash distributions to the investors.  PDC's continued active participation in oil andnatural gas activities for its own account and on behalf of other partnershipsorganized or to be organized by PDC, and the manner in which Partnershiprevenues are allocated, creates conflicts of interest with the Partnership. PDC has interests which inherently conflict with the interests of the InvestorPartners.  In operating the Partnership, the Managing General Partner and itsaffiliates could take actions which benefit themselves and not thePartnership.  These actions could result in the Partnership's being lessprofitable.  In that event, an Investor Partner could anticipate a reduction ofcash distributions.

The Partnership and otherpartnerships sponsored by the Managing General Partner may compete with eachother for prospects, equipment, contractors, and personnel; as a result, thePartnership may find it more difficult to operate effectively and profitably.  During and after 2006, PDC plans to offerinterests in other partnerships to be formed for substantially the samepurposes as those of the Partnership.  Therefore, a number of partnerships withunexpended capital funds, including those partnerships formed before and afterthe Partnership, may exist at the same time.  The Partnership may compete forequipment, contractors, and PDC personnel which may make it more difficult andmore costly to obtain services for the Partnership.  In that event, it ispossible that the Partnership would be less profitable.  Additionally, becausePDC must divide its attention in the management of its own affairs as well asthe affairs of over seventy-five limited partnerships PDC has organized in otherprograms, the Partnership will not receive PDC's full attention and efforts atall times.

The Partnership's derivativeactivities could result in reduced revenue compared to the level thePartnership might experience if no derivative instruments were in place.  The Partnership expects to use derivativeinstruments to reduce the impact of price movements on revenue.  While thesederivative instruments protect the Partnership against the impact of decliningprices, they also may limit the positive impact of price increases.  As aresult, the Partnership may have lower revenues when prices are increasing thanmight otherwise be the case, which may also reduce the Partnership's cash flowsand cash distributions to the Investor Partners.

-9-

Hedging transactions have, in thepast, and may, in the future, impact our cash flow from operations.  Ourcommodity hedging may prevent us from benefiting fully from price increases andmay expose us to other risks.  PDC willenter into hedging arrangements to reduce the Partnership's exposure tofluctuations in natural gas and crude oil prices and to achieve morepredictable cash flow.  Although the Partnership's hedging activities may limitthe Partnership's exposure to declines in natural gas and crude oil prices,these activities may also limit and have, in the past, limited, additionalrevenues from increases in natural gas and crude oil prices.  To the extentthat the Partnership has PDC engage in hedging activities to protect itselffrom commodity price volatility, the Partnership may be prevented fromrealizing the benefits of price increases above the levels of the hedges.  

Additionally,the hedging transactions PDC has entered into, or will enter into on behalf ofthe partnership, may not adequately protect the Partnership from financial lossdue to circumstances such as:

•        Highly volatile natural gasand crude oil prices;

•        Production being less thanexpected; or

•        A counterparty defaults on itscontractual obligations.

A significant financial loss by theManaging General Partner could result in PDC's inability to indemnifyadditional general partners for personal losses suffered because of Partnershipliabilities.  As a result of PDC'scommitments as Managing General Partner of several partnerships and because ofthe unlimited liability of a general partner to third parties, PDC's net worthis at risk of reduction if PDC suffers a significant financial loss.  BecausePDC is primarily responsible for the conduct of the Partnership's affairs, aswell as the affairs of other partnerships for which PDC serves as managinggeneral partner, a significant adverse financial reversal for PDC could resultin PDC's inability to pay Partnership liabilities and obligations.  Theadditional general partners of the Partnership might be personally liable forpayments of Partnership's liabilities and obligations.  Therefore, the ManagingGeneral Partner's financial incapacity could increase the risk of personalliability as an additional general partner because PDC would be unable toindemnify the additional general partners for any personal losses sufferedarising from Partnership operations.

The Managing General Partnermay not have sufficient funds or budget to repurchase limited partnershipunits.  As a result of the Managing General Partner being a general partnerin several partnerships, the Partnership's net worth is at risk of reduction ifPDC suffers a significant financial loss.  Because the investors may requestthe Managing General Partner to repurchase the units in the Partnership,subject to certain conditions and restrictions, a significant adverse financialreversal could result in the Managing General Partner's inability to pay forPartnership obligations or the repurchase of investor units.  

Fluctuating marketconditions and government regulations may cause a decline in the profitabilityof the Partnership.  The sale of any natural gas and oil produced by thePartnership will be affected by fluctuating market conditions and governmentalregulations, including environmental and safety standards set by state andfederal agencies.  From time-to-time, a surplus of natural gas or oil may occurin areas of the United States.  The effect of a surplus may be to reduce theprice the Partnership receives for the natural gas or oil production, or toreduce the amount of natural gas or oil that the Partnership may produce andsell.  As a result, the Partnership may not be profitable.  Lower prices and/orlower production and sales will result in lower revenues for the Partnershipand a reduction in cash distributions to the partners of the Partnership.

Environmental hazards involved indrilling natural gas and oil wells may result in substantial liabilities forthe Partnership.  There are numerous naturalhazards involved in the drilling of wells, including unexpected or unusualformations, pressures, blowouts involving possible damages to property andthird parties, surface damages, personal injury or loss of life, damage to andloss of equipment, reservoir damage, and loss of reserves.  Uninsuredliabilities would reduce the funds available to the Partnership, may result inthe loss of Partnership properties, and may create liability for additionalgeneral partners.  The Partnership may become subject to liability forpollution, abuses of the environment and other similar damages, and insurancecoverage may be insufficient to protect the Partnership against all potentiallosses.  In that event, Partnership assets would be used to pay personal injuryand property damage claims and the costs of controlling blowouts or replacingdestroyed equipment rather than for drilling activities.  These payments wouldcause an otherwise profitable partnership to be less profitable or unprofitableand would result in a reduction of cash distributions to the partners of thePartnership.

-10-

Information concerning reserves andfuture net revenues estimates is inherently uncertain.  The accuracy of proved reserves estimates and estimated future netrevenues from such reserves is a function of the quality of availablegeological, geophysical, engineering and economic data and is subject tovarious assumptions, including assumptions required by the SEC relating to oiland gas prices, drilling and operating expenses, and other matters. Although webelieve that the estimated proved reserves represent reserves that we arereasonably certain to recover, actual future production, oil and gas prices,revenues, taxes, development expenditures, operating expenses, and quantitiesof recoverable oil and gas reserves will most likely vary from the assumptionsand estimates used to determine proved reserves. Any significant variance couldmaterially affect the estimated quantities and value of our oil and gasreserves which in turn could adversely affect our cash flows, results ofoperations, and the availability of capital resources. In addition, we mayadjust estimates of proved reserves to reflect production history, results ofexploration and development, prevailing oil and gas prices and other factors,many of which are beyond our control. Downward adjustments to the estimatedproved reserves could require us to write down to the carrying value of our oiland gas properties which would reduce earnings and our partners' equity. 

Thepresent value of proved reserves will not necessarily equal the current fairmarket value of the estimated oil and gas reserves. In accordance with thereserve reporting requirements of the SEC, the estimated discounted future net cash flows from proved reserves are basedon prices and costs as of the date of the estimate. Actual future prices andcosts may be materially higher or lower than those as of the date of theestimate. The timing of both the production and the expenses with respect tothe development and production of oil and gas properties will affect the timingof future net cash flows from proved reserves and their present value.

Seasonalweather conditions may adversely affect the Partnership's ability to conductdrilling, completion and production activities in some of the areas where weoperate.  Oil and natural gasoperations in the Rocky Mountains are adversely affected by seasonal weatherconditions. In certain areas, drilling and other oil and natural gas activitiesare restricted or prevented by weather conditions for up to 6 months out of theyear. This limits operations in those areas and can intensify competitionduring those months for drilling rigs, oil field equipment, services, suppliesand qualified personnel, which may lead to periodic shortages. Theseconstraints and the resulting shortages or high costs could delay operationsand materially increase operating and capital costs and therefore, adverselyaffect profitability. 

ITEM 1B.  UNRESOLVED STAFFCOMMENTS

None.

**ITEM 2.  PROPERTIES**

Drilling Activity

Thefollowing table sets forth the results of the Partnership's drilling activity asof December 31, 2005.  All of the Partnership's wells drilled and producing arelocated in Colorado.

Gross Wells

Net Wells

Development wells:

Drilled, completed and  producing

 37

32.49

Drilled and not completed

    -

-

Dry hole

    -

        -

Total Wells Drilled 

37

32.49

Adevelopment well is a well that is drilled close to and into the same formationas wells which have already produced and sold oil or natural gas.  Anexploratory well is one which is drilled in an area where there has been no oilor natural gas production, or a well which is drilled to a previously untestedor non-producing zone in an area where there are wells producing from otherformations.  Productive wells consist of producing wells and wells capable ofproducing oil and gas in commercial quantities, including gas wells awaitingpipeline connections to commence deliveries.  A gross well refers to the numberof wells in which the Partnership has an interest.  A net well refers to agross well multiplied by the percentage working interest in the wells owned bythe Partnership.

-11-

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

Production

See"Item 7 - Management's Discussion and Analysis of Financial Condition andResults of Operations" for information related to the Partnership's productionas of December 31, 2005. 

Reserves

See"Note 7 - Supplemental Reserve Information (Unaudited)" in the FinancialStatements for information related to the Partnership's oil and gas reserves asof December 31, 2005.

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 titlehas been made with respect to all of the Partnership's producing properties andthe Partnership believes that it has generally satisfactory title to suchproperties.

**ITEM 3.  LEGALPROCEEDINGS**

The Partnership is not aparty to any legal proceedings.

PDC, as Managing General Partner and operator of thePartnership's wells, may be subject to various legal proceedings from time totime arising in the normal course of business.  Any outstanding and pendinglegal actions are not considered material to the operations of the Partnershipor PDC.

**ITEM 4.  SUBMISSION OFMATTERS TO A VOTE OF SECURITY HOLDERS**

None.

**PART II**

**ITEM 5.  MARKET FORREGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS**

At December 31, 2005, the Partnership had 1,184 Investor Partners holding a totalof 1,451.54 units and one Managing General Partner.  No established publictrading market exists for the units, nor will a public trading market everdevelop for the units.  Limited and additional general partnership interestsare transferable, however, no assignee of units in the Partnership can become asubstituted partner without the written consent of the transferor and theManaging General Partner.  The Managing General Partner has not repurchased anyPartnership interests as of December 31, 2005.

**ITEM 6.  SELECTED FINANCIAL DATA**

Theselected financial data presented below has been restated to reflectadjustments to correct accounting errors in our financial statements and hasbeen derived from audited financial statements of the Partnership.  See theFinancial Statements included with this Form 10-K.

-12-

Years Ended December 31, 

2005

2004 (a)(b)

(Restated)

Oil and gas sales

 $    14,466,329 

 $     6,687,282 

Costs and expenses

         6,185,926 

        4,114,886 

Oil and gas price risk management  loss, net

        (1,129,266)

          (281,435)

Net income

         7,172,552 

        2,322,237 

Allocation of net income:

Managing  General Partner

         1,434,510 

           551,540 

Investor  Partners

         5,738,042 

        1,770,697 

Per  Investor Partner unit

                3,953 

               1,220 

Total Assets at year end

       29,364,078 

      33,843,312 

Cash Distributions:

Managing  General Partner

         2,465,709 

           366,601 

Investor  Partners

         9,862,851 

        1,466,407 

Per  Investor Partner unit

                6,795 

               1,010 

(a) See Restated Financial  Statements elsewhere herein.

(b) From April 30, 2004  (date of inception) through December 31, 2004.

** **

**ITEM 7. MANAGEMENT'SDISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.**

Safe Harbor Statement Underthe Private Securities Litigation Reform Act of 1995

Statements,other than historical facts, contained in this Annual Report on Form 10-K,including statements of estimated oil and gas production and reserves, futurecash flows and the Partnership's strategies, plans and objectives, are"forward-looking statements" within the meaning of Section 27A of theSecurities Act of 1933, as amended (the "Securities Act"), and Section 21E ofthe Securities Exchange Act of 1934, as amended (the "Exchange Act").  Althoughthe Partnership believes that its forward looking statements are based onreasonable assumptions, it cautions that such statements are subject to a widerange of risks, trends and uncertainties, incidental to the production andmarketing of oil and gas, that could cause actual results to differ materiallyfrom those projected.  Among those risks, trends and uncertainties areimportant factors that could cause actual results to differ materially from theforward looking statements, including, but not limited to, changes inproduction volumes, worldwide demand and commodity prices for petroleum naturalresources; risks incidental to the operation of oil and gas wells; futureproduction and development costs; the effect of existing and future laws,governmental regulations and the political and economic climate of the UnitedStates; the effect of derivative activities; and conditions in the capitalmarkets.  In particular, careful consideration should be given to cautionarystatements made in this Form 10-K and in the various reports the Partnershiphas filed with the Securities and Exchange Commission.  The Partnershipundertakes no duty to update or revise these forward-looking statements.

Whenused in this Form 10-K, the words, "expect," "anticipate," "intend," "plan,""believe," "seek," "estimate" and similar expressions are intended to identifyforward-looking statements, although not all forward-looking statements containthese identifying words. Because these forward-looking statements involve risksand uncertainties, actual results could differ materially from those expressedor implied by these forward-looking statements for a number of importantreasons, including those discussed under "Item 1A - Risk Factors" and elsewherein this Form 10-K.

Restatementof Historical Financial Statements

ThePartnership's financial statements have been restated to correct errors in the Partnership'saccounting for derivative transactions, asset retirement obligations, and certain aspects of its accountingfor oil and gas properties.

-13-

Asummary of the adjustments included in the restatement and their impact on netincome and partners' equity for the year ended December 31, 2004, and for thequarter ended March 31, 2005, is included in "Item 1 - Business" above.  Theserestatements had no effect on the Partnership's cash flows.

Detailedinformation as to the effects of the restatements on the Partnership'spreviously reported statements of operations and partners' equity and thebalance sheets as of and for the year ended December 31, 2004, and for each ofthe quarters in 2004 and the first quarter of 2005 are presented in "Note 10 -Restatement of Historical Financial Statements" in the Notes to the FinancialStatements.

Overview

ThePartnership was funded on April 30, 2004, with Investor Partner contributionsof $29,030,865 and the Managing General Partner's cash contribution of $6,419,029. After payment of syndication costs of $2,919,286 and a one-time management feeto the Managing General Partner of $435,463, the Partnership had available cashof $32,095,145 with which to commence the Partnership's drilling activities.

Thedrilling of the Partnership's oil and gas wells commenced in May 2004,following the funding of the Partnership.  Drilling activities and completionactivities continued until the last of the thirty-seven wells in which thePartnership participated was connected to a pipeline in December 2004.  Thethirty-seven wells drilled by the Partnership are located in the State of Colorado within two oil and gas fields and all were completed as producing wells.  Thewells produce predominantly natural gas along with associated crude oil.  Noadditional wells will be drilled and no additional development or exploratorywork will be undertaken because all of the funds from the initial capitalcontributions of the partners were expended on the development of thesethirty-seven wells.  

Initial production from the Partnership's wells commencedin June 2004 upon connecting the first well to a pipeline.   Production andsales of natural gas and oil from the Partnership's wells increased steadilyduring the second half of 2004 as additional wells were completed and placedinto production, the last of which occurred in December 2004.  
 
Results of Operations -2005 as compared to 2004

The following table presentssignificant operational information for the year ended December 31, 2005, ascompared to the period from April 30, 2004 (date of inception) through December31, 2004.

For Year Ended December 31, 

2005

2004

% change

 

(Restated)

 

Oil and gas sales

 $      14,466,329 

 $      6,687,282 

116%

Gas sales - Mcf

           1,624,574 

            720,172 

126%

Average gas price/Mcf

 $                 6.76 

 $               5.24 

29%

Oil sales - Bbls

                61,115 

              68,727 

-11%

Average oil price/Bbl

 $               56.91 

 $             42.41 

34%

Production and operating  costs

 $        2,076,326 

 $         824,496 

152%

Production and operating  costs/Mcfe

 $                 1.04 

 $               0.73 

42%

Depreciation, depletion and  amortization

 $        4,069,845 

 $      2,826,071 

44%

Net income

 $        7,172,552 

 $      2,322,237 

209%

Partnership cash  distributions

 $      12,328,560 

 $      1,833,008 

573%

Oil and gas price risk  management loss, net:

Realized  loss

 $           840,432 

 $         160,424 

424%

Unrealized  loss

 $           288,834 

 $         121,011 

139%

Working capital at year end

 $        2,740,273 

 $      3,752,731 

-27%

-14-

*Definitions:*
- Bbl - One barrel or 42 U.S.     gallons of liquid volume.
- Mcf - One thousand cubic     feet.
- Mcfe - One thousand cubic     feet of natural gas equivalents, based on a ratio of 6 Mcf for each barrel     of oil, which reflects the relative energy content.

Asreflected in the table above, oil and gas sales increased by 116% over theprior year.  This increase was due to the increase in production of natural gasand as the result of having all thirty-seven wells in production during 2005,whereas, in 2004, the drilling of the Partnership's wells was in progressduring the months of May through December and did not reflect a full year ofproduction.  A portion of the sales increase related to the increase in averagenatural gas and oil prices that occurred during 2005. 

Productionand operating costs for 2005 increased by 152% over the previous year, and isdue to the increase in production related activities with all wells producingin 2005, as compared to 2004 when drilling activities were underway and fewerwells were producing.  The average of these costs in relation to natural gasequivalent units (Mcfe) sold during the period increased to $1.04 per Mcfe in2005 as compared to $0.73 in the previous year. 

ThePartnership manages oil and gas price risks through the use of derivativeinstruments to provide protection on declining oil and natural gas prices.  Inperiods of rising oil and natural gas prices, the Partnership may record lossesin its derivative transactions as fair values exceed contract prices related tothe Partnership's oil and gas sales.  In periods of declining prices, thePartnership would theoretically record gains in its derivative transactions.  Transactionsin derivative instruments resulted in net losses for both 2005 and 2004, with2005 being greater as the result of the sharp rise in commodity prices for theyear.  The total losses for both the net realized and the net unrealized lossesfor 2005 were $1,129,266, as compared to $281,435 for 2004.  The net losses arecomprised of the change in fair value of derivatives positions related to thePartnership's oil and gas production for derivative contracts entered into bythe Managing General Partner on behalf of the Partnership.  The Partnershiprecords gains or losses from its derivative positions on the statement ofoperations as oil and gas price risk management gain (loss), net.   

*Liquidityand Capital Resources*

The Partnership had a working capital balance at December31, 2005 of $2,740,273, which generally represents the receivables from oil andgas sales for the preceding three months, offset by accounts payable from oiland gas activity and short-term derivative values. 

Future operations are expected to be funded from revenuesgenerated from oil and gas production activities.  Current production revenues exceed operating costs by awide margin.  The Partnership finished the drilling and completion of itsthirty-seven wells in December 2004 and all of the $32,095,145 available fromthe initial partner contributions was utilized in this process.  There are noplans and no provision in the Partnership Agreement for additional developmentor exploration beyond these thirty-seven wells, and there are no presentcapital needs of the Partnership (see "Item 1. Business - Plan of Operations"above).  Under the Partnership Agreement, the Managing General Partner isallowed to and may withhold production revenues in advance of significantrecompletion work on existing wells that may arise; however, the Partnership isnot permitted to borrow funds.  If Partnership funds are used for recompletionwork, the cash distributions to the partners at the time of the recompletionswill be reduced, but should result in additional cash distributions followingthe recompletions.

The productionphase of operations will continue for the expected life of the wells and untilthe wells can no longer be operated economically.  As wells are produced, theproceeds from the sale of oil and gas are collected and distributed, net ofoperating costs, on a routine basis by the Managing General Partner and are notretained by the Partnership.  Normally, all available funds from the sales ofoil and gas, net of operating costs, are distributed monthly to the partners.  

*Oiland Gas Reserves*

Informationrelated to the oil and gas reserves on the Partnership's wells is discussed indetail in "Note 7 - Supplemental Reserve Information (Unaudited)" in the Notesto Financial Statements.  

-15-

QuarterlyAnalysis - 2005 Quarters versus 2004 Quarters

*Overview*

Thequarterly analysis presented below provides substantially all of theinformation that would normally be contained in quarterly reports on Form 10-Q aspart of this Form 10-K.  As explained in the Restatement of HistoricalFinancial Statements in "Item 1 - Business" above, this comprehensive Form 10-Kincludes all annual and quarterly financial information for 2004 and 2005,including restated information, in lieu of reporting in separately filed Forms10-Q for the affected periods.  

Production and sales of natural gas and oil from thePartnership's wells increased steadily during the second half of 2004 as wellswere drilled and placed into production.  The last four of the thirty-sevenwells commenced production in the first quarter of 2005.  The table belowreflects the Partnership's sales of production from the wells and the averageprices received for each of the quarters in 2004 and 2005.  

No. of

Gas

Oil

Producing

Average

Average

Oil and Gas

Wells

Mcf

Price

Bbls

Price

Sales

2004

Quarter 3

32

193,717

$4.79

30,456

$ 40.70

$       2,167,652

Quarter 4

33

526,455

$5.40

38,271

$ 43.78

4,519,630

Total 2004

720,172

$5.24

68,727

$ 42.41

$       6,687,282

2005

Quarter 1

37

543,611

$5.48

13,256

$53.63

$       3,687,777

Quarter 2

37

396,711

$5.94

20,767

$51.36

3,421,695

Quarter 3

37

354,513

$6.82

14,380

$64.11

3,340,241

Quarter 4

37

329,739

$9.82

12,712

$61.25

4,016,616

Total 2005

1,624,574

$6.76

61,115

$      56.91

$     14,466,329

Thefollowing table sets forth the quarterly operating results for the period fromApril 30, 2004 (date of inception) to December 31, 2004 and 2005 to facilitatean analysis of trends over the quarters in both years.  Additional quarterlyinformation for 2004 and 2005 is presented in "Note 9 - Quarterly FinancialData (Unaudited)" in the Notes to the Financial Statements.

For the Three Months Ended

March 31,

June 30, 

September 30,

December 31,

**STATEMENTS OF OPERATIONS**

2005

2005

2004

2005

2004

2005

2004

 
(Restated)

 

 

 

 
 
Revenues:

 
Oil  and gas sales

$3,687,777 

$3,421,695 

$             - 

$3,340,241 

$2,167,652 

$4,016,616 

$4,519,630 

 
 
Costs and expenses:

 
Production  and operating costs

531,980 

473,094 

 - 

473,716 

 267,182 

597,536 

557,314 

 
Management  fee

   - 

    - 

 435,463 

    - 

     - 

    - 

    - 

 
Direct  costs

    2,102 

 (2,105)

 - 

    1,562 

323 

 30,036 

 26,565 

 
Depreciation,  depletion and amortization

1,178,164 

1,104,228 

 - 

894,901 

1,187,048 

892,552 

1,639,023 

 
Accretion  of asset retirement obligation

    1,996 

    2,025 

 - 

    2,054 

    - 

    2,085 

    1,968 

 
Total  costs and expenses

1,714,242 

1,577,242 

 435,463 

 1,372,233 

1,454,553 

1,522,209 

2,224,870 

 
 
Income (loss) from  operations

1,973,535 

 1,844,453 

 (435,463)

1,968,008 

 713,099 

2,494,407 

2,294,760 

 
 
Interest income

    1,763 

    1,764 

 5,347 

    6,072 

   16,357 

 11,816 

    9,572 

 
Oil and gas price risk  management (loss) gain, net

 (978,729)

271,535 

 - 

(1,295,271)

 (172,186)

873,199 

(109,249)

 
 
Net income (loss)

$  996,569 

$2,117,752 

$(430,116)

$   678,809 

$   557,270 

$3,379,422 

$2,195,083 

 
 
Net income (loss) per  Investor Partner unit

 $    549 

 $ 1,167 

 $ (297)

 $    374 

 $     307 

 $ 1,863 

 $ 1,210 

 
 
 

Resultsof Operations, Liquidity and Capital Resources - 2005 Quarters versus 2004Quarters

Asreflected in the tables above, oil and gas sales for the first, second andthird quarters in 2005 reflect increases over the same quarter in the prioryear.  This increase was due primarily to the increase in production of oil andgas from having all thirty-seven wells in production during 2005, whereas, in2004, the drilling of the Partnership's wells was in progress during the monthsof May through December and all wells were not in production.  A portion of thesales increases related to the increase in average natural gas and oil pricesthat occurred throughout 2005. Similarly, operating costs and depreciation, depletionand amortization (DD&A) increased in conjunction with the production andsales increases for the quarters. 

Withthe consistent overall trend of the quarterly results as explained in thepreceding paragraph, the following quarterly analysis and discussion of theresults of operations, liquidity and capital resources reflects only discussionof those items that occurred in a particular quarter that deserve explanationbeyond that which applies in general to all quarters.

Theaverage of production and operating costs in relation to natural gas equivalentunits (Mcfe) production was $1.04 per Mcfe in 2005 as compared to $0.73 in2004, with ranges across the quarters from $0.71 in the third quarter of 2004 toa high of $1.47 in the fourth quarter of 2005.  This increase in average costswas primarily due to increased severance and property taxes on thesignificantly increased oil and gas sales prices along with additional wellworkovers and production enhancement work performed.  

Thediscussion above under Item 7 captioned "Liquidity and Capital Resources" as ofDecember 31, 2005, generally applies to all quarters in 2004 and 2005.  Onlythe exceptions, if any, to the above discussion will be included in thequarterly analysis below to avoid unnecessary repetition.

*ThreeMonth Periods Ended March 31 and June 30 - 2005 Compared to the Same Periods in2004*

Drillingof the Partnership's wells was not commenced until mid-2004 and no sales oroperating expenses were recorded in the first two quarters of 2004. Consequently, there are no 2004 operating activities with which to compare 2005operating results for these two quarters.

Expensesin the second quarter of 2004 reflects a one-time management fee equal to 11⁄2%of investors' subscriptions, or $435,463, which was paid to the ManagingGeneral Partner upon funding of the Partnership in April 2004 in accordancewith provisions of the Partnership Agreement.

*ThreeMonths Ended September 30 - 2005 Compared to the Same Period in 2004*

Theincreases in sales and operating costs in the third quarter of 2005 as comparedto 2004 occurred primarily due to the production volume increases in 2005 whenall wells were producing, while, in 2004, numerous wells began producing in thethird quarter but were not productive for the entire quarter since they did notstart producing until later in the quarter.  As of September 30, 2004, a totalof thirty-two wells had been drilled and were producing as compared to thethirty-seven wells producing as of September 30, 2005.

-17-

Thedecrease in DD&A in the third quarter of 2005 as compared to 2004 occurredprimarily due to the higher production levels being offset by the depletion ofan increased reserve amount in the quarter, resulting in lower depreciation.  Theincreased reserve amount resulted from the use of actual reserve amounts in2005 versus an estimated reserve amount in 2004.  The increase in the totalreserves resulted from a revised estimation of reserves for 2005.  See Note 7 -"Supplemental Reserve Information (Unaudited)" for a more detailed discussionon the reserves.

Transactionsin derivative instruments resulted in a net loss for the third quarter of 2005of $1,295,271, as compared to a net loss of $172,186 in the same quarter in2004.  This change is generally due to the volume of derivative contracts aswell as rising prices compared to the contract price of the derivativeinstrument. 

Critical AccountingPolicies and Estimates

Wehave identified the following policies ascritical to the understanding of the results of operations. This is not acomprehensive list of all of our accounting policies. In many cases, theaccounting treatment of a particular transaction is specifically dictated byaccounting principles generally accepted in the United States with no need formanagement's judgment in their application. There are also areas in whichmanagement's judgment in selecting any available alternative would not producea materially different result. However, certainaccounting policies are important to the portrayal of the Partnership'sfinancial condition and results of operations and require management's mostsubjective or complex judgments. In applying those policies, management usesits judgment to determine the appropriate assumptions to be used in thedetermination of certain estimates. Those estimates are based on our historicalexperience, our observance of trends in the industry, and information availablefrom other outside sources as appropriate. For a more detailed discussion onthe application of these and other accounting policies, see "Note 2 - Summaryof Significant Accounting Policies" and other related notes in the FinancialStatements. The Partnership's critical accounting policies and estimates are asfollows:

*Oiland Gas Properties*

* *

The Partnership accounts for its oil and gas propertiesunder the successful efforts method of accounting.  Costs of proved developedproducing properties, successful exploratory wells and development dry holecosts are depreciated or depleted by the unit-of-production method based onestimated proved developed producing oil and gas reserves.  Propertyacquisition costs are depreciated or depleted on the unit-of-production methodbased on estimated proved oil and gas reserves.  The Partnership obtains newreserve reports from independent petroleum engineers annually as of December31st of each year.  The Partnership adjusts for any new drilling anddivestitures during the year as needed.  The Partnership does not maintain aninventory of undrilled leases.

Upon sale or retirement ofsignificant portions of, or complete fields of, depreciable or depletableproperty, the book value thereof less proceeds or salvage value, is credited orcharged to income.  Upon sale of individual wells, the proceeds are credited toproperty costs.

Impairment testing for long-livedassets is required when circumstances indicate those assets may be impaired. The Partnership assesses impairment of capitalized costs of proved oil and gasproperties by comparing net capitalized costs to the estimated undiscountedfuture net cash flows on a field-by-field basis using estimated production, andbased upon prices at which management reasonably estimates such products willbe sold. These estimates of future product prices may differ from currentmarket prices of oil and gas. Any downward revisions to the Partnership'sestimates of future production or product prices could result in an impairmentof the Partnership's oil and gas properties in subsequent periods. If netcapitalized costs exceed undiscounted future net cash flows, the measurement ofimpairment is based on estimated fair value calculated using future discountedcash flows.

-18-

*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, collection of revenuefrom 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 up to the life of the well. Virtually all of the Managing General Partner's contracts' pricing provisionsare tied to a market index with certain adjustments based on, among otherfactors, whether a well delivers to a gathering or transmission line, qualityof natural gas and prevailing supply and demand conditions, so that the priceof the natural gas fluctuates to remain competitive with other availablenatural gas supplies.  As a result, the Partnership's revenues from the sale ofnatural gas will suffer if market prices decline and benefit if they increase. However, the Managing General Partner may from time to time enter intoderivative agreements, usually with a term of two years or less which mayeither fix or collar a price in order to reduce the impact of market pricefluctuations. The Partnership believes that the pricing provisions of itsnatural gas contracts are customary in 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, 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 from storage tanks at welllocations to a purchaser, collection of revenue from the sale is reasonablyassured, and the sales price is determinable.  The Partnership does not refineany of its oil production.  The Partnership's crude oil production is sold topurchasers at or near the Partnership's wells under short-term purchasecontracts at prices and in accordance with arrangements that are customary inthe oil industry.

* *

*DerivativeFinancial Instruments*

* *

ThePartnership accounts for derivative financial instruments in accordance withFAS Statement No. 133 "Accounting for Derivative Instruments and CertainHedging Activities" as amended.  During 2005 and 2004, none of thederivative contracts qualified for hedge accounting under the terms of FAS No.133.  Accordingly, the derivative instruments are recorded as an asset orliability on the balance sheet at fair value and the change in the fair valueis recorded in oil and gas price risk management gain (loss), net. Because derivative arrangements are entered into by the Managing GeneralPartner on behalf of the Partnership, they are reported on the balance sheet asa net short-term or long-term receivable due from or payable due to theManaging General Partner.

Themeasurement of fair value is based on actively quoted market prices, ifavailable. Otherwise, the Managing General Partner seeks indicative priceinformation from external sources including broker quotes and industrypublications. If pricing information from external sources is not available,measurement involves judgment and estimates. These estimates are based onvaluation methodologies considered appropriate by the Managing General Partner.

Byusing derivative financial instruments to manage exposures to changes incommodity prices, the Partnership exposes itself to credit risk.  Credit riskis the failure of the counterparty to perform under the terms of the derivativecontract.  When the fair value of a derivative contract is positive, thecounterparty owes the Managing General Partner, which in turn owes thePartnership thus creating repayment risk.  The Managing General Partnerminimizes the credit or repayment risk in derivative instruments by enteringinto transactions with high-quality counterparties.

-19-

RecentlyIssued Accounting Standards

In June 2005, the FASB issuedSFAS No. 154, "Accounting Changes and Error Corrections, a replacement ofAPB Opinion No. 20 and FASB Statement No. 3," which replaces AccountingPrinciples Board Opinion No. 20, "Accounting Changes" and SFAS No. 3,"Reporting Accounting Changes in Interim Financial Statements," andchanges the requirements for the accounting for and reporting of a change inaccounting principle.  SFAS No. 154 requires retrospective application forvoluntary changes in accounting principle unless it is impracticable to do so,and it applies to all voluntary changes in accounting principle.  SFAS No. 154is effective for accounting changes and corrections of errors made in fiscalyears beginning after December 15, 2005. Consequently, we will adopt the provisions of SFAS 154 for our fiscal year beginning January 1, 2006.  We currently believe that adoption of the provisions of SFAS No. 154 will not have amaterial impact on our financial statements.

In September 2006, the FASBissued SFAS No. 157, "Fair Value Measurements," which replaces severalexisting pronouncements, defines fair value, establishes a framework formeasuring fair value, and expands disclosures about fair value measurements. SFAS No. 157 is effective for financial statements issued for fiscal years beginningafter November 15, 2007, and interim periods within those fiscal years. Consequently, we will adopt the provisions of SFAS 157 for our fiscal yearbeginning January 1, 2008.  The Partnership is currently evaluating the impactof the provisions of SFAS No. 157 on its financial statements.

**Item7A.  Quantitative and Qualitative Disclosure About Market Risk**

Market-SensitiveInstruments and Risk Management

ThePartnership's primary market risk exposure is commodity price risk for the oiland gas the Partnership produces and sells.

Commodity Price Risk

TheManaging General Partner utilizes commodity-based derivative instruments,entered into on behalf of the Partnership, to manage a portion of thePartnership's exposure to price risk from oil and natural gas sales.  Theseinstruments consist of CIG (Colorado Interstate Gas) index-based contractstraded by JP Morgan for Colorado natural gas production. These derivativeinstruments have the effect of locking in for specified periods (atpredetermined prices or ranges of prices) the prices the Managing GeneralPartner will receive for the volume of oil and natural gas to which thederivative relates.  As a result, while these derivative instruments arestructured to reduce Partnership's exposureto changes in price associated with the derivative commodity, they also limitthe benefit the Partnership might otherwise have received from price changesassociated with the commodity.  The Partnership has adopted the policy of theManaging General Partner prohibiting the use of oil and natural gas future andoption contracts for speculative purposes.  Derivative arrangements areentered into by the Managing General Partner on behalf of the Partnership andare reported on the Partnership's balance sheet at fair value as a netshort-term or long-term receivable due from or payable to the Managing GeneralPartner.  Changes in the fair value of the Partnership's share of derivativesare recorded in the statement of operations. The following table summarizes thePartnership's share of open derivative positions as of December 31, 2005 and2004.

-20-

Open Derivative Positions

 
 
Commodity

Type

 Quantity   Gas-MMBtu Oil-Barrels

Weighted Average Price 

Fair Market Value

 
(a)

 
 
Partnership's Share  of Open Positions as of December 31, 2005:

 
Natural Gas

Sale Option

 960,452 

 $    6.03 

 $208,051 

Natural Gas

Purchase Option

 373,903 

 $    7.61 

 (617,897)

Due to Managing General Partner -  Derivatives, Total

 $      (409,846)

Partnership's  Share of Open Positions maturing within 12 months following December 31,  2005:

Natural Gas

Sale Option

 886,026 

 $    6.03 

 $184,486 

Natural Gas

Purchase Option

 336,690 

 $    7.53 

 (528,787)

Due to Managing General Partner - Derivatives, Short-term

 $              (344,301)

Partnership's  Share of Open Positions maturing within 12 months as of December 31, 2004:

Natural Gas

Sale Option

 253,304 

 $    3.58 

 $  44,306 

Natural Gas

Purchase Option

 126,652 

 $    4.71 

 (101,669)

Oil

Sale Option

    34,356 

 $  32.30 

     29,270 

Oil

Purchase Option

    17,178 

 $  40.00 

   (92,918)

Due to Managing General Partner - Derivatives , Total

 $              (121,011)

 
(a) MMBtu - one  million British thermal units. One British thermal unit is the heat required  to 

 
raise the temperature of a one-pound mass of water from 58.5 to  59.5 degrees Fahrenheit.

 
 
AtDecember 31, 2005, the maximum term for the derivative positions listed aboveis 15 months.

Theannual average Colorado Interstate Gas closing price for natural gas for 2005was $6.96 per MMBtu.  The average NYMEX closing price for oil for 2005 was$55.34 per barrel.  Future near-term gas and oil prices will be affected byvarious supply and demand factors such as weather, government and environmentalregulations and new drilling activities within the industry.

Disclosure of Limitations

As the information aboveincorporates only those exposures that exist at December 31, 2005, it does notconsider 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, and the Partnership's hedging strategies and commodity prices at thetime.

**ITEM 8.  FINANCIALSTATEMENTS AND SUPPLEMENTARY DATA**

The financial statements areattached to this Form 10-K beginning at page F-1.

-21-

**ITEM9.  CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING ANDFINANCIAL DISCLOSURE**

None.

**ITEM 9A.  CONTROLS ANDPROCEDURES**

*IntroductoryExplanation* - As disclosed in moredetail in "Item 1 - Business" above, the Partnership has no management orofficers because all of the management, officers and other employees that mayprovide services to or on behalf of the Partnership are employed by theManaging General Partner.  As used for the disclosures in this Item 9A,management and officers of the Partnership refers to the management andofficers of the Managing General Partner.  

*Evaluationof disclosure controls and procedures*- The Partnership carried out an evaluation, under the supervision and with theparticipation of management including the Chief Executive Officer and the ChiefFinancial Officer, of the effectiveness of the design and operation of itsdisclosure controls and procedures pursuant to Exchange Act Rule 13a-14(a) asof the end of the period covered by this Annual Report on Form 10-K. Based uponand as of the date of this evaluation, the Chief Executive Officer and theChief Financial Officer concluded that as of the date of this report, thePartnership's disclosure controls and procedures were not effective because ofthe material weaknesses described below.

*Materialweaknesses in internal control -*During2005, the Partnership identified materialweaknesses related to its policies and procedures andtechnical expertise in U.S. generally accepted accounting principles to ensurethe preparation of accurate and reliable interim and annual financialstatements. Specifically, the Partnership lacked personnel with sufficienttechnical accounting and financial reporting expertise and policies andprocedures in place to determine and document the appropriate application ofaccounting principles. These deficiencies impacted the Partnership's accountingfor derivatives, asset retirement obligations and depreciation, depletion andamortization, and result in more than a remote likelihood that a materialmisstatement of the annual or interim financial statements would not beprevented or detected.  

Inlight of the material weaknesses described above, the Partnership performedadditional analyses and other post-closing procedures to ensure its financialstatements are prepared in accordance with generally accepted accountingprinciples. Accordingly, notwithstanding the material weaknesses discussed inthis Item 9A, management believes that the financial statements included inthis report fairly present in all material respects our financial position,results of operations and cash flows for the periods presented. 

* *

*Changes in internal control over financial reporting* - 

During the fourth quarter of 2005, the followingchanges were made in the Partnership's internal control over financialreporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) of theSecurities Exchange Act of 1934) that have materially affected or arereasonably likely to materially affect internal control over financialreporting. 

•       The Partnership has increased its technicalexpertise through development of training programs and acquisition ofaccounting research software during the fourth quarter of 2005.  Trainingwill be on-going; however, programs provided during 2005 included oil and gasaccounting, general accounting and SEC financial reporting.

•       The Partnership has enhanced the documentationof its policies and procedures and related templates and analyses that supportthe application of accounting principles in several areas, including derivatives,oil and gas properties, and asset retirement obligations.

In addition, during the third quarter of fiscal 2005and subsequently in 2006, the Partnership made the following changes andremediation:

-22-

At the direction of the board of directors and auditcommittee, the Partnership has spent and continues to spend a significantamount of time and resources to improve its control environment.  The Partnershipis committed to instilling strong internal control policies and procedures andensuring that the "tone at the top" fully supports accuracy andcompleteness in all financial reporting.  In support of this position, thePartnership's progress toward improving internal control over financialreporting has been openly communicated with the Audit Committee, and the Partnershiphas undertaken to improve the design and effectiveness of its internal controlover financial reporting. The initiatives developed were both organizationaland process focused.  Organizational changes made during 2005 and throughthe date of this filing include, among others:

•       The Partnership has enhanced thecorporate accounting and reporting functions in the third quarter of 2005 bycreating and filling several new positions with professionals highlyexperienced in oil and gas accounting. Two new professionals hold degrees inaccounting and are Certified Public Accountants. One additional CertifiedPublic Accountant and a financial reporting director were hired during 2006.

•       The Partnership engaged a teamof highly experienced advisors in early 2006 to assist with various accountingresearch, projects and monitoring activities.  They assist with accountingand reporting issues including, but not limited to, derivatives, oil and gasactivities, new accounting standards or rules, SEC reporting and on-goingmonitoring of changes that may impact the Partnership's application ofaccounting principles.

•       The Partnership began theprocess of implementing measures related to documentation of its controls andprocedures, segregation of duties, timely reconciliations and the use ofdisclosure checklists to support the financial reporting process.

The Partnership has also implemented or is planning toimplement several process changes to improve the documentation supportingcertain accounting and reporting activities as well as to improve thedocumentation of its application of accounting principles.

•       The Partnership has evaluatedand selected a third-party integrated oil and gas accounting software system,which is expected to be fully implemented in early 2007.

The Partnership believes the measures taken to dateand planned for the future will address the reported material weaknesses andintends to complete the remediation efforts by early 2007.  In addition,the Partnership will continue to develop and implement other initiatives thatwill further improve both the effectiveness and efficiency of its internalcontrol over financial reporting. 

Beginning with the fiscal year ending December 31, 2007, Section 404 of the Sarbanes-Oxley Act of 2002 will require us toinclude an internal control report of management with our Annual Report on Form10-K. The internal control report must contain (1) a statement of management'sresponsibility for establishing and maintaining adequate internal control overfinancial reporting, (2) a statement identifying the framework used bymanagement to conduct the required evaluation of the effectiveness of ourinternal control over financial reporting, (3) management's assessment of theeffectiveness of our internal control over financial reporting as of the end ofour most recent fiscal year, including a statement as to whether or not ourinternal control over financial reporting is effective, and (4) a statementthat our independent registered public accountants have issued an attestationreport on management's assessment of our internal control over financialreporting.

In order to achieve compliance with Section 404 withinthe prescribed period, management has begun to assess the adequacy of ourinternal control over financial reporting, remediate any control weaknessesthat may be identified, and implement a continuous reporting and improvementprocess for internal control over financial reporting. We expect to continue tomake changes in our internal control over financial reporting during theperiods prior to December 31, 2007, in connection with our Section 404compliance efforts. 

-23-

*Limitationson the effectiveness of internal control -*A control system, no matter how well conceived and operated, canprovide only reasonable, not absolute, assurance that the objectives of theinternal control system are met. Because of the inherent limitations of anyinternal control system, no evaluation of controls can provide absoluteassurance that all control issues, if any, within a company have been detected.

**ITEM 9B.  OTHERINFORMATION**

None.

** **

**PART III**

**ITEM 10. DIRECTORS ANDEXECUTIVE OFFICERS OF THE REGISTRANT**

ThePartnership has no directors or executive officers.  The Partnership is managedby Petroleum Development Corporation ("PDC"), the Managing General Partner. PDC's common stock is listed on the NASDAQ Global Select Market and Form 10-Kfor 2005 has been filed with the Securities and Exchange Commission.  

Althoughthe Partnership has no Code of Ethics, PDC has a Code of Ethics that applies toits senior executive officers.  The Code of Ethics is posted on PDC's websiteat www.petd.com. 

**ITEM 11.  EXECUTIVECOMPENSATION**

ThePartnership, having no executive officers or directors, pays no executivecompensation.  None of PDC's officers or directors received any directremuneration or other compensation from the Partnership. These persons receiveremuneration and compensation solely from PDC.

**ITEM 12.  SECURITYOWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDERMATTERS**

The Partnership has no equitycompensation plans.

PDC owns a 20% partnershipinterest in the Partnership.

**ITEM 13. CERTAINRELATIONSHIPS AND RELATED TRANSACTIONS**

PDC,as the Managing General Partner, and its wholly-owned subsidiaries, RileyNatural Gas and PDC Securities Incorporated, are reimbursed for certainPartnership operating expenses and receive fees for services as provided for inthe partnership agreement.  As ofDecember 31, 2005 and 2004, the Partnership owed the Managing General Partner $551,615and $86,998, respectively.  As a result of derivative transactionsexecuted by the Managing General Partner on behalf of the Partnership, there werealso short term related party derivative payables of $344,301 and $121,011 at December31, 2005 and 2004, respectively and long-term related party derivative payablesof $65,545 for 2005 and $0 for 2004.  Thefollowing table presents reimbursements and service fees paid by thePartnership to PDC, or its affiliates, the year ended December 31, 2005 and theperiod from April 30, 2004 (date of inception) through December 31, 2004.

2005

2004

Management fee

 $                       - 

 $                 435,463 

Drilling services

                          - 

               32,095,145 

Syndication costs*

                          - 

                    583,857 

Well operations fees

              205,063 

                      67,101 

*      Consists of organization and offering costs, excluding costs oforganizing and selling the offering paid directly to non-affiliated brokerdealers as provided in the dealer/manager and selling agreements.

-24-

**ITEM14.  PRINCIPAL ACCOUNTANT FEES AND SERVICES**

For the years ended December31, 2005 and 2004, there were billings of $ 5,857 and $5,525 from thePartnership's independent auditors, KPMG LLP., for professional services forthe audit of the Partnership's financial statements in its Form 10-K and reviewof quarterly information normally contained in Form 10-Qs.  

The costs related to therestatement and re-audit of the financial statements of the Partnership to beincurred in 2006 are expected to be significant.  The Managing General Partnerhas determined it will assume the cost and expenses for the restatement.  ThePartnership will bear only an estimate of the cost of filing that Form 10-K asif there had not been a restatement. 

Pre-Approval Policies andProcedures

The Sarbanes-Oxley Act of2002 requires that all services provided to the Partnership by its independent registeredpublic accountants be subject to pre-approval by the Audit Committee orauthorized members of the Committee.  The Partnership does not have an AuditCommittee, however, the Managing General Partner's Audit Committee also servesfor the Partnership.  The Audit Committee has adopted policies and proceduresfor pre-approval of all audit services and non-audit services to be provided bythe Partnership's independent registered public accountants.  Services providedby the Partnership's independent registered public accountants with respect tothe restatement of the Partnership's financial statements were pre-approved bythe Managing General Partner's Audit Committee.  Actual fees incurred for allservices performed by the independent accountant are reported to the AuditCommittee after the services are fully performed.

-25-

**PART IV**

** **

**ITEM 15. EXHIBITS ANDFINANCIAL STATEMENT SCHEDULES**

 

(1)   Financial Statements

SeeIndex to Financial Statements on F-2 

(2)   Financial Statement Schedules

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 LimitedPartnership Agreement (incorporated by reference to Appendix A toPost-Effective Amendment No. 2 to Form S-1, SEC File No. 333-111260, and Rule424 final prospectus, dated May 25, 2004, of PDC 2004-2006 Drilling Program,filed with the SEC on May 21, 2004).

14                    Codeof Ethics of Petroleum Development Corporation, the Managing General Partner ofthe Limited Partnership (incorporated by reference to the code posted on theweb site of Petroleum Development Corporation at www.petd.com).

31.1                 Rule13a-14(a)/15d-14(c) Certification of Chief Executive Officer of PetroleumDevelopment Corporation, the Managing General Partner of the LimitedPartnership.

31.2                 Rule13a-14(a)/15d-14(c) Certification of Chief Financial Officer of PetroleumDevelopment Corporation, the Managing General Partner of the Limited Partnership.

32                    Title 18 U.S.C.Section 1350 (Section 906 of Sarbanes-Oxley Act of 2002) Certifications byChief Executive Officer and Chief Financial Officer of Petroleum DevelopmentCorporation, the Managing General Partner of the Limited Partnership.

-26-

SIGNATURES

Pursuant to the requirementsof Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registranthas duly caused this report to be signed on its behalf by the undersigned,thereunto duly authorized.

PDC 2004-A Limited Partnership

By its Managing General Partner

Petroleum Development Corporation

By /s/ Steven R. Williams

Steven R. Williams, Chairman

December 21, 2006

Pursuant to the requirementsof the Securities Exchange Act of 1934, this report has been signed below bythe following persons on behalf of the Registrant and in the capacities and onthe dates indicated:

Signature

Title

Date

/s/ Steven R. Williams

Chairman, Chief Executive  Officer and

December 21, 2006

    Steven  R. Williams

Director of Petroleum  Development Corporation,

Managing General Partner of  the Registrant

/s/ Richard W.  McCullough

Chief Financial Officer and  Treasurer

December 21, 2006

    Richard  W. McCullough

Petroleum Development  Corporation,

Managing General Partner of  the Registrant 

(Principal Financial and  Accounting Officer)

/s/ Darwin L. Stump 

Chief Accounting Officer

December 21, 2006

    Darwin  L. Stump

Petroleum Development  Corporation,

Managing General Partner of  the Registrant 

 

/s/ Thomas E. Riley 

President and Director

December 21, 2006

    Thomas  E. Riley

Petroleum Development  Corporation,

Managing General Partner of  the Registrant

/s/ Jeffrey C. Swoveland

Director 

December 21, 2006

    Jeffrey  C. Swoveland

Petroleum Development  Corporation,

Managing General Partner of  the Registrant

/s/ Vincent F.  D'Annunzio

Director 

December 21, 2006

    Vincent  F. D'Annunzio

Petroleum Development  Corporation,

Managing General Partner of  the Registrant

-27-

PDC 2004-A LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Financial Statements for Annual Report

on Form 10-K to Securities and Exchange

Commission

Year Ended December 31, 2005 and 

Period from April 30, 2004 (date of inception) throughDecember 31, 2004 (restated)

(With Independent Registered Public Accounting Firm'sReport Thereon)

F-1

PDC 2004-A LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Index to Financial Statements

Report of Independent  Registered Public Accounting Firm

F-3

Balance Sheets - December  31, 2005 and 2004

F-4

Statements of Operations -  Year Ended December 31, 2005 and Period 

From April 30, 2004 (date  of inception) through December 31, 2004

F-5

Statements of Partners'  Equity - Year Ended December 31, 2005 and Period

From April 30, 2004 (date  of inception) through December 31, 2004

F-6

Statements of Cash Flows -  Year Ended December 31, 2005 and Period 

From April 30, 2004 (date  of inception) through December 31, 2004

F-7

Notes to Financial  Statements

F-8

F-2

PDC 2004-A LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Report of Independent Registered Public AccountingFirm

To the Partners

PDC 2004-A Limited Partnership:

We have audited the accompanying balance sheets of PDC2004-A Limited Partnership as of December 31, 2005 and 2004, and the relatedstatements of operations, partners' equity and cash flows for the year endedDecember 31, 2005 and the period from April 30, 2004 (date of inception) toDecember 31, 2004.  These financial statements are the responsibility of thePartnership's management.  Our responsibility is to express an opinion on thesefinancial statements based on our audits.

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

In our opinion, the financial statements referred to abovepresent fairly, in all material respects, the financial position of PDC 2004-ALimited Partnership as of December 31, 2005 and 2004, and the results of itsoperations and its cash flows for the year ended December 31, 2005 and theperiod from April 30, 2004 (date of inception) to December 31, 2004, inconformity with U.S. generally accepted accounting principles.

As discussed in Note 10, the Company has restated theaccompanying financial statements as of and for the period ended  December 31,2004.

KPMG LLP

Pittsburgh, Pennsylvania

November 22, 2006

F-3

PDC 2004-A LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Balance Sheets

December 31, 2005 and 2004

Assets

2005

2004

(Restated)

Current assets:

 

Cash  and cash equivalents

 $             11,314 

 $             30,947 

Accounts  receivable - oil and gas sales 

           4,016,616 

           4,406,372 

Total  current assets

           4,027,930 

           4,437,319 

Oil and gas properties,  successful efforts method

         32,232,064 

         32,232,064 

Less accumulated  depreciation, depletion and amortization

         (6,895,916)

         (2,826,071)

         25,336,148 

         29,405,993 

Total Assets

 $      29,364,078 

 $      33,843,312 

Liabilities and  Partners' Equity

Current liabilities:

Accounts  payable and accrued expenses

 $           391,741 

 $           476,579 

Due  to Managing General Partner - derivatives

              344,301 

              121,011 

Due  to Managing General Partner - other

              551,615 

                86,998 

Total  current liabilities

           1,287,657 

              684,588 

Due to Managing General  Partner - derivatives, long-term

                65,545 

                       -   

Asset retirement  obligations

              147,047 

              138,887 

Partners' equity

         27,863,829 

         33,019,837 

Total Liabilities and  Partners' Equity

 $      29,364,078 

 $      33,843,312 

See accompanying notes to  financial statements.

F-4

PDC 2004-A LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Statements of Operations

Year Ended December 31, 2005 and Period from April  30, 2004 

(date of inception) through December 31, 2004

 
2005

2004

 
(Restated)

 
Revenues:

 
Oil  and gas sales

 $      14,466,329 

 $        6,687,282 

 
 
Costs and Expenses:

 
Production  and operating costs

           2,076,326 

              824,496 

 
Management  fee

                         - 

              435,463 

 
Direct  costs

                31,595 

                26,888 

 
Depreciation,  depletion and amortization

           4,069,845 

           2,826,071 

 
Accretion  of asset retirement obligations

                  8,160 

                  1,968 

 
    Total costs and expenses

           6,185,926 

           4,114,886 

 
 
Income from operations

           8,280,403 

           2,572,396 

 
 
Interest income

                21,415 

                31,276 

 
Oil and gas price risk  management loss, net

         (1,129,266)

            (281,435)

 
 
Net income

 $        7,172,552 

 $        2,322,237 

 
 
Net income per Investor  Partner unit

 $               3,953 

 $               1,220 

 
 
 
See accompanying notes to  financial statements.

 
 
F-5

PDC 2004-A LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Statements of Partners' Equity

Year Ended December 31, 2005, and Period from April  30, 2004 

(date of inception) through December 31, 2004

Managing

Investor

General

Partners

Partner

Total

Partners' initial capital  contributions

 $  29,030,865 

 $6,419,029 

 $  35,449,894 

Syndication costs

 (2,919,286)

 - 

 (2,919,286)

Distributions to partners

 (1,466,407)

(366,601)

 (1,833,008)

Net income (restated)

   1,770,697 

 551,540 

   2,322,237 

Balance, December 31, 2004  (restated)

         26,415,869 

   6,603,968 

 33,019,837 

Distributions to partners

 (9,862,851)

 (2,465,709)

   (12,328,560)

Net income

   5,738,042 

   1,434,510 

   7,172,552 

Balance, December 31, 2005

 $  22,291,060 

 $5,572,769 

 $  27,863,829 

See accompanying notes to  financial statements.

F-6

PDC 2004-A LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Statements of Cash Flows

Year Ended December 31, 2005 and Period from April  30, 2004 

(date of inception) through December 31, 2004

2005

2004  

(Restated) 

Cash flows from operating  activities:

Net income 

 $      7,172,552 

 $        2,322,237 

Adjustments to reconcile  net income to 

net  cash provided by operating activities:

Depreciation,  depletion and amortization

         4,069,845 

           2,826,071 

Accretion  of asset retirement obligation

                8,160 

                  1,968 

Unrealized  loss on derivative transactions

            288,835 

              121,011 

Changes  in operating assets and liabilities:

Decrease  (increase) in accounts receivable - oil and gas sales

            389,756 

         (4,406,372)

Increase  in due to Managing General Partner - other

            464,617 

                86,998 

(Decrease)  increase in accounts payable and accrued expenses

            (84,838)

              476,579 

Net  cash provided by operating activities

       12,308,927 

           1,428,492 

Cash flows from investing  activities:

Expenditures  for oil and gas properties

                  -    

       (32,095,145)

Net  cash used in investing activities

                   -    

       (32,095,145)

Cash flows from financing  activities:

Investor  Partners' contributions

                   -    

         29,030,865 

Managing  General Partner contribution

                   -    

           6,419,029 

Syndication  costs paid

                   -    

         (2,919,286)

Distributions  to partners

     (12,328,560)

         (1,833,008)

Net  cash (used in) provided by financing activities

     (12,328,560)

         30,697,600 

Net (decrease) increase in  cash and cash equivalents

            (19,633)

                30,947 

Cash and cash equivalents  at beginning of period

              30,947 

                  -    

Cash and cash equivalents  at end of period

 $           11,314 

 $             30,947 

See accompanying notes to  financial statements.

F-7

PDC 2004-A LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Notes to Financial Statements

 (1)  Organization

The PDC 2004-A LimitedPartnership (the "Partnership") was organized as a limited partnership inaccordance with the laws of the State of West Virginia for the purpose of engagingin the drilling, completion and operation of oil and gas development andexploratory wells in the Rocky Mountain Region.  Business operations of thePartnership commenced on April 30, 2004, upon the closing of an offering forthe sale of partnership units.

Purchasersof partnership units subscribed to and fully paid for 33.34 units of limitedpartner interest and 1,418.20 units of additional general partner interests at$20,000 per unit (Investor Partners). Petroleum Development Corporation has beendesignated the Managing General Partner of the Partnership and has a 20%ownership in the Partnership.  Generally, throughout the term of thePartnership, revenues, costs and cash available for distributions are allocated80% to the limited and additional general partners pro rata based on theirinvestment in the Partnership and 20% to the Managing General Partner.  Thelimited and additional general partners are referred to collectively as"Investor Partners."

Uponcompletion of the drilling phase of the Partnership's wells, all additionalgeneral partners units were converted into units of limited partner interestsand thereafter become limited partners of the Partnership.

Inaccordance with the terms of the Limited Partnership Agreement (the Agreement),the Managing General Partner manages all activities of the Partnership and actsas the intermediary for substantially all Partnership transactions.

(2)   Summary of SignificantAccounting Policies

*Restatement of HistoricalFinancial Statements*

See"Note 10 - Restatement of Historical Financial Statements" for adescription of our restatement of historical financial statements related toerrors in accounting.

*Partnership Financial StatementPresentation Basis*

Thefinancial statements include only those assets, liabilities and results ofoperations of the partners which relate to the business of the Partnership. The statements do not include any assets, liabilities, revenues or expensesattributable to any of the partners' other activities.

*Reclassifications*

Certain prior year amounts have beenreclassified to conform with current year classifications.

*Oil and Gas Properties*

 

The Partnership accounts for its oil and gas propertiesunder the successful efforts method of accounting. Costs of proved developedproducing properties and development dry hole costs are depreciated or depletedby the unit-of-production method based on estimated proved developed producingoil and gas reserves.  Property acquisition costs are depreciated or depletedon the unit-of-production method based on estimated proved oil and gasreserves.  The Partnership obtains new reserve reports from independentpetroleum engineers annually as of December 31st of each year.  The Partnershipadjusts for any new drilling and divestitures during the year as needed.  ThePartnership does not maintain an inventory of undrilled leases.

Upon sale or retirement ofsignificant portions of or complete fields of depreciable or depletableproperty, the book value thereof less proceeds or salvage value, is credited orcharged to income.  Upon sale of individual wells, the proceeds are credited toproperty costs.

F-8

PDC 2004-A LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Notes to Financial Statements, Continued

Impairment testing for long-lived assets is required whencircumstances indicate those assets may be impaired.  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 estimated production, based upon prices at whichmanagement reasonably estimates such products will be sold. These estimates offuture product prices may differ from current market prices of oil and gas. Anydownward revisions to the Partnership's estimates of future production orproduct prices could result in an impairment of the Partnership's oil and gasproperties in the subsequent periods. If net capitalized costs exceedundiscounted future net cash flows, an impairment is recorded.  The measurementof impairment is based on estimated fair value calculated using futurediscounted 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 up to the life of the well. Virtually all of the Managing General Partner's contracts pricing provisionsare tied to a market index with certain adjustments based on, among otherfactors, whether a well delivers to a gathering or transmission line, qualityof natural gas and prevailing supply and demand conditions, so that the priceof the natural gas fluctuates to remain competitive with other availablenatural gas supplies.  As a result, the Partnership's revenues from the sale ofnatural gas will suffer if market prices decline and benefit if they increase. However, the Managing General Partner may from time to time enter intoderivative agreements, usually with a term of two years or less which mayeither fix or collar a price in order to reduce market price fluctuations. ThePartnership believes that the pricing provisions of its natural gas contractsare customary in 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, 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  from storage tanks at welllocations to a purchaser, collection of revenue from the sale is reasonablyassured and the sales price is determinable.  The Partnership is currently ableto sell all the oil that it can produce under existing sales contracts withpetroleum refiners and marketers.  The Partnership does not refine any of itsoil production.  The Partnership's crude oil production is sold to purchasersat or near the Partnership's wells under short-term purchase contracts atprices and in accordance with arrangements that are customary in the oilindustry.

ThePartnership sold oil and natural gas to three customers which accounted for58%, 28% and 14%, of the Partnership's total oil and natural gas sales for theyear ended December 31, 2005, and 57%, 25% and 18% for the period frominception to December 31, 2004.

*AssetRetirement Obligations*

The Partnership accounts for asset retirement obligationsby recording the fair value of its plugging and abandonment obligations whenincurred, which is at the time the well is completely drilled. Upon initialrecognition of an asset retirement obligation, the Partnership increases thecarrying amount of the long-lived asset by the same amount as the liability.Over time, the asset retirement obligations are accreted for the change intheir present value. The initial capitalized costs are depleted over the usefullives of the related assets, through charges to depreciation, depletion andamortization. 

* *

* *

* *

* *

* *

F-9
**
PDC 2004-A LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Notes to Financial Statements, Continued

* *

*Derivative Financial Instruments*

* *

ThePartnership accounts for derivative financial instruments in accordance withFAS Statement No. 133 "Accounting for Derivative Instruments and CertainHedging Activities" as amended.  During 2005 and 2004, none of thederivative contracts qualified for hedge accounting under the terms of FAS No.133.  Accordingly, the derivative instruments are recorded as an asset orliability on the balance sheet at fair value and the change in the fair valueis recorded in oil and gas price risk management gain (loss), net. Because derivative arrangements are entered into by the Managing GeneralPartner on behalf of the Partnership, they are reported on the balance sheet asa net short-term or long-term receivable due from or payable due to theManaging General Partner.  Amounts due to the Managing General Partner forrealized losses and gains on closed derivative positions are included of$328,665 and $0 at December 31, 2005 and 2004 are included in the balance "Dueto Managing General Partner - other".

Themeasurement of fair value is based on actively quoted market prices, ifavailable. Otherwise, the Managing General Partner seeks indicative priceinformation from external sources including broker quotes and industrypublications. If pricing information from external sources is not available,measurement involves judgment and estimates. These estimates are based onvaluation methodologies considered appropriate by the Managing General Partner.

Byusing derivative financial instruments to manage exposures to changes incommodity prices, the Partnership exposes itself to credit risk.  Credit riskis the failure of the counterparty to perform under the terms of the derivativecontract.  When the fair value of a derivative contract is positive, thecounterparty owes the Managing General Partner, which in turn owes thePartnership thus creating repayment risk.  The Managing General Partnerminimizes the credit or repayment risk in derivative instruments by enteringinto transactions with high-quality counterparties.

*Income Taxes*

* *

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

*Use of Estimates*

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

*RecentlyIssued Accounting Standards*

In June 2005, the FASB issued SFAS No. 154,"Accounting Changes and Error Corrections, a replacement of APB OpinionNo. 20 and FASB Statement No. 3," which replaces Accounting Principles BoardOpinion No. 20, "Accounting Changes" and SFAS No. 3, "ReportingAccounting Changes in Interim Financial Statements," and changes the requirementsfor the accounting for and reporting of a change in accounting principle. SFASNo. 154 requires retrospective application for voluntary changes in accountingprinciple unless it is impracticable to do so, and it applies to all voluntarychanges in accounting principle.  SFAS No. 154 is effective for accountingchanges and corrections of errors made in fiscal years beginning after December15, 2005. Consequently, we will adopt the provisions of SFAS 154 for our fiscalyear beginning January 1, 2006. We currently believe that adoption of theprovisions of SFAS No. 154 will not have a material impact on our financialstatements.

In September 2006, the FASBissued SFAS No. 157, "Fair Value Measurements," which replaces severalexisting pronouncements, defines fair value, establishes a framework formeasuring fair value, and expands disclosures about fair value measurements. SFAS No. 157 is effective for financial statements issued for fiscal yearsbeginning after November 15, 2007, and interim periods within those fiscalyears.  Consequently, we will adopt the provisions of SFAS 157 for our fiscalyear beginning January 1, 2008.  The Partnership is currently evaluating theimpact of the provisions of SFAS No. 157 on its financial statements.

F-10

PDC 2004-A LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Notes to Financial Statements, Continued

(3)   Transactions with ManagingGeneral Partner and Affiliates

PDC,as the Managing General Partner, and its wholly-owned subsidiaries, RileyNatural Gas and PDC Securities Incorporated, are reimbursed for certainPartnership operating expenses and receive fees for services as provided for inthe partnership agreement.  As ofDecember 31, 2005 and 2004, the Partnership owed the Managing General Partner $551,615and $86,998, respectively.  As a result of derivative transactionsexecuted by the Managing General Partner on behalf of the Partnership, there werealso short term related party derivative payables of $344,301 and $121,011 atDecember 31, 2005 and 2004, respectively and long-term related party derivativepayables of $65,545 for 2005 and $0 for 2004.  The following table presents reimbursements and service fees paid bythe Partnership to PDC, or its affiliates, for the year ended December 31, 2005and the period from April 30, 2004 (date of inception) through December 31,2004.

2005

2004

Management fee

 $                       - 

 $                 435,463 

Drilling services

                          -  

               32,095,145 

Syndication costs

                          -  

                    583,857  

Well operations fees

              205,063 

                       67,101 

Inaddition, as the operator of the Partnership's wells, the Managing GeneralPartner receives all  proceeds from the sale of oil and gas produced and paysfor all costs incurred related to services, equipment and supplies from vendorsfor all well production and operating costs and other direct costs for thePartnership.  Net revenue from oil and gas operations is distributed monthly toall partners based on their share of costs and revenues.  

As described above, theManaging General Partner utilizes commodity-based derivative instruments,entered into on behalf of the Partnership, to manage a portion of thePartnership's exposure to price risk from oil and natural gas sales.  Theseinstruments consist of CIG (Colorado Interstate Gas) index-based contractstraded by JP Morgan for Colorado natural gas production. These derivativeinstruments have the effect of locking in for specified periods (atpredetermined prices or ranges of prices) the prices the Managing GeneralPartner will receive for the volume of oil and natural gas to which thederivative relates.  

The fair value of thecommodity based derivatives was $(409,846) and $(121,011) at December 31, 2005and 2004, respectively. The Partnership recognized in the statement of income arealized loss on commodity based derivatives of $840,432 and $160,424 for theyears ended December 31, 2005 and 2004, respectively. The following tablesummarizes the Partnership's share of open derivative positions as of December31, 2005 and 2004.

Open Derivative Positions

Commodity

Type

 Quantity   Gas-MMBtu Oil-Barrels

Weighted Average Price 

Fair Market Value

Partnership's  Share of Open Positions as of December 31, 2005:

Natural Gas

Sale Option

         960,452 

 $        6.03 

 $               208,051 

Natural Gas

Purchase Option

         373,903 

 $        7.61 

                (617,897)

Due to Managing General Partner - Derivatives, Total

 $             (409,846)

F-11

 PDC 2004-A LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Notes to Financial Statements, Continued

 Partnership's  Share of Open Positions maturing within 12 months following December 31,  2005:

Natural Gas

Sale Option

         886,026 

 $         6.03 

 $               184,486 

Natural Gas

Purchase Option

         336,690 

 $         7.53 

                (528,787)

Due to Managing General Partner - Derivatives, Short-term

 $             (344,301)

Partnership's  Share of Open Positions maturing within 12 months as of December 31, 2004:

Natural Gas

Sale Option

         253,304 

 $         3.58 

 $                 44,306 

Natural Gas

Purchase Option

         126,652 

 $         4.71 

                (101,669)

Oil

Sale Option

           34,356 

 $       32.30 

                    29,270 

Oil

Purchase Option

           17,178 

 $       40.00 

                  (92,918)

Due to Managing General Partner - Derivatives , Total

 $             (121,011)

AtDecember 31, 2005, the maximum term for the derivative positions listed aboveis 15 months.

(4)   Allocation of Partners' Interests

The table below summarizesthe participation of the Managing General Partner and the Investor Partners inthe costs and revenues of the Partnership.  At December 31, 2005, the ManagingGeneral Partner owns a 20% equity ownership in the Partnership.  

 Managing

Investor

General

Partnership Costs

Partners (e)

Partner (e)

Offering  Costs - Commissions, Due Diligence and Wholesaling (a)

100%

0%

Other  Organization and Offering Costs (a)

0%

100%

Management  Fee (b)

100%

0%

Lease  Costs

0%

100%

Tangible  Well Costs

0%

100%

Intangible  Drilling Costs

100%

0%

Operating  Costs (c)

80%

20%

Direct  Costs (d)

80%

20%

Partnership Revenues

 

 

Sale  of Oil and Gas Production

80%

20%

Sale  of Productive Properties

80%

20%

Sale  of Equipment 

0%

100%

Interest  Income

80%

20%

(a)  The Managing General Partner paid alllegal, accounting, printing, and filing fees associated with the organizationof the Partnership and the offering of units and is allocated 100% of thesecosts.  The Investor Partners paid all dealer manager commissions, discounts,and due diligence reimbursements and are allocated 100% of these costs.

(b)  Represents a one-time fee paid to theManaging General Partner upon the funding of the Partnership equal to 1-1/2% oftotal Investor Partner subscriptions.

F-12

PDC 2004-A LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Notes to Financial Statements, Continued

(c)   Represents operating costsincurred after the completion of productive wells, including monthly per-wellcharges paid to the Managing General Partner for well tending fees andPartnership administration fees.

(d)   The Managing General Partner isreimbursed by the Partnership for direct costs incurred by the Managing GeneralPartner on behalf of the Partnership, such as for independent auditor, reserveengineer and tax preparation fees.

(e)  To the extent that Investor Partnersreceive preferred cash distributions, the allocations for Investor Partnerswill be increased accordingly and the allocation for the Managing GeneralPartner will likewise be decreased.  See "Performance Standard Obligation ofManaging General Partner" below.

*PerformanceStandard Obligation of Managing General Partner*

* *

TheAgreement provides for the enhancement of investor cash distributions if thePartnership does not meet a performance standard defined in the Agreementduring the first 10 years beginning 6 months after the close of thePartnership.  In general, if the average annual rate of return to the InvestorPartners is less than 12.5% of their subscriptions, the allocation rate of cashdistributions to Investor Partners will increase by one-half of the ManagingGeneral Partner's interest until the average annual rate increases to 12.5%,with a corresponding decrease to the Managing General Partner.  The 12.5% rateof return is calculated by including the estimated benefit of a 25% income taxsavings on the investment in the first year in addition to cash distributionsmade to the Investor Partners.  During 2005, no obligation of the ManagingGeneral Partner arose under this provision.

*UnitRepurchase Provisions*

* *

InvestorPartners may request that the Managing General Partner repurchase units at anytime beginning with the third anniversary of the first cash distribution of thePartnership.  The repurchase price is set at a minimum of four times the mostrecent twelve months' of cash distributions from production.  The ManagingGeneral Partner is obligated to purchase, in any calendar year, InvestorPartner units aggregating to 10% of the initial subscriptions if requested bythe Investor Partners subject to its financial ability to do so and opinions ofcounsel.  No partnership units can be purchased under this provision by theManaging General Partner until thirty-six months after the first distributionto the partners.

(5)   Costs Relating to Oil and Gas Activities

ThePartnership is engaged solely in oil and gas activities, all of which arelocated in the continental United States.  Information regarding aggregatecosts and results of operations for these activities is located in the basicfinancial statements.  Capitalized costs for these activities at December 31,2005 and 2004, are as follows:

 
2005

2004

 
(Restated)

 
 

 
Leasehold costs

 $                 771,136 

 $                 771,136 

 
Development costs

               31,460,928 

               31,460,928 

 
 $            32,232,064 

 $            32,232,064 

 
F-13

PDC 2004-A LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Notes to Financial Statements, Continued

(6)   AssetRetirement Obligations

Changes in carrying amounts of the asset retirement obligationsassociated with our oil and gas properties at December 31, 2005 and 2004 are asfollows:

2005

2004

(Restated)

Balance at beginning of  year

 $         138,887 

 $                   -   

Obligations  assumed with development activities

and  acquisitions

                        - 

          136,919 

Accretion  expense

                8,160 

              1,968 

Balance  at end of year

 $         147,047 

 $        138,887 

The discount rate used incalculating the asset retirement obligation and related accretion was 5.75%.This rate approximates the borrowing rate of the Managing General Partner.    

(7)   Supplemental ReserveInformation (Unaudited)

Provedoil and gas reserves of the Partnership have been estimated at December 31,2005 and 2004 by independent petroleum engineers. These reserves have beenprepared in compliance with the Securities and Exchange Commission rules basedon year end prices.  All of the partnership's reserves are proved developedreserves.  An analysis of the change in estimated quantities of proveddeveloped oil and gas reserves is shown below:

Oil (Bbls)

2005

2004

Proved  developed reserves:

Beginning of year

 597,000 

- 

Revisions of previous estimates

 (76,000)

- 

New discoveries and extensions

 4,000 

666,000 

Production

 (61,000)

(69,000)

End of Year

 464,000 

597,000 

 Gas (MCF) 

2005

2004

Proved  developed reserves:

Beginning of year

 14,862,000 

- 

Revisions of previous estimates

 (1,103,000)

- 

New discoveries and extensions

52,000 

   15,582,000 

Production

 (1,625,000)

 (720,000)

End of Year

 12,186,000 

   14,862,000 

F-14

PDC 2004-A LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Notes to Financial Statements, Continued

(8)       Standardized Measure of Discounted FutureNet Cash Flows and Changes Therein Relating to Proved Oil and Gas Reserves(Unaudited)

Summarized in the following table is information for thePartnership with respect to the standardized measure of discounted future netcash flows relating to proved oil and gas reserves.  Future cash inflows are computedby applying year-end prices of oil and gas relating to the Partnership provedreserves to the year-end quantities of those reserves.  Future production,development, site restoration and abandonment costs are derived based oncurrent costs assuming continuation of existing economic conditions. 

December 31,

2005

2004

Future  estimated revenues

 $  123,914,432 

 $ 107,896,378 

Future  estimated production costs

 (27,322,929)

 (21,323,209)

Future  estimated development costs

   (3,352,882)

   (2,084,870)

   Future  net cash flows

   93,238,621 

 84,488,299 

10% annual  discount for estimated timing of cash flows

 (49,581,000)

 (43,516,000)

Standardized  measure of discounted future

   estimated  net cash flows

 $43,657,621 

 $   40,972,299 

The following table summarizes the principal sources of change inthe standardized measure of discounted future estimated net cash flow for theyear ended December 31, 2005, and the period from April 30, 2004 (date ofinception) through December 31, 2004:

2005

2004

(Restated)

Sales of oil  and gas production, net of production costs

 $  (12,390,003)

 $(5,862,786)

Net changes in  prices and production costs

   14,490,000 

 -   

Extensions,  discoveries, and improved recovery,

   less  related cost

 -   

 46,835,299 

Development  cost incurred during the period

 -   

 -   

Revisions of  previous quantity estimates

   (4,539,000)

 -   

Accretion of  discount

 4,527,000 

 -   

Timing and  other

597,325 

 -   

    Net change

 

 $  2,685,322 

 

 $   40,972,513 

Thedata presented should not be viewed as representing the expected cash flowfrom, 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-15

PDC 2004-A LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Notes to Financial Statements, Continued

(9)   Quarterly Financial Data(Unaudited)

 

Quarterlyfinancial data for the years ended December 31, 2005 and 2004 are as follows:

**STATEMENTS OF OPERATIONS**

For the Year

For the Three Months Ended

Ended

March 31,

June 30,

September 30,

December 31,

December 31, 

2005

2005

2005

2005

2005

(Restated)

Revenues:

 Oil and gas sales

 $ 3,687,777 

 $ 3,421,695 

 $ 3,340,241 

 $ 4,016,616 

 $14,466,329 

Costs and Expenses:

Production  and operating costs

       531,980 

       473,094 

       473,716 

       597,536 

     2,076,326 

Direct  costs

   2,102 

 (2,105)

   1,562 

 30,036 

 31,595 

Depreciation,  depletion and amortization

    1,178,164 

    1,104,228 

       894,901 

       892,552 

     4,069,845 

Accretion  of asset retirement obligations

   1,996 

   2,025 

   2,054 

   2,085 

    8,160 

Total  costs and expenses

    1,714,242 

    1,577,242 

    1,372,233 

    1,522,209 

     6,185,926 

Income from operations

    1,973,535 

    1,844,453 

    1,968,008 

    2,494,407 

     8,280,403 

Interest income

   1,763 

   1,764 

   6,072 

 11,816 

 21,415 

Oil and gas price risk  management (loss) gain, net

     (978,729)

       271,535 

 (1,295,271)

       873,199 

   (1,129,266)

Net income 

 $    996,569 

 $ 2,117,752 

 $    678,809 

 $ 3,379,422 

 $  7,172,552 

Net income per Investor  Partner unit

 $   549 

 $1,167 

 $   374 

 $1,863 

 $ 3,953 

**STATEMENTS OF OPERATIONS**

For the Period

For the Period

April 30, 2004

April 30, 2004

(date of inception)

For the Three Months Ended

(date of inception)

to June 30,

September 30,

December 31,

to December 31,

2004

2004

2004

2004

(Restated)

Revenues:

 Oil and gas sales

 $                -  

 $ 2,167,652  

 $ 4,519,630 

 $ 6,687,282 

Costs and Expenses:

Production  and operating costs

   - 

   267,182  

   557,314 

   824,496 

Management  fee

   435,463  

   - 

   - 

   435,463 

Direct  costs

   - 

 323  

 26,565 

 26,888 

Depreciation,  depletion and amortization

   - 

1,187,048  

1,639,023 

2,826,071 

Accretion  of asset retirement obligations

   - 

   - 

   1,968 

   1,968 

Total  costs and expenses

   435,463  

1,454,553  

2,224,870 

4,114,886 

(Loss) income from  operations

 (435,463)

   713,099  

2,294,760 

2,572,396 

Interest income

   5,347 

 16,357  

   9,572 

 31,276 

Oil and gas price risk  management loss, net

   - 

 (172,186)

 (109,249)

 (281,435)

Net (loss) income 

 $  (430,116)

 $557,270  

 $ 2,195,083 

 $ 2,322,237 

Net (loss) income per  Investor Partner unit

 $ (297)

 $   307 

 $1,210 

 $1,220 

F-16

PDC 2004-A LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Notes to Financial Statements, Continued

Quarterly results for theperiod from April 30, 2004 (date of inception) to June 30, 2004 and for thethree months ended September 30 and December 31, 2004 were not previouslyreported.  Thus, results for these periods included in this Form 10-K are not presentedas restated amounts.

BALANCE SHEETS

June 30,

September 30,

2005

2004

2005

2004

Assets

Current assets:

     Cash and cash  equivalents

$       16,231 

$ 10,777,100 

$       12,874 

$    2,468,497 

     Accounts receivable -  oil and gas sales 

   3,222,235 

 - 

   3,340,241 

   2,045,992 

          Total current  assets

   3,238,466 

 10,777,100 

   3,353,115 

   4,514,489 

Oil and gas properties,  successful efforts method

 32,232,064 

   8,831,568 

 32,232,064 

 27,318,153 

Less accumulated depreciation,  depletion and amortization

 (5,108,463)

 - 

 (6,003,364)

 (1,187,048)

Wells in progress

 - 

 12,388,737 

 - 

   2,296,121 

 27,123,601 

 21,220,305 

 26,228,700 

 28,427,226 

Total Assets

$ 30,362,067 

$ 31,997,405 

$  29,581,815 

$ 32,941,715 

Liabilities and Partners'  Equity

Current liabilities:

     Accounts payable and  accrued expenses

$   287,371 

$                -    

 $      305,311 

 $   148,487 

     Due to Managing General  Partner - derivatives

  526,205 

   -   

   1,423,955 

 106,977 

     Due to Managing General  Partner - other

 379,491 

   -   

 419,521 

44,197 

          Total current  liabilities

   1,193,067 

   -   

   2,148,787 

 299,661 

Due to Managing General  Partner - derivatives, long-term

40,856 

   -   

 187,754 

18,047 

Asset retirement obligations

 142,908 

58,525 

 144,962 

 127,857 

Partners' equity

 28,985,236 

 31,938,880 

 27,100,312 

 32,496,150 

Total Liabilities and  Partners' Equity

$ 30,362,067 

$ 31,997,405 

$  29,581,815 

$ 32,941,715 

Balance sheets as of June 30,2004 and September 30, 2004 were not previously reported.  Thus, the balancesat these dates included in this Form 10-K are not presented as restatedamounts.

F-17

PDC 2004-A LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Notes to Financial Statements, Continued

STATEMENTS OF OPERATIONS

For the Period

For the Period

 
For the

April 30, 2004

For the

April 30, 2004

 
Six Months Ended

(date of inception) to

Nine Months Ended

(date of inception) to

 
June 30, 2005

June 30, 2004

September 30, 2005

September 30, 2004

 
 
Revenues:

 
 Oil and gas sales

 $ 7,109,472 

 $                   -  

 $   10,449,713 

 $ 2,167,652 

 
 
Costs and Expenses:

 
Production and operating  costs

1,005,074 

   - 

1,478,790 

   267,182 

 
Management fee

   - 

   435,463 

   - 

   435,463 

 
Direct costs

(3)

   - 

   1,559 

 323 

 
Depreciation, depletion and  amortization

2,282,392 

   - 

3,177,293 

1,187,048 

 
Accretion of asset  retirement obligations

   4,021 

   - 

   6,075 

   - 

 
Total costs and expenses

3,291,484 

   435,463 

4,663,717 

1,890,016 

 
 
Income (loss) from  operations

3,817,988 

 (435,463)

5,785,996 

   277,636 

 
 
Interest income

   3,527 

   5,347 

   9,599 

 21,704 

 
Oil and gas price risk  management loss, net

 (707,194)

   - 

 (2,002,465)

 (172,186)

 
 
Net income (loss)

 $ 3,114,321 

 $  (430,116)

 $ 3,793,130 

 $127,154 

 
 
Net income (loss) per  Investor Partner unit

 $1,716 

 $ (297)

 $2,091 

 $ 10 

 
Quarterlyresults for the period from April 30, 2004 (date of inception) to June 30, 2004and for the period from April 30, 2004 (date of inception) to September 30,2004 were not previously reported.  Thus, results for these periods included inthis Form 10-K are not presented as restated amounts.

F-18

PDC 2004-A LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Notes to Financial Statements, Continued

**STATEMENTS OF CASH FLOWS**

For the Period

For the Period

For the

April 30, 2004

For the

April 30, 2004

Six Months Ended

(date of inception) to

Nine Months Ended

(date of inception) to

June 30, 2005

June 30, 2004

September 30, 2005

September 30, 2004

Cash flows from operating activities:

Net income (loss)

 $     3,114,321 

 $   (430,116)

 $ 3,793,130 

 $   127,154 

Adjustments to reconcile net  income (loss) to 

      net  cash provided by (used in) operating activities:

Depreciation,  depletion and amortization

2,282,392 

   - 

    3,177,293 

   1,187,048 

Accretion  of asset retirement obligations

       4,021 

   - 

   6,075 

 - 

Unrealized  loss on derivative transactions

   446,050 

   - 

    1,490,698 

      125,024 

Changes  in operating assets and liabilities:

Decrease  (increase) in accounts receivable -

   oil and gas sales

1,184,137 

   - 

    1,066,131 

 (2,045,992)

Increase  (decrease)in accounts payable and 

   accrued expenses

 (189,208)

   - 

     (171,268)

      148,487 

Increase  in due to Mananging General Partner - other

    292,493 

   - 

       332,523 

44,197 

Net  cash provided by (used in) operating activities

 7,134,206 

 (430,116)

    9,694,582 

     (414,082)

Cash flows from investing  activities:

Expenditures  for oil and gas properties

       - 

 (21,161,780)

 - 

(29,486,417)

Net  cash used in investing activities

       - 

 (21,161,780)

 - 

(29,486,417)

Cash flows from financing  activities:

Investor  Partners' contributions

       - 

 25,982,288 

 - 

 25,982,288 

Managing  General Partner contribution

       - 

    6,386,708 

 - 

   6,386,708 

Syndication  costs paid

       - 

   - 

 - 

 - 

Distributions  to partners

       (7,148,922)

   - 

 (9,712,655)

 - 

Net  cash (used in) provided by financing activities

 (7,148,922)

 32,368,996 

 (9,712,655)

 32,368,996 

Net (decrease) increase in  cash and cash equivalents

    (14,716)

 10,777,100 

       (18,073)

   2,468,497 

Cash and cash equivalents at  beginning of period

     30,947 

   - 

 30,947 

 - 

Cash and cash equivalents at  end of period

 $  16,231 

 $     10,777,100 

 $      12,874 

 $2,468,497 

Quarterlycash flows for the period from April 30, 2004 (date of inception) to June 30,2004 and for the period from April 30, 2004 (date of inception) to September30, 2004 were not previously reported.  Thus, cash flows for these periodsincluded in this Form 10-K are not presented as restated amounts.

F-19

PDC 2004-A LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Notes to Financial Statements, Continued

(10) Restatement of Historical Financial Statements 

During2005, errors were identified with respect to the Partnership's use of hedgeaccounting for certain transactions under Statement of Financial AccountingStandards No. 133, "Accounting for Derivative Instruments and HedgingActivities," as amended (FAS 133).  Accordingly, the Partnership revised itsaccounting for its derivative transactions after determining that the Partnership'sderivative transactions did not qualify for hedge accounting. These errorsbegan upon inception in 2004 and continued through the first quarter of 2005.The Partnership did not have sufficient documentation required for thesederivatives to qualify for hedge accounting treatment and did not test themperiodically for effectiveness as required by FAS 133.

ThePartnership also determined its interpretation of the accounting related toasset retirement obligations was not consistent with the applicable rules inStatement of Financial Accounting Standards No. 143, "Accounting for AssetRetirement Obligations" ("FAS 143").  FAS 143 requires that the fair value ofthe Partnership's plugging and abandonment obligations be recorded at the timethe obligations are incurred, which is at the time the well is completelydrilled.  Upon initial recognition of an asset retirement obligation, thePartnership should increase the carrying amount of the long-lived asset by thesame amount as the liability.  Over time, the liabilities are accreted for thechange in their present value through charges to income.  The initialcapitalized costs are depleted over the useful lives of the related assetsthrough charges to depreciation, depletion and amortization.  In accounting forasset retirement obligations, the Partnership did not properly account for the establishmentof the liabilities.  The impact of the corrections to apply the proper methodof accruing for well plugging and abandonment costs are included in the restatedfinancial statements.

Lastly,the Partnership corrected its accounting for oil and gas properties due to thefollowing reasons:
- The     Partnership determined its calculation of depreciation, depletion and     amortization was not consistent with applicable rules in Statement of     Financial Accounting Standards No. 19, "Financial Accounting and     Reporting by Oil and Gas Producing Companies" ("FAS 19").      According to FAS 19, a field is defined to be "an area consisting of a     single reservoir or multiple reservoirs all grouped on or related to the     same individual geological structural feature and/or stratigraphic     condition."  In accounting for its oil and gas properties, the Partnership     included areas that should have been treated as separate fields as part of     a single field.  The impact of corrections to divide the Partnership's oil     and gas properties into revised fields are included in the restated     financial statements.  
- In     addition, the Partnership used its proved developed reserves, as defined     by Securities and Exchange Commission rules, to calculate depreciation.      The Partnership's proved developed reserves included the anticipated     recompletion of the Codell formation in the Wattenberg Field in Colorado.  After reviewing the rules, the Partnership concluded that the future estimated     costs and the reserves from these recompletions should be excluded in     calculating the depreciation amounts.  The change resulted in increases in     depreciation compared to the method previously used by the Company until     the recompletions and behind pipe reserves are completed.  The financial     impact of corrections to exclude both the future estimated costs and the     reserves from these "behind pipe reserves" in calculating depreciation     amounts are included in the restated financial statements.
- Certain     policies and procedures followed by the Partnership for calculating     quarterly depreciation were incorrect.  The Partnership utilized the     previous annual oil and gas reserve reports to estimate quarterly     depreciation and adjusted the yearly depreciation based upon the new oil     and gas reserve report at the end of the next year.  However, each interim     period's depreciation must stand on its own and should not be adjusted at     the year end upon the issuance of a new oil and gas reserve report.  The     financial impact of corrections to calculate each interim period's     depreciation on its own were included in the restated financial     statements.

*Effectsof the Restatement*

Therestatement also impacted or made changes to the following financial statementfootnotes: Note 2, 3, 5, 6, 8 and added Note 10, Restatement of HistoricalFinancial Statements.

Thefollowing tables set forth the effects of the restatement relating to thederivatives transactions, oil and gas property depreciation and depletion, andasset retirement obligations on net income within the Partnership's previouslyreported operations for the quarter ended March 31, 2005 and the period fromApril 30, 2004, (date of inception) through December 31, 2004.

F-20

PDC 2004-A LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Notes to Financial Statements, Continued

This restatement resulted  in the following adjustments to Net Income:

* *

* *

Period from 

Quarter

April 30, 2004

Income / (expense) 

Ended

(date of inception) to

March 31, 2005

December 31, 2004

(Unaudited)

Depreciation, depletion and  amortization 

 $                    (89,681)

 $                  (847,815)

Disqualification of the use  of hedge accounting

                     (903,715)

                     (121,012)

Asset retirement  obligations

                         (1,735)

                         (1,300)

Net decrease in reported  net income

 $                  (995,131)

 $                  (970,127)

Restatedfinancial statements for the quarter ended March 31, 2005 and the period fromApril 30, 2004 (date of inception) through December 31, 2004, are presentedbelow.  Amounts previously reported in the statement of operations undercosts and expenses line items "independent engineering fee", "independent auditfee", "tax return preparation" and "direct administrative cost" are presentedin the line item "direct costs" in the statement of operations in both the"Previously Reported" and "Restated" columns.  This reclassification, toconform to the current year presentation, did not affect net income or total costsand expenses.   Similarly, interest income and oil and gas price riskmanagement gain or loss (previously classified within revenues) has beenpresented, in the "Restated" column, outside of income from operations, toconform to the current year presentation. 

**STATEMENTS OF OPERATIONS**

For the Period From

April 30, 2004

For the Quarter Ended

(date of inception) to

March 31, 2005

December 31, 2004

Previously

Previously

Reported

Restated

Reported

Restated

(Unaudited)

(Unaudited)

Revenues:

Oil and gas sales

$ 3,612,763 

$ 3,687,777 

$ 6,526,859 

$ 6,687,282 

Interest income

       1,763 

     - 

     31,276 

     - 

3,614,526 

3,687,777 

6,558,135 

6,687,282 

Costs and Expenses:

Production and operating  costs

   531,980 

   531,980 

   824,496 

   824,496 

Management fee

       -  

       - 

   435,463 

   435,463 

Direct costs

 2,363 

       2,102 

     27,556 

     26,888 

Depreciation, depletion and  amortization

1,088,483 

1,178,164 

1,978,256 

2,826,071 

Accretion of asset  retirement obligation

       - 

       1,996 

       - 

       1,968 

 Total costs and expenses

1,622,826 

1,714,242 

3,265,771 

4,114,886 

Income from operations

1,991,700 

1,973,535 

3,292,364 

2,572,396 

Interest income

       -  

       1,763 

       - 

     31,276 

Oil and gas price risk  management loss, net

       - 

 (978,729)

       - 

(281,435)

 

 

 

 

Net income

$ 1,991,700 

 $996,569 

 

$ 3,292,364 

$ 2,322,237 

Net income per Investor  Partner unit

 $    1,098 

 $       549 

 

 $    1,755 

 $    1,220 

F-21

PDC 2004-A LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Notes to Financial Statements, Continued

BALANCE SHEETS

March 31, 2005

December 31, 2004

Previously

Previously

Reported

Restated

Reported

Restated

(Unaudited)

(Unaudited)

Assets

Current assets:

Cash and cash equivalents

$        28,835 

$       28,835 

$        30,947 

$       30,947 

Accounts receivable - oil  and gas sales

3,062,009 

3,536,733 

3,942,937 

4,406,372 

Due from Managing General  Partner - other

   1,763 

     - 

      - 

                 - 

Total current assets

 3,092,607 

3,565,568 

3,973,884 

4,437,319 

Oil and gas properties,  successful efforts method

32,111,848 

32,232,064 

32,111,848 

32,232,064 

Less accumulated  depreciation, depletion and amortization

(3,066,739)

(4,004,235)

(1,978,256)

(2,826,071)

29,045,109 

 28,227,829 

30,133,592 

 29,405,993 

Due from Managing General  Partner - derivatives, long-term

        - 

       12,935 

        - 

            - 

Total Assets

$32,137,716 

$31,806,332 

$34,107,476 

$33,843,312 

Liabilities and Partners'  Equity

Current liabilities:

Accounts payable and accrued  expenses

$     405,136 

$    424,142 

$    221,153 

$     476,579 

Due to Managing General  Partner - derivatives

     - 

 1,037,663 

            - 

 121,011 

Due to Managing General Partner  - other

         - 

   89,210 

              - 

 86,998 

Total current liabilities

 405,136 

 1,551,015 

 221,153 

 684,588 

Asset retirement obligations

 17,632 

 140,883 

    17,371 

 138,887 

Partners' equity

31,714,948 

30,114,434 

33,868,952 

33,019,837 

Total Liabilities and  Partners' Equity

$32,137,716 

$31,806,332 

$34,107,476 

$33,843,312 

Statementof Cash Flows:

Onlycertain line items within cash flows from operating activities have beenrestated.  The net change in cash and cash equivalents for the period and thecash and cash equivalents balance at the end of the period are the same as inthe original presentation of the financial statements.  No changes were made tothe cash flows from investing and financing activities.  Accordingly, noreconciliation of the statement of cash flows is provided herein. 

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