10-K 1 pdc10k12052004a11.htm PART I

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C.  20549

FORM 10-K

ANNUAL REPORT

PURSUANT TO SECTIONS 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

                        (Mark One)

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

For the fiscal year ended December 31, 2005

OR

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

For the transition period from                 to

Commission File Number  000-51218

PDC 2004-A LIMITED PARTNERSHIP

(Exact name of registrant as specified 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 executive offices)     (zip code)

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

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

SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:

General and Limited Partnership Interest

(Title of class)



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

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

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

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

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

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

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

Yes        No   X  

There is no trading market for the registrant's securities.

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TABLE OF CONTENTS

PART I

Item 1        Business

Item 1A     Risk Factors

Item 1B      Unresolved Staff Comments

Item 2        Properties

Item 3        Legal Proceedings

Item 4        Submission of Matters to a Vote of Security Holders

PART II

Item 5        Market for Registrant's Common Equity and Related Stockholder Matters

Item 6        Selected Financial Data

Item 7        Management's Discussion and Analysis of Financial Condition and Results of Operations

Item 7A     Quantitative and Qualitative Disclosures About Market Risk

Item 8        Financial Statements and Supplementary Data

Item 9        Changes in and Disagreement with Accountants on Accounting and Financial Disclosure

Item 9A     Controls and Procedures

Item 9B      Other Information

PART III

Item 10      Directors and Executive Officers of the Registrant

Item 11      Executive Compensation

Item 12      Security Ownership of Certain Beneficial Owners and Management and Related Stockholders Matters

Item 13      Certain Relationships and Related Transactions

Item 14      Principal Accountant Fees and Services

PART IV

Item 15      Exhibits and Financial Statement Schedules

Signatures

Financial Statements

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PART I

ITEM 1.  BUSINESS

 

Restatement of Historical Financial Statements

Overview

Petroleum Development Corporation ("PDC" or the "Company") is the Managing General Partner for PDC 2004-A Limited Partnership (the "Partnership").  The Managing General Partner manages all of the Partnership's exploration and production activities, accounting, and reporting requirements.  The Partnership has no employees and all accounting and reporting has been performed by the Partnership's Managing General Partner and its staff.  For disclosures in this Form 10-K, the management and officers of the Partnership refers to management and officers of the Managing General Partner.

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

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

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

The following tables set forth a summary of the adjustments for the restatement and their impact on net income for the period from April 30, 2004 through December 31, 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)

 

 

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Material Weaknesses and Accounting Issues

The Partnership has evaluated the effectiveness of the design and operation of its disclosure and control procedures.  During 2005, the Partnership determined that there were errors in previously filed financial statements which required a restatement of the financial statements.  As a result of this review of accounting procedures and policies, the Partnership concluded that, as of December 31, 2005, disclosure controls and procedures were not effective to ensure that information required to be disclosed in the reports filed under the Exchange Act are recorded, processed, summarized, and reported within the time periods specified in the SEC's rules and forms. 

During 2005, the Partnership identified material weaknesses related to its policies and procedures and technical expertise in U.S. generally accepted accounting principles to ensure the preparation of accurate and reliable interim and annual financial statements. Specifically, the Partnership lacked personnel with sufficient technical accounting and financial reporting expertise and also lacked policies and procedures in place to determine and document the appropriate application of accounting principles. These deficiencies impacted the Partnership's accounting for derivatives, asset retirement obligations and depreciation, depletion and amortization, and resulted in more than a remote likelihood that a material misstatement of the annual or interim financial statements would not be prevented or detected. 

To address the material weaknesses, we performed additional analyses and other post-closing procedures to ensure that the financial statements were prepared in accordance with generally accepted accounting principles.  Accordingly, management of the Partnership believes that the financial statements included in this report fairly present in all material respects the Partnership's financial position, results of operations and cash flows for the periods presented.  See Item 9A. "Controls and Procedures" for information concerning these material weaknesses.

For additional information relating to the effect of our restatement, see the following items:

          ●  Item 6.  Selected Financial Data

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

          ●  Item 8.  Financial Statements and Supplementary Data

General

The Partnership was organized as a limited partnership pursuant to the West Virginia Uniform Limited Partnership Act for the purpose of aggregating funds for the exploration and production of oil and natural gas.  Business operations of the Partnership commenced on April 30, 2004, upon the closing of the offering for the sale of the partnership units.

Pursuant to a registration statement filed with the Securities and Exchange Commission, limited and general partnership interests were registered for an offering under the PDC 2004-2006 Drilling Program for the formation of a series of limited partnerships.  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 contributed by the Managing General Partner. Total funding of the Partnership was $35,449,894.  The capital contributions from the Investor Partners consisted of 1,451.54 partnership 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 commence Partnership activities for the drilling of natural gas and oil wells. During 2005, all additional general partners were converted to limited partners under provisions of the Partnership Agreement.

Under the terms of the Partnership Agreement, the allocation of production revenues among the Investor Partners and the Managing General Partner is as follows:

 Allocation

of Revenues

Investor Partners

    80%

Managing General Partner

    20%

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Operating and direct costs are allocated and charged to the Investor Partners and the Managing General Partner in the same percentages as revenues are allocated.  See "Note 4 - Allocation of Partners' Interests" in the Notes to the Financial Statements for a complete description of the allocation of all Partnership revenues and costs.

Drilling Activities

Since its formation, the Partnership has been engaged in onshore, domestic oil and natural gas exploration and production exclusively in the Rocky Mountain Region. The Partnership participated in drilling only development wells. Due to natural gas being the predominant production, all wells are classified as gas wells although significant amounts of oil can be produced in association with the gas.  The following table summarizes the Partnership's drilling activities during 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

 

The thirty-seven wells in the table above are the only wells the Partnership will drill and all of the capital contributions provided by the partnership offering were utilized during 2004.

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

Plan of Operations

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

Employees

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

Markets for Oil and Gas

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

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

Derivatives and Hedging Activities

Historically, PDC and RNG have utilized commodity based derivative instruments to manage a portion of the exposure to price volatility stemming from natural gas and crude oil production.  In order to provide a more predictable cash flow stream, PDC expects to continue the use of derivative instruments including the Partnership's production of natural gas and oil, and will enter into derivative contracts on behalf of the Partnership.  PDC may use financial hedges, put options, call options, and other derivative instruments to offset variations in prices.  The contracts hedge committed and anticipated natural gas and oil sales generally forecasted to occur within the next two-year period. The Managing General Partner does not hold or issue derivatives for trading or speculative purposes and permits utilization of hedges only if there is an underlying physical position.  See "Commodity Price Risk" under Item 7A in this Form 10-K.

Competition

The Partnership competes in marketing its gas and oil with numerous companies and individuals, many of which have financial resources, staffs and facilities substantially greater than those of the Partnership or PDC.

Governmental Regulations

Federal and state regulatory authorities have established rules and regulations requiring permits for well operations, reclamation bonds and reports concerning operations.  States also have statutes and regulations concerning the spacing of wells, environmental matters and conservation, and have established regulations concerning the unitization and pooling of oil and gas properties and maximum rates of production from oil and gas wells.

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

Environmental and Safety Regulations.  The Partnership believes that it complies, in all material respects, with all legislation and regulations relating to environmental and safety matters in the drilling and production of oil and gas wells and the discharge of wastes.  Compliance with such provisions and regulations is significant during well development but has not had a material effect upon the Partnership's expenditures for capital equipment, its operations or its competitive position.  The cost of such compliance is not anticipated to be material in the future.

The Partnership believes it has complied in all material respects with applicable state and federal regulations.  The Partnership spent approximately $176,000 in 2004 for expenditures related primarily to environmental permitting and compliance; the amounts spent in 2005 are deemed not material. 

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ITEM 1A.  RISK FACTORS

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

Drilling natural gas and oil wells is speculative and may be unprofitable or result in the total loss of investment. The drilling and completion operations undertaken by the Partnership for the development of natural gas and oil reserves are inherently speculative and involve a high degree of risk and the possibility of a total loss of investment. Drilling activities may result in unprofitable well operations, not only from non-productive wells, but also from wells that do not produce natural gas or oil in sufficient quantities or quality to return a profit on the amounts expended.  Consequently, Partnership wells may not produce sufficient natural gas and oil for investors to receive a profit or even to recover their initial investment.  Only three of the prior Partnerships sponsored by PDC have, to date, generated cash distributions in excess of investor subscriptions without tax savings.  PDC cannot predict whether any prospect will produce commercial quantities of natural gas or oil.  PDC cannot predict the life and the ultimate production of any wells, and the actual lives could differ from those anticipated.

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

The additional general partners will be individually liable for Partnership obligations and liabilities that arose prior to conversion to limited partners (which can occur only after the drilling completion operations are finished) that are beyond the amount of their subscriptions, Partnership assets, and the assets of the Managing General Partner.  Under West Virginia law, the state in which the Partnership has organized, general partners of a limited partnership have unlimited liability with respect to the Partnership.  Therefore, the additional general partners of the Partnership will be liable individually and as a group for all obligations and liabilities of creditors and claimants, whether arising out of contract or tort or in the conduct of the Partnership's operations, until such time as the additional general partners are converted to limited partners.  Under the Partnership Agreement, this conversion is not scheduled to occur until the drilling and completion operations are finished.  Irrespective of conversion, the additional general partners will remain fully liable for obligations and liabilities that arose prior to conversion.  Investors as additional general partners may be liable for amounts in excess of their subscriptions, the assets of the Partnership including insurance coverage, and the assets of the Managing General Partner.

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

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

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

The high level of drilling activity could 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 demand compared to the supplies available, leading in general to higher prices for natural gas.  The high level of drilling, combined with a reduction in demand resulting from higher prices, could result in an oversupply of natural gas.  In the Rocky Mountain region, rapid growth of production and increasing supplies may result in lower prices and production curtailment due to limitations on available pipeline facilities or markets not developed to utilize or transport the new supplies.  In both cases, the result would probably be lower prices for the natural gas the Partnership produces, reduced profitability for the Partnership and reduced cash distributions to the Investor Partners.

Sufficient insurance coverage may not be available for the Partnership, thereby increasing the risk of loss for the Investor Partners.  It is possible that some or all of the insurance coverage which the Partnership has available may become unavailable or prohibitively expensive.  In that case, PDC might elect to change the insurance coverage.  The additional general partners could be exposed to additional financial risk due to the reduced insurance coverage and due to the fact that additional general partners would continue to be individually liable for obligations and liabilities of the Partnership.  Investor Partners could be subject to greater risk of loss of their investment because less insurance would be available to protect the Partnership from casualty losses.  Moreover, should the Partnership's cost of insurance become more expensive, the amount of cash distributions to the investors will be reduced.

Through their involvement in Partnership and other non-partnership activities, the Managing General Partner and its affiliates have interests which conflict with those of the Investor Partners; actions taken by the Managing General Partner in furtherance of its own interests could result in the Partnership being less profitable and a reduction in cash distributions to the investors.  PDC's continued active participation in oil and natural gas activities for its own account and on behalf of other partnerships organized or to be organized by PDC, and the manner in which Partnership revenues are allocated, creates conflicts of interest with the Partnership.  PDC has interests which inherently conflict with the interests of the Investor Partners.  In operating the Partnership, the Managing General Partner and its affiliates could take actions which benefit themselves and not the Partnership.  These actions could result in the Partnership's being less profitable.  In that event, an Investor Partner could anticipate a reduction of cash distributions.

The Partnership and other partnerships sponsored by the Managing General Partner may compete with each other for prospects, equipment, contractors, and personnel; as a result, the Partnership may find it more difficult to operate effectively and profitably.  During and after 2006, PDC plans to offer interests in other partnerships to be formed for substantially the same purposes as those of the Partnership.  Therefore, a number of partnerships with unexpended capital funds, including those partnerships formed before and after the Partnership, may exist at the same time.  The Partnership may compete for equipment, contractors, and PDC personnel which may make it more difficult and more costly to obtain services for the Partnership.  In that event, it is possible that the Partnership would be less profitable.  Additionally, because PDC must divide its attention in the management of its own affairs as well as the affairs of over seventy-five limited partnerships PDC has organized in other programs, the Partnership will not receive PDC's full attention and efforts at all times.

The Partnership's derivative activities could result in reduced revenue compared to the level the Partnership might experience if no derivative instruments were in place.  The Partnership expects to use derivative instruments to reduce the impact of price movements on revenue.  While these derivative instruments protect the Partnership against the impact of declining prices, they also may limit the positive impact of price increases.  As a result, the Partnership may have lower revenues when prices are increasing than might otherwise be the case, which may also reduce the Partnership's cash flows and cash distributions to the Investor Partners.

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Hedging transactions have, in the past, and may, in the future, impact our cash flow from operations.  Our commodity hedging may prevent us from benefiting fully from price increases and may expose us to other risks.  PDC will enter into hedging arrangements to reduce the Partnership's exposure to fluctuations in natural gas and crude oil prices and to achieve more predictable cash flow.  Although the Partnership's hedging activities may limit the Partnership's exposure to declines in natural gas and crude oil prices, these activities may also limit and have, in the past, limited, additional revenues from increases in natural gas and crude oil prices.  To the extent that the Partnership has PDC engage in hedging activities to protect itself from commodity price volatility, the Partnership may be prevented from realizing 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 of the partnership, may not adequately protect the Partnership from financial loss due to circumstances such as:

•         Highly volatile natural gas and crude oil prices;

•         Production being less than expected; or

•         A counterparty defaults on its contractual obligations.

A significant financial loss by the Managing General Partner could result in PDC's inability to indemnify additional general partners for personal losses suffered because of Partnership liabilities.  As a result of PDC's commitments as Managing General Partner of several partnerships and because of the unlimited liability of a general partner to third parties, PDC's net worth is at risk of reduction if PDC suffers a significant financial loss.  Because PDC is primarily responsible for the conduct of the Partnership's affairs, as well as the affairs of other partnerships for which PDC serves as managing general partner, a significant adverse financial reversal for PDC could result in PDC's inability to pay Partnership liabilities and obligations.  The additional general partners of the Partnership might be personally liable for payments of Partnership's liabilities and obligations.  Therefore, the Managing General Partner's financial incapacity could increase the risk of personal liability as an additional general partner because PDC would be unable to indemnify the additional general partners for any personal losses suffered arising from Partnership operations.

The Managing General Partner may not have sufficient funds or budget to repurchase limited partnership units.  As a result of the Managing General Partner being a general partner in several partnerships, the Partnership's net worth is at risk of reduction if PDC suffers a significant financial loss.  Because the investors may request the Managing General Partner to repurchase the units in the Partnership, subject to certain conditions and restrictions, a significant adverse financial reversal could result in the Managing General Partner's inability to pay for Partnership obligations or the repurchase of investor units. 

Fluctuating market conditions and government regulations may cause a decline in the profitability of the Partnership.  The sale of any natural gas and oil produced by the Partnership will be affected by fluctuating market conditions and governmental regulations, including environmental and safety standards set by state and federal agencies.  From time-to-time, a surplus of natural gas or oil may occur in areas of the United States.  The effect of a surplus may be to reduce the price the Partnership receives for the natural gas or oil production, or to reduce the amount of natural gas or oil that the Partnership may produce and sell.  As a result, the Partnership may not be profitable.  Lower prices and/or lower production and sales will result in lower revenues for the Partnership and a reduction in cash distributions to the partners of the Partnership.

Environmental hazards involved in drilling natural gas and oil wells may result in substantial liabilities for the Partnership.  There are numerous natural hazards involved in the drilling of wells, including unexpected or unusual formations, pressures, blowouts involving possible damages to property and third parties, surface damages, personal injury or loss of life, damage to and loss of equipment, reservoir damage, and loss of reserves.  Uninsured liabilities would reduce the funds available to the Partnership, may result in the loss of Partnership properties, and may create liability for additional general partners.  The Partnership may become subject to liability for pollution, abuses of the environment and other similar damages, and insurance coverage may be insufficient to protect the Partnership against all potential losses.  In that event, Partnership assets would be used to pay personal injury and property damage claims and the costs of controlling blowouts or replacing destroyed equipment rather than for drilling activities.  These payments would cause an otherwise profitable partnership to be less profitable or unprofitable and would result in a reduction of cash distributions to the partners of the Partnership.

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

The present value of proved reserves will not necessarily equal the current fair market value of the estimated oil and gas reserves. In accordance with the reserve reporting requirements of the SEC, the estimated discounted future net cash flows from proved reserves are based on prices and costs as of the date of the estimate. Actual future prices and costs may be materially higher or lower than those as of the date of the estimate. The timing of both the production and the expenses with respect to the development and production of oil and gas properties will affect the timing of future net cash flows from proved reserves and their present value.

Seasonal weather conditions may adversely affect the Partnership's ability to conduct drilling, completion and production activities in some of the areas where we operate.  Oil and natural gas operations in the Rocky Mountains are adversely affected by seasonal weather conditions. In certain areas, drilling and other oil and natural gas activities are restricted or prevented by weather conditions for up to 6 months out of the year. This limits operations in those areas and can intensify competition during those months for drilling rigs, oil field equipment, services, supplies and qualified personnel, which may lead to periodic shortages. These constraints and the resulting shortages or high costs could delay operations and materially increase operating and capital costs and therefore, adversely affect profitability.

ITEM 1B.  UNRESOLVED STAFF COMMENTS

None.

ITEM 2.  PROPERTIES

Drilling Activity

The following table sets forth the results of the Partnership's drilling activity as of December 31, 2005.  All of the Partnership's wells drilled and producing are located 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

A development well is a well that is drilled close to and into the same formation as wells which have already produced and sold oil or natural gas.  An exploratory well is one which is drilled in an area where there has been no oil or natural gas production, or a well which is drilled to a previously untested or non-producing zone in an area where there are wells producing from other formations.  Productive wells consist of producing wells and wells capable of producing oil and gas in commercial quantities, including gas wells awaiting pipeline connections to commence deliveries.  A gross well refers to the number of wells in which the Partnership has an interest.  A net well refers to a gross well multiplied by the percentage working interest in the wells owned by the Partnership.

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

Production

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

Reserves

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

Title to Properties

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

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

ITEM 3.  LEGAL PROCEEDINGS

The Partnership is not a party to any legal proceedings.

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

ITEM 4.  SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

None.

PART II

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

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

ITEM 6.  SELECTED FINANCIAL DATA

The selected financial data presented below has been restated to reflect adjustments to correct accounting errors in our financial statements and has been derived from audited financial statements of the Partnership.  See the Financial 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'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.

Safe Harbor Statement Under the 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, future cash flows and the Partnership's strategies, plans and objectives, are "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933, as amended (the "Securities Act"), and Section 21E of the Securities Exchange Act of 1934, as amended (the "Exchange Act").  Although the Partnership believes that its forward looking statements are based on reasonable assumptions, it cautions that such statements are subject to a wide range of risks, trends and uncertainties, incidental to the production and marketing of oil and gas, that could cause actual results to differ materially from those projected.  Among those risks, trends and uncertainties are important factors that could cause actual results to differ materially from the forward looking statements, including, but not limited to, changes in production volumes, worldwide demand and commodity prices for petroleum natural resources; risks incidental to the operation of oil and gas wells; future production and development costs; the effect of existing and future laws, governmental regulations and the political and economic climate of the United States; the effect of derivative activities; and conditions in the capital markets.  In particular, careful consideration should be given to cautionary statements made in this Form 10-K and in the various reports the Partnership has filed with the Securities and Exchange Commission.  The Partnership undertakes no duty to update or revise these forward-looking statements.

When used in this Form 10-K, the words, "expect," "anticipate," "intend," "plan," "believe," "seek," "estimate" and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain these identifying words. Because these forward-looking statements involve risks and uncertainties, actual results could differ materially from those expressed or implied by these forward-looking statements for a number of important reasons, including those discussed under "Item 1A - Risk Factors" and elsewhere in this Form 10-K.

Restatement of Historical Financial Statements

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

-13-



A summary of the adjustments included in the restatement and their impact on net income and partners' equity for the year ended December 31, 2004, and for the quarter ended March 31, 2005, is included in "Item 1 - Business" above.  These restatements had no effect on the Partnership's cash flows.

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

Overview

The Partnership was funded on April 30, 2004, with Investor Partner contributions of $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 fee to the Managing General Partner of $435,463, the Partnership had available cash of $32,095,145 with which to commence the Partnership's drilling activities.

The drilling of the Partnership's oil and gas wells commenced in May 2004, following the funding of the Partnership.  Drilling activities and completion activities continued until the last of the thirty-seven wells in which the Partnership participated was connected to a pipeline in December 2004.  The thirty-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.  The wells produce predominantly natural gas along with associated crude oil.  No additional wells will be drilled and no additional development or exploratory work will be undertaken because all of the funds from the initial capital contributions of the partners were expended on the development of these thirty-seven wells. 

Initial production from the Partnership's wells commenced in June 2004 upon connecting the first well to a pipeline.   Production and sales of natural gas and oil from the Partnership's wells increased steadily during the second half of 2004 as additional wells were completed and placed into production, the last of which occurred in December 2004. 

 

Results of Operations - 2005 as compared to 2004

The following table presents significant operational information for the year ended December 31, 2005, as compared to the period from April 30, 2004 (date of inception) through December 31, 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.

As reflected in the table above, oil and gas sales increased by 116% over the prior year.  This increase was due to the increase in production of natural gas and 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 progress during the months of May through December and did not reflect a full year of production.  A portion of the sales increase related to the increase in average natural gas and oil prices that occurred during 2005.

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

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

Liquidity and Capital Resources

The Partnership had a working capital balance at December 31, 2005 of $2,740,273, which generally represents the receivables from oil and gas sales for the preceding three months, offset by accounts payable from oil and gas activity and short-term derivative values.

Future operations are expected to be funded from revenues generated from oil and gas production activities.  Current production revenues exceed operating costs by a wide margin.  The Partnership finished the drilling and completion of its thirty-seven wells in December 2004 and all of the $32,095,145 available from the initial partner contributions was utilized in this process.  There are no plans and no provision in the Partnership Agreement for additional development or exploration beyond these thirty-seven wells, and there are no present capital needs of the Partnership (see "Item 1. Business - Plan of Operations" above).  Under the Partnership Agreement, the Managing General Partner is allowed to and may withhold production revenues in advance of significant recompletion work on existing wells that may arise; however, the Partnership is not permitted to borrow funds.  If Partnership funds are used for recompletion work, the cash distributions to the partners at the time of the recompletions will be reduced, but should result in additional cash distributions following the recompletions.

The production phase of operations will continue for the expected life of the wells and until the wells can no longer be operated economically.  As wells are produced, the proceeds from the sale of oil and gas are collected and distributed, net of operating costs, on a routine basis by the Managing General Partner and are not retained by the Partnership.  Normally, all available funds from the sales of oil and gas, net of operating costs, are distributed monthly to the partners. 

Oil and Gas Reserves

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

-15-



Quarterly Analysis - 2005 Quarters versus 2004 Quarters

Overview

The quarterly analysis presented below provides substantially all of the information that would normally be contained in quarterly reports on Form 10-Q as part of this Form 10-K.  As explained in the Restatement of Historical Financial Statements in "Item 1 - Business" above, this comprehensive Form 10-K includes all annual and quarterly financial information for 2004 and 2005, including restated information, in lieu of reporting in separately filed Forms 10-Q for the affected periods. 

Production and sales of natural gas and oil from the Partnership's wells increased steadily during the second half of 2004 as wells were drilled and placed into production.  The last four of the thirty-seven wells commenced production in the first quarter of 2005.  The table below reflects the Partnership's sales of production from the wells and the average prices 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

The following table sets forth the quarterly operating results for the period from April 30, 2004 (date of inception) to December 31, 2004 and 2005 to facilitate an analysis of trends over the quarters in both years.  Additional quarterly information for 2004 and 2005 is presented in "Note 9 - Quarterly Financial Data (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

 

 

 

Results of Operations, Liquidity and Capital Resources - 2005 Quarters versus 2004 Quarters

As reflected in the tables above, oil and gas sales for the first, second and third quarters in 2005 reflect increases over the same quarter in the prior year.  This increase was due primarily to the increase in production of oil and gas from having all thirty-seven wells in production during 2005, whereas, in 2004, the drilling of the Partnership's wells was in progress during the months of May through December and all wells were not in production.  A portion of the sales increases related to the increase in average natural gas and oil prices that occurred throughout 2005. Similarly, operating costs and depreciation, depletion and amortization (DD&A) increased in conjunction with the production and sales increases for the quarters.

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

The average of production and operating costs in relation to natural gas equivalent units (Mcfe) production was $1.04 per Mcfe in 2005 as compared to $0.73 in 2004, with ranges across the quarters from $0.71 in the third quarter of 2004 to a high of $1.47 in the fourth quarter of 2005.  This increase in average costs was primarily due to increased severance and property taxes on the significantly increased oil and gas sales prices along with additional well workovers and production enhancement work performed. 

The discussion above under Item 7 captioned "Liquidity and Capital Resources" as of December 31, 2005, generally applies to all quarters in 2004 and 2005.  Only the exceptions, if any, to the above discussion will be included in the quarterly analysis below to avoid unnecessary repetition.

Three Month Periods Ended March 31 and June 30 - 2005 Compared to the Same Periods in 2004

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

Expenses in the second quarter of 2004 reflects a one-time management fee equal to 1½% of investors' subscriptions, or $435,463, which was paid to the Managing General Partner upon funding of the Partnership in April 2004 in accordance with provisions of the Partnership Agreement.

Three Months Ended September 30 - 2005 Compared to the Same Period in 2004

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

-17-



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

Transactions in derivative instruments resulted in a net loss for the third quarter of 2005 of $1,295,271, as compared to a net loss of $172,186 in the same quarter in 2004.  This change is generally due to the volume of derivative contracts as well as rising prices compared to the contract price of the derivative instrument.

Critical Accounting Policies and Estimates

We have identified the following policies as critical to the understanding of the results of operations. This is not a comprehensive list of all of our accounting policies. In many cases, the accounting treatment of a particular transaction is specifically dictated by accounting principles generally accepted in the United States with no need for management's judgment in their application. There are also areas in which management's judgment in selecting any available alternative would not produce a materially different result. However, certain accounting policies are important to the portrayal of the Partnership's financial condition and results of operations and require management's most subjective or complex judgments. In applying those policies, management uses its judgment to determine the appropriate assumptions to be used in the determination of certain estimates. Those estimates are based on our historical experience, our observance of trends in the industry, and information available from other outside sources as appropriate. For a more detailed discussion on the application of these and other accounting policies, see "Note 2 - Summary of Significant Accounting Policies" and other related notes in the Financial Statements. The Partnership's critical accounting policies and estimates are as follows:

Oil and Gas Properties

 

The Partnership accounts for its oil and gas properties under the successful efforts method of accounting.  Costs of proved developed producing properties, successful exploratory wells and development dry hole costs are depreciated or depleted by the unit-of-production method based on estimated proved developed producing oil and gas reserves.  Property acquisition costs are depreciated or depleted on the unit-of-production method based on estimated proved oil and gas reserves.  The Partnership obtains new reserve reports from independent petroleum engineers annually as of December 31st of each year.  The Partnership adjusts for any new drilling and divestitures during the year as needed.  The Partnership does not maintain an inventory of undrilled leases.

Upon sale or retirement of significant portions of, or complete fields of, depreciable or depletable property, the book value thereof less proceeds or salvage value, is credited or charged to income.  Upon sale of individual wells, the proceeds are credited to property costs.

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

-18-



Revenue Recognition

 

Sales of natural gas are recognized when natural gas has been delivered to a custody transfer point, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser, collection of revenue from the sale is reasonably assured, and the sales price is fixed or determinable.  Natural gas is sold by the Managing General Partner under contracts with terms ranging from one month up to the life of the well.  Virtually all of the Managing General Partner's contracts' pricing provisions are tied to a market index with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality of natural gas and prevailing supply and demand conditions, so that the price of the natural gas fluctuates to remain competitive with other available natural gas supplies.  As a result, the Partnership's revenues from the sale of natural gas will suffer if market prices decline and benefit if they increase.  However, the Managing General Partner may from time to time enter into derivative agreements, usually with a term of two years or less which may either fix or collar a price in order to reduce the impact of market price fluctuations. The Partnership believes that the pricing provisions of its natural gas contracts are customary in the industry.

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

Sales of oil are recognized when persuasive evidence of a sales arrangement exists, the oil is verified as produced and is delivered from storage tanks at well locations to a purchaser, collection of revenue from the sale is reasonably assured, and the sales price is determinable.  The Partnership does not refine any of its oil production.  The Partnership's crude oil production is sold to purchasers at or near the Partnership's wells under short-term purchase contracts at prices and in accordance with arrangements that are customary in the oil industry.

 

Derivative Financial Instruments

 

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

The measurement of fair value is based on actively quoted market prices, if available. Otherwise, the Managing General Partner seeks indicative price information from external sources including broker quotes and industry publications. If pricing information from external sources is not available, measurement involves judgment and estimates. These estimates are based on valuation methodologies considered appropriate by the Managing General Partner.

By using derivative financial instruments to manage exposures to changes in commodity prices, the Partnership exposes itself to credit risk.  Credit risk is the failure of the counterparty to perform under the terms of the derivative contract.  When the fair value of a derivative contract is positive, the counterparty owes the Managing General Partner, which in turn owes the Partnership thus creating repayment risk.  The Managing General Partner minimizes the credit or repayment risk in derivative instruments by entering into transactions with high-quality counterparties.

-19-



Recently Issued Accounting Standards

In June 2005, the FASB issued SFAS No. 154, "Accounting Changes and Error Corrections, a replacement of APB Opinion No. 20 and FASB Statement No. 3," which replaces Accounting Principles Board Opinion No. 20, "Accounting Changes" and SFAS No. 3, "Reporting Accounting Changes in Interim Financial Statements," and changes the requirements for the accounting for and reporting of a change in accounting principle.  SFAS No. 154 requires retrospective application for voluntary changes in accounting principle unless it is impracticable to do so, and it applies to all voluntary changes in accounting principle.  SFAS No. 154 is effective for accounting changes and corrections of errors made in fiscal years 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 a material impact on our financial statements.

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

Item 7A.  Quantitative and Qualitative Disclosure About Market Risk

Market-Sensitive Instruments and Risk Management

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

Commodity Price Risk

The Managing General Partner utilizes commodity-based derivative instruments, entered into on behalf of the Partnership, to manage a portion of the Partnership's exposure to price risk from oil and natural gas sales.  These instruments consist of CIG (Colorado Interstate Gas) index-based contracts traded by JP Morgan for Colorado natural gas production. These derivative instruments have the effect of locking in for specified periods (at predetermined prices or ranges of prices) the prices the Managing General Partner will receive for the volume of oil and natural gas to which the derivative relates.  As a result, while these derivative instruments are structured to reduce Partnership's exposure to changes in price associated with the derivative commodity, they also limit the benefit the Partnership might otherwise have received from price changes associated with the commodity.  The Partnership has adopted the policy of the Managing General Partner prohibiting the use of oil and natural gas future and option contracts for speculative purposes.  Derivative arrangements are entered into by the Managing General Partner on behalf of the Partnership and are reported on the Partnership's balance sheet at fair value as a net short-term or long-term receivable due from or payable to the Managing General Partner.  Changes in the fair value of the Partnership's share of derivatives are recorded in the statement of operations. The following table summarizes the Partnership's share of open derivative positions as of December 31, 2005 and 2004.

-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.

 

 

At December 31, 2005, the maximum term for the derivative positions listed above is 15 months.

The annual average Colorado Interstate Gas closing price for natural gas for 2005 was $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 by various supply and demand factors such as weather, government and environmental regulations and new drilling activities within the industry.

Disclosure of Limitations

As the information above incorporates only those exposures that exist at December 31, 2005, it does not consider those exposures or positions which could arise after that date. As a result, the Partnership's ultimate realized gain or loss with respect to commodity price fluctuations will depend on the exposures that arise during the period, and the Partnership's hedging strategies and commodity prices at the time.

ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

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

-21-



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

None.

ITEM 9A.  CONTROLS AND PROCEDURES

Introductory Explanation - As disclosed in more detail in "Item 1 - Business" above, the Partnership has no management or officers because all of the management, officers and other employees that may provide services to or on behalf of the Partnership are employed by the Managing General Partner.  As used for the disclosures in this Item 9A, management and officers of the Partnership refers to the management and officers of the Managing General Partner. 

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

Material weaknesses in internal control - During 2005, the Partnership identified material weaknesses related to its policies and procedures and technical expertise in U.S. generally accepted accounting principles to ensure the preparation of accurate and reliable interim and annual financial statements. Specifically, the Partnership lacked personnel with sufficient technical accounting and financial reporting expertise and policies and procedures in place to determine and document the appropriate application of accounting principles. These deficiencies impacted the Partnership's accounting for derivatives, asset retirement obligations and depreciation, depletion and amortization, and result in more than a remote likelihood that a material misstatement of the annual or interim financial statements would not be prevented or detected. 

In light of the material weaknesses described above, the Partnership performed additional analyses and other post-closing procedures to ensure its financial statements are prepared in accordance with generally accepted accounting principles. Accordingly, notwithstanding the material weaknesses discussed in this Item 9A, management believes that the financial statements included in this 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 following changes were made in the Partnership's internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) of the Securities Exchange Act of 1934) that have materially affected or are reasonably likely to materially affect internal control over financial reporting.

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

•       The Partnership has enhanced the documentation of its policies and procedures and related templates and analyses that support the 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 2005 and subsequently in 2006, the Partnership made the following changes and remediation:

-22-



At the direction of the board of directors and audit committee, the Partnership has spent and continues to spend a significant amount of time and resources to improve its control environment.  The Partnership is committed to instilling strong internal control policies and procedures and ensuring that the "tone at the top" fully supports accuracy and completeness in all financial reporting.  In support of this position, the Partnership's progress toward improving internal control over financial reporting has been openly communicated with the Audit Committee, and the Partnership has undertaken to improve the design and effectiveness of its internal control over financial reporting. The initiatives developed were both organizational and process focused.  Organizational changes made during 2005 and through the date of this filing include, among others:

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

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

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

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

•       The Partnership has evaluated and 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 date and planned for the future will address the reported material weaknesses and intends to complete the remediation efforts by early 2007.  In addition, the Partnership will continue to develop and implement other initiatives that will further improve both the effectiveness and efficiency of its internal control over financial reporting.

Beginning with the fiscal year ending December 31, 2007, Section 404 of the Sarbanes-Oxley Act of 2002 will require us to include an internal control report of management with our Annual Report on Form 10-K. The internal control report must contain (1) a statement of management's responsibility for establishing and maintaining adequate internal control over financial reporting, (2) a statement identifying the framework used by management to conduct the required evaluation of the effectiveness of our internal control over financial reporting, (3) management's assessment of the effectiveness of our internal control over financial reporting as of the end of our most recent fiscal year, including a statement as to whether or not our internal control over financial reporting is effective, and (4) a statement that our independent registered public accountants have issued an attestation report on management's assessment of our internal control over financial reporting.

In order to achieve compliance with Section 404 within the prescribed period, management has begun to assess the adequacy of our internal control over financial reporting, remediate any control weaknesses that may be identified, and implement a continuous reporting and improvement process for internal control over financial reporting. We expect to continue to make changes in our internal control over financial reporting during the periods prior to December 31, 2007, in connection with our Section 404 compliance efforts.

-23-



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

ITEM 9B.  OTHER INFORMATION

None.

 

PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

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

Although the Partnership has no Code of Ethics, PDC has a Code of Ethics that applies to its senior executive officers.  The Code of Ethics is posted on PDC's website at www.petd.com.

ITEM 11.  EXECUTIVE COMPENSATION

The Partnership, having no executive officers or directors, pays no executive compensation.  None of PDC's officers or directors received any direct remuneration or other compensation from the Partnership. These persons receive remuneration and compensation solely from PDC.

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

The Partnership has no equity compensation plans.

PDC owns a 20% partnership interest in the Partnership.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

PDC, as the Managing General Partner, and its wholly-owned subsidiaries, Riley Natural Gas and PDC Securities Incorporated, are reimbursed for certain Partnership operating expenses and receive fees for services as provided for in the partnership agreement.  As of December 31, 2005 and 2004, the Partnership owed the Managing General Partner $551,615 and $86,998, respectively.  As a result of derivative transactions executed by the Managing General Partner on behalf of the Partnership, there were also short term related party derivative payables of $344,301 and $121,011 at December 31, 2005 and 2004, respectively and long-term related party derivative payables of $65,545 for 2005 and $0 for 2004.  The following table presents reimbursements and service fees paid by the Partnership to PDC, or its affiliates, the year ended December 31, 2005 and 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

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

-24-



ITEM 14.  PRINCIPAL ACCOUNTANT FEES AND SERVICES

For the years ended December 31, 2005 and 2004, there were billings of $ 5,857 and $5,525 from the Partnership's independent auditors, KPMG LLP., for professional services for the audit of the Partnership's financial statements in its Form 10-K and review of quarterly information normally contained in Form 10-Qs. 

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

Pre-Approval Policies and Procedures

The Sarbanes-Oxley Act of 2002 requires that all services provided to the Partnership by its independent registered public accountants be subject to pre-approval by the Audit Committee or authorized members of the Committee.  The Partnership does not have an Audit Committee, however, the Managing General Partner's Audit Committee also serves for the Partnership.  The Audit Committee has adopted policies and procedures for pre-approval of all audit services and non-audit services to be provided by the Partnership's independent registered public accountants.  Services provided by the Partnership's independent registered public accountants with respect to the restatement of the Partnership's financial statements were pre-approved by the Managing General Partner's Audit Committee.  Actual fees incurred for all services performed by the independent accountant are reported to the Audit Committee after the services are fully performed.

-25-



PART IV

 

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

 

(1)   Financial Statements

See Index to Financial Statements on F-2

(2)   Financial Statement Schedules

All financial statement schedules are omitted because they are not required, inapplicable, or the information is included in the Financial Statements or Notes thereto.

(3)   Exhibits

4.1                   Form of Limited Partnership Agreement (incorporated by reference to Appendix A to Post-Effective Amendment No. 2 to Form S-1, SEC File No. 333-111260, and Rule 424 final prospectus, dated May 25, 2004, of PDC 2004-2006 Drilling Program, filed with the SEC on May 21, 2004).

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

31.1                 Rule 13a-14(a)/15d-14(c) Certification of Chief Executive Officer of Petroleum Development Corporation, the Managing General Partner of the Limited Partnership.

31.2                 Rule 13a-14(a)/15d-14(c) Certification of Chief Financial Officer of Petroleum Development Corporation, the Managing General Partner of the Limited Partnership.

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

-26-



SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has 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 requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the 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) through December 31, 2004 (restated)

(With Independent Registered Public Accounting Firm's Report 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 Accounting Firm

To the Partners

PDC 2004-A Limited Partnership:

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

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

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of PDC 2004-A Limited Partnership as of December 31, 2005 and 2004, and the results of its operations and its cash flows for the year ended December 31, 2005 and the period from April 30, 2004 (date of inception) to December 31, 2004, in conformity with U.S. generally accepted accounting principles.

As discussed in Note 10, the Company has restated the accompanying 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 Limited Partnership (the "Partnership") was organized as a limited partnership in accordance with the laws of the State of West Virginia for the purpose of engaging in the drilling, completion and operation of oil and gas development and exploratory wells in the Rocky Mountain Region.  Business operations of the Partnership commenced on April 30, 2004, upon the closing of an offering for the sale of partnership units.

Purchasers of partnership units subscribed to and fully paid for 33.34 units of limited partner interest and 1,418.20 units of additional general partner interests at $20,000 per unit (Investor Partners). Petroleum Development Corporation has been designated the Managing General Partner of the Partnership and has a 20% ownership in the Partnership.  Generally, throughout the term of the Partnership, revenues, costs and cash available for distributions are allocated 80% to the limited and additional general partners pro rata based on their investment in the Partnership and 20% to the Managing General Partner.  The limited and additional general partners are referred to collectively as "Investor Partners."

Upon completion of the drilling phase of the Partnership's wells, all additional general partners units were converted into units of limited partner interests and thereafter become limited partners of the Partnership.

In accordance with the terms of the Limited Partnership Agreement (the Agreement), the Managing General Partner manages all activities of the Partnership and acts as the intermediary for substantially all Partnership transactions.

(2)   Summary of Significant Accounting Policies

Restatement of Historical Financial Statements

See "Note 10 - Restatement of Historical Financial Statements" for a description of our restatement of historical financial statements related to errors in accounting.

Partnership Financial Statement Presentation Basis

The financial statements include only those assets, liabilities and results of operations of the partners which relate to the business of the Partnership.  The statements do not include any assets, liabilities, revenues or expenses attributable to any of the partners' other activities.

Reclassifications

Certain prior year amounts have been reclassified to conform with current year classifications.

Oil and Gas Properties

 

The Partnership accounts for its oil and gas properties under the successful efforts method of accounting. Costs of proved developed producing properties and development dry hole costs are depreciated or depleted by the unit-of-production method based on estimated proved developed producing oil and gas reserves.  Property acquisition costs are depreciated or depleted on the unit-of-production method based on estimated proved oil and gas reserves.  The Partnership obtains new reserve reports from independent petroleum engineers annually as of December 31st of each year.  The Partnership adjusts for any new drilling and divestitures during the year as needed.  The Partnership does not maintain an inventory of undrilled leases.

Upon sale or retirement of significant portions of or complete fields of depreciable or depletable property, the book value thereof less proceeds or salvage value, is credited or charged to income.  Upon sale of individual wells, the proceeds are credited to property 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 when circumstances indicate those assets may be impaired.  The Partnership assesses impairment of capitalized costs of proved oil and gas properties by comparing net capitalized costs to estimated undiscounted future net cash flows on a field-by-field basis using estimated production, based upon prices at which management reasonably estimates such products will be sold. These estimates of future product prices may differ from current market prices of oil and gas. Any downward revisions to the Partnership's estimates of future production or product prices could result in an impairment of the Partnership's oil and gas properties in the subsequent periods. If net capitalized costs exceed undiscounted future net cash flows, an impairment is recorded.  The measurement of impairment is based on estimated fair value calculated using future discounted cash flows.

Revenue Recognition

Sales of natural gas are recognized when natural gas has been delivered to a custody transfer point, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser upon delivery, collection of revenue from the sale is reasonably assured, and the sales price is fixed or determinable.  Natural gas is sold by the Managing General Partner under contracts with terms ranging from one month up to the life of the well.  Virtually all of the Managing General Partner's contracts pricing provisions are tied to a market index with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality of natural gas and prevailing supply and demand conditions, so that the price of the natural gas fluctuates to remain competitive with other available natural gas supplies.  As a result, the Partnership's revenues from the sale of natural gas will suffer if market prices decline and benefit if they increase.  However, the Managing General Partner may from time to time enter into derivative agreements, usually with a term of two years or less which may either fix or collar a price in order to reduce market price fluctuations. The Partnership believes that the pricing provisions of its natural gas contracts are customary in the industry.

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

Sales of oil are recognized when persuasive evidence of a sales arrangement exists, the oil is verified as produced and is delivered  from storage tanks at well locations to a purchaser, collection of revenue from the sale is reasonably assured and the sales price is determinable.  The Partnership is currently able to sell all the oil that it can produce under existing sales contracts with petroleum refiners and marketers.  The Partnership does not refine any of its oil production.  The Partnership's crude oil production is sold to purchasers at or near the Partnership's wells under short-term purchase contracts at prices and in accordance with arrangements that are customary in the oil industry.

The Partnership sold oil and natural gas to three customers which accounted for 58%, 28% and 14%, of the Partnership's total oil and natural gas sales for the year ended December 31, 2005, and 57%, 25% and 18% for the period from inception to December 31, 2004.

Asset Retirement Obligations

The Partnership accounts for asset retirement obligations by recording the fair value of its plugging and abandonment obligations when incurred, which is at the time the well is completely drilled. Upon initial recognition of an asset retirement obligation, the Partnership increases the carrying amount of the long-lived asset by the same amount as the liability. Over time, the asset retirement obligations are accreted for the change in their present value. The initial capitalized costs are depleted over the useful lives of the related assets, through charges to depreciation, depletion and amortization.

 

 

 

 

 

F-9



PDC 2004-A LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Notes to Financial Statements, Continued

 

Derivative Financial Instruments

 

The Partnership accounts for derivative financial instruments in accordance with FAS Statement No. 133 "Accounting for Derivative Instruments and Certain Hedging Activities" as amended.  During 2005 and 2004, none of the derivative contracts qualified for hedge accounting under the terms of FAS No. 133.  Accordingly, the derivative instruments are recorded as an asset or liability on the balance sheet at fair value and the change in the fair value is recorded in oil and gas price risk management gain (loss), net.  Because derivative arrangements are entered into by the Managing General Partner on behalf of the Partnership, they are reported on the balance sheet as a net short-term or long-term receivable due from or payable due to the Managing General Partner.  Amounts due to the Managing General Partner for realized 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 "Due to Managing General Partner - other".

The measurement of fair value is based on actively quoted market prices, if available. Otherwise, the Managing General Partner seeks indicative price information from external sources including broker quotes and industry publications. If pricing information from external sources is not available, measurement involves judgment and estimates. These estimates are based on valuation methodologies considered appropriate by the Managing General Partner.

By using derivative financial instruments to manage exposures to changes in commodity prices, the Partnership exposes itself to credit risk.  Credit risk is the failure of the counterparty to perform under the terms of the derivative contract.  When the fair value of a derivative contract is positive, the counterparty owes the Managing General Partner, which in turn owes the Partnership thus creating repayment risk.  The Managing General Partner minimizes the credit or repayment risk in derivative instruments by entering into transactions with high-quality counterparties.

Income Taxes

 

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

Use of Estimates

The Partnership has made a number of estimates and assumptions relating to the reporting of assets and liabilities, revenues and expenses, and the disclosure of contingent assets and liabilities to prepare these financial statements in conformity 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 estimates of oil and gas reserves and future cash flows from oil and gas properties which are used in assessing impairment of long-lived assets.

Recently Issued Accounting Standards

In June 2005, the FASB issued SFAS No. 154, "Accounting Changes and Error Corrections, a replacement of APB Opinion No. 20 and FASB Statement No. 3," which replaces Accounting Principles Board Opinion No. 20, "Accounting Changes" and SFAS No. 3, "Reporting Accounting Changes in Interim Financial Statements," and changes the requirements for the accounting for and reporting of a change in accounting principle. SFAS No. 154 requires retrospective application for voluntary changes in accounting principle unless it is impracticable to do so, and it applies to all voluntary changes in accounting principle.  SFAS No. 154 is effective for accounting changes and corrections of errors made in fiscal years 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 a material impact on our financial statements.

In September 2006, the FASB issued SFAS No. 157, "Fair Value Measurements," which replaces several existing pronouncements, defines fair value, establishes a framework for measuring fair value, and expands disclosures about fair value measurements.  SFAS No. 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years.  Consequently, we will adopt the provisions of SFAS 157 for our fiscal year beginning January 1, 2008.  The Partnership is currently evaluating the impact 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 Managing General Partner and Affiliates

PDC, as the Managing General Partner, and its wholly-owned subsidiaries, Riley Natural Gas and PDC Securities Incorporated, are reimbursed for certain Partnership operating expenses and receive fees for services as provided for in the partnership agreement.  As of December 31, 2005 and 2004, the Partnership owed the Managing General Partner $551,615 and $86,998, respectively.  As a result of derivative transactions executed by the Managing General Partner on behalf of the Partnership, there were also short term related party derivative payables of $344,301 and $121,011 at December 31, 2005 and 2004, respectively and long-term related party derivative payables of $65,545 for 2005 and $0 for 2004.  The following table presents reimbursements and service fees paid by the Partnership to PDC, or its affiliates, for the year ended December 31, 2005 and 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

In addition, as the operator of the Partnership's wells, the Managing General Partner receives all  proceeds from the sale of oil and gas produced and pays for all costs incurred related to services, equipment and supplies from vendors for all well production and operating costs and other direct costs for the Partnership.  Net revenue from oil and gas operations is distributed monthly to all partners based on their share of costs and revenues. 

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

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

At December 31, 2005, the maximum term for the derivative positions listed above is 15 months.

(4)   Allocation of Partners' Interests

The table below summarizes the participation of the Managing General Partner and the Investor Partners in the costs and revenues of the Partnership.  At December 31, 2005, the Managing General 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 all legal, accounting, printing, and filing fees associated with the organization of the Partnership and the offering of units and is allocated 100% of these costs.  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 the Managing General Partner upon the funding of the Partnership equal to 1-1/2% of total Investor Partner subscriptions.

F-12



PDC 2004-A LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Notes to Financial Statements, Continued

(c)   Represents operating costs incurred after the completion of productive wells, including monthly per-well charges paid to the Managing General Partner for well tending fees and Partnership administration fees.

(d)   The Managing General Partner is reimbursed by the Partnership for direct costs incurred by the Managing General Partner on behalf of the Partnership, such as for independent auditor, reserve engineer and tax preparation fees.

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

Performance Standard Obligation of Managing General Partner

 

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

Unit Repurchase Provisions

 

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

(5)   Costs Relating to Oil and Gas Activities

The Partnership is engaged solely in oil and gas activities, all of which are located in the continental United States.  Information regarding aggregate costs and results of operations for these activities is located in the basic financial 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)   Asset Retirement Obligations

Changes in carrying amounts of the asset retirement obligations associated with our oil and gas properties at December 31, 2005 and 2004 are as follows:

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 in calculating the asset retirement obligation and related accretion was 5.75%. This rate approximates the borrowing rate of the Managing General Partner.   

(7)   Supplemental Reserve Information (Unaudited)

Proved oil and gas reserves of the Partnership have been estimated at December 31, 2005 and 2004 by independent petroleum engineers. These reserves have been prepared in compliance with the Securities and Exchange Commission rules based on year end prices.  All of the partnership's reserves are proved developed reserves.  An analysis of the change in estimated quantities of proved developed 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 Future Net Cash Flows and Changes Therein Relating to Proved Oil and Gas Reserves (Unaudited)

Summarized in the following table is information for the Partnership with respect to the standardized measure of discounted future net cash flows relating to proved oil and gas reserves.  Future cash inflows are computed by applying year-end prices of oil and gas relating to the Partnership proved reserves to the year-end quantities of those reserves.  Future production, development, site restoration and abandonment costs are derived based on current 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 in the standardized measure of discounted future estimated net cash flow for the year ended December 31, 2005, and the period from April 30, 2004 (date of inception) 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

The data presented should not be viewed as representing the expected cash flow from, or current value of, existing proved reserves since the computations are based on a large number of estimates and arbitrary assumptions.  Reserve quantities cannot be measured with precision and their estimation requires many judgmental determinations and frequent revisions.  The required projection of production and related expenditures over time requires further estimates with respect to pipeline availability, rates of demand and governmental control. Actual future prices and costs are likely to be substantially different from the current prices and costs utilized in the computation of reported amounts.  Any analysis or evaluation of the reported amounts should give specific recognition to the computational methods utilized and the limitations inherent therein.

F-15



PDC 2004-A LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Notes to Financial Statements, Continued

(9)   Quarterly Financial Data (Unaudited)

 

Quarterly financial 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 the period from April 30, 2004 (date of inception) to June 30, 2004 and for the three months ended September 30 and December 31, 2004 were not previously reported.  Thus, results for these periods included in this Form 10-K are not presented as 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 balances at these dates included in this Form 10-K are not presented as restated amounts.

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

 

Quarterly results 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 September 30, 2004 were not previously reported.  Thus, results for these periods included in this 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

Quarterly cash 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 September 30, 2004 were not previously reported.  Thus, cash flows for these periods included 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

During 2005, errors were identified with respect to the Partnership's use of hedge accounting for certain transactions under Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities," as amended (FAS 133).  Accordingly, the Partnership revised its accounting for its derivative transactions after determining that the Partnership's derivative transactions did not qualify for hedge accounting. These errors began upon inception in 2004 and continued through the first quarter of 2005. The Partnership did not have sufficient documentation required for these derivatives to qualify for hedge accounting treatment and did not test them periodically for effectiveness as required by FAS 133.

The Partnership also determined its interpretation of the accounting related to asset retirement obligations was not consistent with the applicable rules in Statement of Financial Accounting Standards No. 143, "Accounting for Asset Retirement Obligations" ("FAS 143").  FAS 143 requires that the fair value of the Partnership's plugging and abandonment obligations be recorded at the time the obligations are incurred, which is at the time the well is completely drilled.  Upon initial recognition of an asset retirement obligation, the Partnership should increase the carrying amount of the long-lived asset by the same amount as the liability.  Over time, the liabilities are accreted for the change in their present value through charges to income.  The initial capitalized costs are depleted over the useful lives of the related assets through charges to depreciation, depletion and amortization.  In accounting for asset retirement obligations, the Partnership did not properly account for the establishment of the liabilities.  The impact of the corrections to apply the proper method of accruing for well plugging and abandonment costs are included in the restated financial statements.

Lastly, the Partnership corrected its accounting for oil and gas properties due to the following 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.

Effects of the Restatement

The restatement also impacted or made changes to the following financial statement footnotes: Note 2, 3, 5, 6, 8 and added Note 10, Restatement of Historical Financial Statements.

The following tables set forth the effects of the restatement relating to the derivatives transactions, oil and gas property depreciation and depletion, and asset retirement obligations on net income within the Partnership's previously reported operations for the quarter ended March 31, 2005 and the period from April 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)

Restated financial statements for the quarter ended March 31, 2005 and the period from April 30, 2004 (date of inception) through December 31, 2004, are presented below.  Amounts previously reported in the statement of operations under costs and expenses line items "independent engineering fee", "independent audit fee", "tax return preparation" and "direct administrative cost" are presented in the line item "direct costs" in the statement of operations in both the "Previously Reported" and "Restated" columns.  This reclassification, to conform to the current year presentation, did not affect net income or total costs and expenses.   Similarly, interest income and oil and gas price risk management gain or loss (previously classified within revenues) has been presented, in the "Restated" column, outside of income from operations, to conform 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

Statement of Cash Flows:

Only certain line items within cash flows from operating activities have been restated.  The net change in cash and cash equivalents for the period and the cash and cash equivalents balance at the end of the period are the same as in the original presentation of the financial statements.  No changes were made to the cash flows from investing and financing activities.  Accordingly, no reconciliation of the statement of cash flows is provided herein.

F-22