10-K 1 pdc2005b10k120521.htm

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  000-51452

PDC 2005-B LIMITED PARTNERSHIP

(Exact name of registrant as specified in its charter)

        West Virginia            

      20-2088726      

(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.



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 and Issuer Purchases of Equity Securities

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



PART I

 

ITEM 1.  BUSINESS

Overview

This Annual Report on Form 10-K for the year ended December 31, 2005 includes the financial statements of PDC 2005-B Limited Partnership ("the Partnership") for the year ended December 31, 2005 and substantially all of the information for the quarters ended June 30, 2005 and September 30, 2005 that would normally be contained in Quarterly Reports on Form 10-Q. 

As previously reported in an update included in Form 12b-25 (Notification of Late Filing) filed with the SEC on March 31, 2006, the Managing General Partner had suspended filing financial reports pending the complete assessment of its Partnership oil and gas property accounting and to correct potential errors related to depreciation, asset impairments, asset retirement obligations and hedge accounting. 

General

PDC 2005-B Limited 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 May 18, 2005, upon the closing of the offering for the sale of 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.  PDC 2005-B Limited Partnership was formed with total capital contributions of $40,452,761 from limited partners and additional general partners (collectively, the "Investor Partners") and $8,942,916 in capital contributed by Petroleum Development Corporation ("PDC"), the Managing General Partner. Total funding of the Partnership was $49,395,677.  The capital contributions from the Investor Partners consisted of 2,022.64 partnership units at a unit price of $20,000 each. After syndication costs of $4,074,306 and a one time management fee to the Managing General Partner of $606,791, the Partnership had available cash of $44,714,580 to commence Partnership activities for the drilling of natural gas and oil wells.

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%

 

 

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 the drilling of 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 2005 related to its 52 wells:

 

-1-



 

Wattenberg Field (DJ Basin)

Grand Valley Field (Piceance Basin)

 

Total

Drilled, completed and producing

42

   1

 43

Drilled but not completed

   -

  7

   7

Drilling in progress

   -

   2

   2

Dry holes

   -

   -

   -

Totals

42

10

52

As of December 31, 2005, completion of nine wells, all in the Grand Valley Field, were delayed until the spring of 2006 due to weather conditions restricting access to the well sites.  As of the date of this report, all 52 of the Partnership's wells have been completed.  The 52 wells in the table above are the only wells the Partnership will drill because all of the capital contributions provided by the partnership offering will have been utilized upon completion of these remaining wells.  

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.

 

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 during 2005, which accounted for 75%, 23% and 2% of the Partnership's total oil and natural gas sales for the period.

-2-



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 below.

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 estimates it has spent approximately $630,000 in 2005 to comply with federal and state regulations, primarily relating to environmental permitting and compliance.

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 one of the prior Partnerships sponsored by PDC has, 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 well, and the actual lives could differ from those anticipated.

-3-



The partnership units are not registered, there will be no public market for the units, 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.  The offer and sale of units have not been, and will not in the future, be registered under the Securities Act or under any state securities laws.  Each purchaser of units has been required to represent that such investor has purchased the units for his or her own account for investment and not with a view to resale or distribution.  No transfer of a unit may be made unless the transferee is a "qualified investor" and such transfer is registered under the Securities Act and applicable state securities laws, or an exemption therefrom is available.  The Partnership may require that the transferor provide an opinion of legal counsel stating that the transfer complies with all applicable securities laws.  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 intends to utilize substantially all available capital raised in the offering for the drilling and completion of wells and will have only nominal funds available for Partnership purposes prior to the time of production from Partnership well operations.  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.

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.

-4-



 

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's 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 create 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 which do not benefit 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 (when the Partnership is also needful of 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 the 74 limited partnerships PDC has organized in previous 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, and may also reduce the Partnership's cash flows and cash distributions to the Investor Partners.

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 engages 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. 

-5-



 

Additionally, the hedging transactions PDC has entered into, or will enter into, 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 for Partnership liabilities and obligations.  The additional general partners of the Partnership might be personally liable for payments of the 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 they 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.

Information concerning our 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 our 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 flow, 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 our estimated proved reserves could require us to write down the carrying value of our oil and gas properties, which would reduce our earnings and our partners' equity.

-6-



 

The present value of proved reserves will not necessarily equal the current fair market value of our 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

The Partnership's properties consist of oil and gas wells, associated well equipment, and the ownership in leasehold acreage assigned to the spacing units on which the 52 Partnership wells were drilled.  The Partnership has no undeveloped acreage.

Drilling Activity


The Partnership commenced drilling activities on May 31, 2005, following funding of the Partnership.  All of the Partnership's wells are located in the state of Colorado. The following table sets forth the results of the Partnership's drilling activity as of December 31, 2005. 

    Gross Wells  

 Net Wells

Development wells:

 

 

Drilled, completed and producing.......................................

43 

   42.85

Drilled and not completed.........................

    6.08

Drilling in progress................................................................

 2 

    1.50

Dry hole..................................................................................

    - 

         -

Total Wells Drilled................................................................

 52 

     50.43

As of the date of this report, all 52 wells drilled by the Partnership are considered to be productive wells. The Partnership did not participate in the drilling of any exploratory wells. Completion of the nine wells that were started but not completed in 2005 was delayed until the spring of 2006 due to weather conditions restricting access to the well site.  The 52 wells in the table above are the only wells to be drilled by the Partnership since all of the funds raised in the Partnership offering of $44,714,580 will have been utilized upon the completion of the nine remaining wells. 

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.

-7-



 

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.

Production

See "Item 7 - Management's Discussion and Analysis and Results of Operations" below for information related to volumes, prices and production costs.

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 satisfactory title to such properties.

ITEM 3.  LEGAL PROCEEDINGS

The Registrant 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 such 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 1,645 Investor Partners holding a total of 2,022.64 partnership 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 an interest in the Partnership can become a substituted partner without the written consent of the transferor and the Managing General Partner.

ITEM 6.  SELECTED FINANCIAL DATA

 

The selected financial data presented below has been derived from audited financial statements of the Partnership.  See the Financial Statements included with this Form 10-K.

-8-

 

 



 

Period From

May 18, 2005

(date of inception)

Through

December 31, 2005

Oil and gas sales

 $            4,442,990

Costs and expenses

               3,344,476

Oil and gas price risk management loss, net

                    31,322

Net income

               1,468,684

Allocation of Net income:

Managing General Partner

                  415,095

Investor Partners

               1,053,589

Per Investor Partner unit

                         521

Total assets at end of year

             46,864,262

Cash distributions:

Managing General Partner

                  156,085

Investor Partners

                  624,341

Per Investor Partner unit

                         309

 

 

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.

 

-9-



 

Overview

The Partnership was funded on May 18, 2005, with initial Investor Partner contributions of $40,452,761 and the Managing General Partner's cash contribution of $8,942,916.  After payment of syndication costs of $4,074,306 and a one-time management fee to the Managing General Partner of $606,791, the Partnership had available cash of $44,714,580 to commence the Partnership's drilling activities.

The drilling of oil and gas wells on prospects evaluated and designated by PDC commenced on May 31, 2005.  As of December 31, 2005, forty-three wells have been completed and are producing and nine additional wells were in various stages of completion.  The remaining work on these nine wells was delayed into 2006 primarily due to weather conditions restricting access to the well sites.  The Partnership drilled only development wells and did not participate in the drilling of exploratory wells.  Drilling of one of the two wells that was started but not finished in 2005 had drilling finished in January of 2006 and the other well is to be finished in 2006. No additional wells will be drilled by the Partnership.  The table in "Item 1 - Business" summarizes the Partnership's drilling activity during 2005.

Results of Operations

The following table presents significant operational information for the above referenced period in the Partnership's first year of operations:



2005

Oil and gas sales

 $      4,442,990

Gas sales - Mcf

            116,200

Average gas price/Mcf

 $               9.62

Oil sales - Bbls

60,050

Average oil price/Bbl

 $             55.38

Production and operating costs

 $         679,519

Production and operating costs/Mcfe

 $               1.43

Depreciation, depletion and amortization

 $      2,021,701

Net income

 $      1,468,684

Partnership cash distributions

 $         780,426

Oil and gas price risk management loss, net:

Realized loss

 $           31,322

Working capital at year end

 $      3,320,810

 

* 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.

Initial production from the Partnership wells commenced during the third quarter of 2005, as wells were drilled, completed and connected to pipelines. Sales of natural gas and oil from the Partnership's wells increased steadily during 2005 as additional wells were completed and placed into production.  The table below reflects the production volumes, net to the Partnership, for each of the quarters in 2005. 

-10-



 

No. of

Gas

Oil

Producing

Average

Average

Oil and Gas

Wells

Mcf

Price

Bbls

Price

Sales

Quarter 2

-

                    -  

 $            -  

                  -  

 $            -  

 $                      -

Quarter 3

21

            22,215

           8.03

          13,147

         59.08

             955,079

Quarter 4

43

            93,985

           9.99

          46,903

         54.34

          3,487,911

Total 2005

          116,200

 $        9.62

          60,050

 $      55.38

 $       4,442,990

 

The Partnership's future revenues from oil and natural gas sales will be affected by changes in prices.  As a result of changes in market conditions, gas prices are highly dependent on the balance between supply and demand. The Partnership's sales prices for natural gas and oil are subject to increases and decreases based on various market sensitive indices.

Interest income was earned by the Partnership during 2005 on bank balances that existed while awaiting capital expenditures on the drilling of the remaining oil and gas wells.

In accordance with the Partnership Agreement, a one-time management fee equal to 1½% of investors' subscriptions, or $606,791, was paid by the Partnership to the Managing General Partner upon funding of the Partnership.

The net loss of $31,322 from oil and gas price risk management is comprised of the change in fair value of oil and natural gas derivatives related to the Partnership's oil and gas production for derivative contracts entered into on behalf of the Partnership by the Managing General Partner.  The Partnership views these transactions as a gain or loss on financial instruments and not a part of oil and gas sales.

Liquidity and Capital Resources

The Partnership had a working capital balance at December 31, 2005, of $3,320,810, which was primarily the result of receivables from oil and gas sales during the fourth quarter and cash on hand. Future operations are expected to be conducted with available funds and revenues generated from oil and gas production activities.   Other than the planned future recompletions in the Codell formation, there is no provision in the Partnership Agreement for additional development or exploration beyond these 52 wells and there are no present additional capital needs of the Partnership. Current production revenues exceed operating costs by a wide margin. However, PDC plans to recomplete the Codell formation in most of the 42 wells in the Wattenberg Field after 5 years or more of production. 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 for the recompletion). The Partnership is not permitted to borrow under the Partnership Agreement; therefore, the cost of the recompletions will be paid out of overall revenues of the Partnership.  The Managing General Partner is allowed to and may withhold production revenues in advance of recompletion work.  This would reduce cash distributions to the partners at the time of the recompletions, but should result in additional cash distributions following the recompletions.

Oil and Gas Reserves

Proved oil and gas reserves of the Partnership have been estimated at December 31, 2005, to include 743,000 barrels of oil and 11,899,000 Mcfs of natural gas.  See "Note 7 - Supplemental Reserve Information (Unaudited)" in the Financial Statements for additional reserve information.

 

The following table sets forth the quarterly information for each of the quarters during the year ended December 31, 2005.  See also "Note 9 - Quarterly Financial Data (Unaudited)" in the Financial Statements.

 

-11-



May 18, 2005

(Inception)

For the Three Months Ended

to June 30,

September 30,

December 31,

2005

2005

2005

Oil and gas sales

 $                   -  

 $         955,079

 $     3,487,911

Gas sales - Mcf

                      -  

              22,215

             93,985

Average gas price/Mcf

 $                   -  

 $               8.03

 $              9.99

Oil sales - Bbls

                      -  

13,147

46,903

Average oil price/Bbl

 $                   -  

 $             59.08

 $            54.34

Production and operating costs

 $                   -  

 $         156,891

 $        522,628

Production and operating costs/Mcfe

 $                   -  

 $               4.44

 $              1.18

Depreciation, depletion and amortization

 $                   -  

 $         358,600

 $     1,663,101

Net (loss) income

 $        (516,094)

 $         593,952

 $     1,390,826

Partnership cash distributions

 $                   -  

 $                     -

 $        780,426

Oil and gas price risk management loss, net:

Realized loss/(gain)

 $                   -  

 $           17,759

 $          13,563

Unrealized loss/(gain)

 $                   -  

 $           19,935

 $         (19,935)

Working capital at end of period

 $    38,325,559

 $    17,119,549

 $     3,320,810

 

 

Management's Discussion and Analysis

Period from May 18 to June 30, 2005

The Partnership began operations in May 2005 and drilled 9 wells by June 30, 2005.  Interest income of $91,243 was earned in this quarter on Partnership funds in a bank awaiting expenditure for the drilling of additional wells.  Expenses in the quarter reflect a one time management fee equal to 1 ½ % of investors' subscriptions, or $607,299, which was paid to the Managing General Partner upon funding of the Partnership in May 2005 in accordance with provisions of the Partnership Agreement.

Three Months Ended September 30, 2005

Results of Operation - During the quarter, the Partnership had net income of $593,952 resulting from the commencement of production of oil and gas.  Production commenced as wells were drilled, completed and connected to a pipeline.  During the quarter 21 wells began production. Total production for the Partnership during the quarter was 22,215 Mcf of natural gas and 13,147 barrels of oil. The results included net losses related to oil and gas price risk management of $37,694 which included an unrealized loss of $19,935 and a realized loss of $17,759.  The Partnership's strategy in its derivative policy is to provide protection on declining oil and natural gas prices.  During this period of rising oil and natural gas prices, the Partnership recorded losses as market prices exceeded contract prices related to the Partnership's oil and gas sales.  The Partnership made no partner distributions during the quarter.

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:

-12-



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 major acquisitions, new drilling and divestures during the year as needed.  The Partnership does not maintain an inventory of undrilled leases.

Upon sale or retirement of significant or entire portions of fields of depreciable or depletable property, the book value thereof, less proceeds, is credited or charged to income.  Upon sale of a partial unit of property, the proceeds are credited to accumulated depreciation and depletion.

Use of Estimates in Testing for Impairment in Long-Lived Assets

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.

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 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 and 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 a stock tank 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.

 

-13-



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, 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 loss (gain), net.  Because derivative arrangements are entered into by the Managing General Partner on behalf of the Partnership, the fair value of open derivative positions is 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.

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.

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 Partnership held no derivative positions as of December 31, 2005.

 

-14-



 

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, the Partnership's hedging strategies at the time 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.

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 -

 

There have not been any changes 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) during the most recent fiscal quarter that have materially affected or are reasonably likely to materially affect internal control over financial reporting, except for changes in the fourth quarter of 2005 as noted below. 

•       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.

 

-15-



 

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

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 it plans to implement during 2006.

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 during 2006.  In addition, the Partnership will continue to develop and implement other initiatives during 2006 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.

 

-16-



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. Except as described above, there have been no changes in our internal control over financial reporting (as defined in Rule 13(a)-15(f) under the Exchange Act) that occurred during the quarters ended June 30, 2005, September 30, 2005 and December 31, 2005, that have materially affected or are reasonably likely to materially affect our internal control over financial reporting.

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, and other information related to PDC, 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, 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. The following table presents reimbursements and service fees paid by the Partnership to PDC or its affiliates during 2005.

 

-17-



May 18, 2005 (inception) through December 31, 2005:

Management fee

 $                606,791

Drilling services

              44,714,580

Syndication costs*

                   809,055

Well operations fees

                     49,402

 

*      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.

Additional information concerning commodity-based derivative instruments entered into by the Managing General Partner on behalf of the Partnership is contained in Item 7A.

 

ITEM 14.  PRINCIPAL ACCOUNTANT FEES AND SERVICES

For the period from inception to December 31, 2005, there have been billings of $6,958 from the Partnership's independent auditors for professional services rendered to the Partnership.

Pre-Approval Policies and Procedures

The Sarbanes-Oxley Act of 2002 requires that all services provided to the Partnership by its independent 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 accountants. Actual fees incurred for all services performed by the independent accountant are reported to the Audit Committee after the services are fully performed.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

-18-



PART IV

 

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(1)   Financial Statements

The Index to Financial Statements is located at 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

                                Exhibit

                                 No.                 Description  

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.

 

 

-19-



 

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 2005-B Limited Partnership

By its Managing General Partner

Petroleum Development Corporation

By /s/ Steven R. Williams

Steven R. Williams, CEO

September 7, 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                

September 7, 2006

    Steven R. Williams

Director of Petroleum Development Corporation,

 

 

Managing General Partner of the

 

 

Registrant

 

 

 

 

/s/ Darwin L. Stump

 Chief Financial Officer and Treasurer            

September 7, 2006

    Darwin L. Stump

 of Petroleum Development Corporation,

 

 

 the Managing General Partner of the

 

 

Registrant

 

 

(Principal Financial and Accounting Officer)

 

 

 

 

 

 

 

/s/ Thomas E. Riley

 President and Director                 

September 7, 2006

    Thomas E. Riley

 of Petroleum Development Corporation,

 

 

the Managing General Partner of the

 

 

Registrant

 

 

 

 

/s/ Donald B. Nestor 

 Director of Petroleum Development Corporation,

September 7, 2006

    Donald B. Nestor

 the Managing General Partner of the

 

 

Registrant 

 

 

 

 

/s/ Vincent F. D'Annunzio 

 Director of Petroleum Development Corporation,

September 7, 2006

    Vincent F. D'Annunzio

the Managing General Partner of the

 

 

Registrant 

 

 

 

-20-

 



PDC 2005-B LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Financial Statements for Annual Report

on Form 10-K to Securities and Exchange

Commission

May 18, 2005 (date of inception) Through December 31, 2005

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

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

F-1



Index to Financial Statements

 

 

Report of Independent Registered Public Accounting Firm

F-3

 

Balance Sheet - December 31, 2005

F-4

 

Statement of Operations - Period from May 18, 2005 (date of inception)

F-5

        to December 31, 2005

 

 

Statement of Partners' Equity - Period from May 18, 2005 (date of inception)

F-6

        to December 31, 2005

 

 

Statement of Cash Flows - Period from May 18, 2005 (date of inception)

F-7

        to December 31, 2005

 

 

Notes to Financial Statements

F-8

 

 



 

PDC 2005-B LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

 

Report of Independent Registered Public Accounting Firm

To the Partners

PDC 2005-B Limited Partnership:

We have audited the accompanying balance sheet of PDC 2005-B Limited Partnership as of December 31, 2005, and the related statements of operations, partners' equity and cash flows for the period from May 18, 2005 (date of inception) to December 31, 2005.  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 audit.

We conducted our audit 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 audit provides 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 2005-B Limited Partnership as of December 31, 2005, and the results of its operations and its cash flows for the period from May 18, 2005 (date of inception) to December 31, 2005, in conformity with U.S. generally accepted accounting principles.

KPMG LLP

Pittsburgh, Pennsylvania

July 20, 2006

 

 

 

 

 

F-3



 

PDC 2005-B LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

 

 

Balance Sheet

December 31, 2005

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Assets

 

 

 

 

 

 

 

 

 

 

 

 

 

Current assets:

 

 

 

 

 

 

Cash and cash equivalents

 

 

 

 

 $           401,621

Accounts receivable - oil and gas sales

 

 

 

           3,487,911

 

 

 

 

 

 

 

Total current assets

 

 

 

 

           3,889,532

 

 

 

 

 

 

 

Oil and gas properties, successful efforts method

 

 

 

         44,996,431

Less accumulated depreciation, depletion and amortization

 

         (2,021,701)

 

 

 

 

 

 

         42,974,730

 

 

 

 

 

 

 

Total Assets

 

 

 

 

 

 $      46,864,262

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Liabilities and Partners' Equity

 

 

 

 

 

 

 

 

 

 

 

 

Current liabilities:

 

 

 

 

 

 

Accounts payable and accrued expenses

 

 

 

 $           568,722

Total current liabilities

 

 

 

 

              568,722

 

 

 

 

 

 

 

Asset retirement obligations

 

 

 

 

              285,911

 

 

 

 

 

 

 

Partners' equity

 

 

 

 

 

         46,009,629

 

 

 

 

 

 

 

Total Liabilities and Partners' Equity

 

 

 

 

 $      46,864,262

 

 

 

 

 

 

 

 

 

 

 

 

 

 

See accompanying notes to financial statements.

 

 

 

 

 

 

 

 

F-4



 

PDC 2005-B LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

 

 

Statement of Operations

 

 

 

 

 

Period from May 18, 2005 (date of inception) to  December 31, 2005

 

 

 

 

 

 

 

 

 

 

Revenues:

 

 

 

 

Oil and gas sales

 

 

 

 $       4,442,990

 

 

 

 

 

Costs and expenses:

 

 

 

 

Production and operating costs

 

 

              679,519

Management fee

 

 

 

              606,791

Direct costs

 

 

 

                32,405

Depreciation, depletion and amortization

 

           2,021,701

Accretion of asset retirement obligations

 

                  4,060

Total costs and expenses

 

 

           3,344,476

 

 

 

 

 

Income from operations

 

 

           1,098,514

 

 

 

 

 

Interest income

 

 

 

              401,492

Oil and gas price risk management loss, net

 

              (31,322)

 

 

 

 

 

Net income

 

 

 

 $        1,468,684

 

 

 

 

 

Net income per Investor Partner unit

 

 

 $              521

 

 

 

 

 

 

 

 

 

 

See accompanying notes to financial statements.

 

 

 

 

 

 

 

F-5



PDC 2005-B LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

 

 

Statement of Partners' Equity

 

 

 

 

 

 

 

 

 

Period from May 18, 2005 (date of inception) to  December 31, 2005

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Managing

 

 

 

 

 

 

Investor

 

General

 

 

 

 

 

 

Partners

 

Partner

 

Total

 

 

 

 

 

 

 

 

 

Partners' initial capital contributions

 

 

 $      40,452,761

 

 $        8,942,916

 

 $      49,395,677

 

 

 

 

 

 

 

 

 

Syndication costs

 

 

 

         (4,074,306)

 

                          -

 

         (4,074,306)

 

 

 

 

 

 

 

 

 

Distributions to partners

 

 

            (624,341)

 

            (156,085)

 

            (780,426)

 

 

 

 

 

 

 

 

 

Net income

 

 

 

           1,053,589

 

              415,095

 

           1,468,684

 

 

 

 

 

 

 

 

 

Balance, December 31, 2005

 

 

 $      36,807,703

 

 $        9,201,926

 

 $      46,009,629

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

See accompanying notes to financial statements.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

F-6



 

PDC 2005-B LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

 

Statement of Cash Flows

 

 

 

 

 

Period from May 18, 2005 (date of inception) to  December 31, 2005

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2005

Cash flows from operating activities:

 

 

 

Net income

 

 

 

 $            1,468,684

Adjustments to reconcile net income to

 

 

      net cash provided by operating activities:

 

 

Depreciation, depletion and amortization

 

               2,021,701

Accretion of asset retirement obligation

 

                      4,060

Changes in operating assets and liabilities:

 

 

Increase in accounts receivable - oil and gas sales

 

              (3,487,911)

Increase in accounts payable and accrued expenses

 

                  568,722

Net cash provided by operating activities

 

                  575,256

 

 

 

 

 

Cash flows from investing activities:

 

 

 

Expenditures for oil and gas properties

 

            (44,714,580)

Net cash used in investing activities

 

            (44,714,580)

 

 

 

 

 

Cash flows from financing activities:

 

 

 

Investor Partner contributions

 

 

             40,452,761

Managing General Partner contribution

 

               8,942,916

Syndication costs paid

 

 

              (4,074,306)

Distributions to partners

 

 

                 (780,426)

Net cash provided by financing activities

 

             44,540,945

 

 

 

 

 

Net increase in cash and cash equivalents

 

                  401,621

Cash and cash equivalents at beginning of period

 

                              -

Cash and cash equivalents at end of period

 

 $               401,621

 

 

 

 

 

See accompanying notes to financial statements.

 

 

 

 

 

 

 

 

 

 

 

 

F-7



 PDC 2005-B LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Notes to Financial Statements

 

(1)   Organization

The PDC 2005-B 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 May 18, 2005, upon the closing of an offering for the sale of partnership units.

Purchasers of partnership units subscribed to and fully paid for 37.77 units of limited partner interests and 1,984.87 units of additional general partner interests at $20,000 per unit. Petroleum Development Corporation ("PDC") has been designated the Managing General Partner of 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."

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

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.

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 major acquisitions, new drilling and divestures during the year as needed.  The Partnership does not maintain an inventory of undrilled leases.

Upon sale or retirement of significant or entire portions of fields of depreciable or depletable property, the book value thereof less proceeds, is credited or charged to income.  Upon sale of a partial unit of property, the proceeds are credited to accumulated depreciation and depletion.

Impairment of Long-Lived Assets

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 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 which may consider future discounted cash flows.

 

F-8



 

PDC 2005-B LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Notes to Financial Statements

 

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 (see Note 3).  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 and 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 in a stock tank, 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 during 2005, which accounted for 75%, 23% and 2% of the Partnership's total oil and natural gas sales for the period.

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, 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.

 

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, 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 loss (gain), net.  Because derivative arrangements are entered into by the Managing General Partner on behalf of the Partnership, the fair value of open positions is 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 in accounts payable in the amount of $13,563 at December 31, 2005.

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.

 

F-9



 

PDC 2005-B LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Notes to Financial Statements

 

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 and 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.

Fair Value of Financial Instruments

The carrying values of the Company's receivables, payables and debt obligations are estimated to be substantially the same as the fair values as of December 31, 2005.

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.

(3)   Transactions with Managing General Partner and Affiliates

The Managing General Partner and its wholly-owned subsidiaries, Riley Natural Gas and PDC Securities Incorporated, are regularly reimbursed for operating expenses and receive fees for services as provided for in the Agreement. The table below presents to the transactions with the Managing General Partner for the period from May 18, 2005, through December 31, 2005.

 

 

 

 

Management fee

 

 $              606,791

Drilling services

 

 

            44,714,580

Syndication costs

 

                 809,055

Well operations fees

                   49,402

 

 

 

 

 

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 generally distributed monthly to all partners based on their share of costs and revenues.  However, the Partnership retains the underlying credit risk related to the sale of all oil and gas produced. 

F-10



 

PDC 2005-B LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Notes to Financial Statements

 

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.  The Partnership had no open derivative positions as of December 31, 2005. 

(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's 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.

(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.

 

 

F-11



 

PDC 2005-B LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Notes to Financial Statements

 

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 2008.

(5) Asset Retirement Obligations

Changes in carrying amounts of the asset retirement obligations associated with our oil and gas properties are as follows:

 

 

 

 

Period from

 

 

 

 

May 18, 2005

 

 

 

 

(date of inception)

 

 

 

 

through

 

 

 

 

December 31, 2005

 

 

 

 

 

Balance at beginning of period

 

 

 $                           -  

Obligations assumed with development activities

 

                    281,851

Accretion expense

 

 

 

                        4,060

Balance at end of year

 

 

 

 $                 285,911

 

 

 

 

 

 

The discount rate used in calculating the asset retirement obligations was 5%.  This rate approximates the borrowing rate of the Managing General Partner.

 (6)  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 capitalized costs and results of operations for these activities is located in the basic financial statements.  Costs capitalized for these activities are as follows:

 

 

Period from      May 18, 2005

 

 

(date of inception)

 

 

through

 

 

December 31, 2005

 

 

 

Lease acquisition cost

 

 $                635,880

Development costs

 

              30,590,842

Wells in progress

 

              13,769,709

 

 

 $           44,996,431

 

 

 

F-12



PDC 2005-B LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Notes to Financial Statements

 

 

 (7)  Supplemental Reserve Information (Unaudited)

Proved oil and gas reserves of the Partnership have been estimated at December 31, 2005, 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

 

Proved developed reserves:

 

 

 

Beginning of year

 

                            -  

 

Revisions of previous estimates

                            -  

 

New discoveries and extensions

                   803,000

 

Production

 

                   (60,000)

 

End of Year

 

                   743,000

 

 

 

 

 

 

 

 Gas (MCF)

 

 

 

2005

 

Proved developed reserves:

 

 

 

Beginning of year

 

                            -  

 

Revisions of previous estimates

                            -  

 

New discoveries and extensions

              12,015,000

 

Production

 

                 (116,000)

 

End of Year

 

              11,899,000

 

 

 

 

 

 

(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's 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.

As of

December 31, 2005

Future estimated revenues

 $          139,312,000

Future estimated production costs

             (31,322,000)

Future estimated development costs

               (5,132,000)

   Future net cash flows

             102,858,000

10% annual discount for estimated timing of cash flows

             (49,437,000)

Standardized measure of discounted future

   estimated net cash flows

 $            53,421,000

 

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

 

F-13



PDC 2005-B LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Notes to Financial Statements

 

 

 

 

 

 

As of

 

 

 

 

December 31, 2005

Sales of oil and gas production, net of production costs

 $            (3,763,000)

Discoveries, less related costs

               57,184,000

 

 

 

 

 $            53,421,000

 

 

 

 

 

 

It is necessary to emphasize that 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.

 (9) Quarterly Financial Data (Unaudited)

Quarterly financial data for the period from May 18, 2005 (date of inception) through December 31, 2005 is as follows:

 

 

 

Period May 18,

Three Months Ended

 

 

to June 30,

September 30,

December 31,

Year

 

2005

2005

2005

2005

Revenues:

 

 

 

 

 Oil and gas sales

 $                    -  

 $       955,079

 $     3,487,911

 $     4,442,990

 

 

 

 

 

Costs and Expenses:

 

 

 

 

Production and operating costs

                       -  

          156,891

           522,628

           679,519

Management fee

             607,299

                    -  

                (508)

           606,791

Direct costs

                      38

                    -  

             32,367

             32,405

Depreciation, depletion and amortization

                       -  

          358,600

        1,663,101

        2,021,701

Accretion of asset retirement obligation

                       -  

                 851

               3,209

               4,060

Total costs and expenses

             607,337

          516,342

        2,220,797

        3,344,476

 

 

 

 

 

(Loss) income from operations

            (607,337)

          438,737

        1,267,114

        1,098,514

 

 

 

 

 

Interest income

               91,243

          192,909

           117,340

           401,492

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

                       -  

          (37,694)

               6,372

            (31,322)

 

 

 

 

 

Net (loss) income

 $         (516,094)

 $       593,952

 $     1,390,826

 $     1,468,684

 

 

 

 

 

Net (loss) income per Investor Partner Unit

 $                (264)

 $              235

 $               550

 $               521

 

 

 

 

 

 

The following presents substantially all of the information for the quarters ended June 30, 2005 and September 30, 2005 that would normally be contained in quarterly reports on Form 10-Q but are instead reported as part of this 10-K.

 

F-14

 



PDC 2005-B LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Notes to Financial Statements

 

 

Balance Sheets

 

June 30,

Sept. 30,

 

 

2005

2005

 

 

 

 

Cash and cash equivalents

 

 $  42,969,290

 $   20,635,453

Accounts receivable - oil and gas sales

 

                    -  

           955,079

Due from escrow agent

 

            84,516

             15,971

Total current assets

 

     43,053,806

      21,606,503

 

 

 

 

Oil and gas properties, successful efforts method

 

       2,411,473

      21,917,731

Less accumulated depreciation, depletion and amortization

                    -  

         (358,600)

Wells in progress

 

       4,068,246

        6,795,545

 

 

 

 

 

 

       6,479,719

      28,354,676

 

 

 

 

Total Assets

 

 $  49,533,525

 $   49,961,179

 

 

 

 

 

 

 

 

Accounts payable and accrued expenses

 

 $                 -  

 $        174,650

Due to Managing General Partner - wells

 

       4,728,248

        4,292,370

Due to Managing General Partner - derivatives

 

                    -  

             19,935

Total current liabilities

 

       4,728,248

        4,486,955

 

 

 

 

Asset retirement obligations

 

                    -  

             74,995

 

 

 

 

Partners' equity

 

     44,805,277

      45,399,229

 

 

 

 

Total Liabilities and Partners' Equity

 

 $  49,533,525

 $   49,961,179

 

 

 

 

 

 

 

 

 



Statements of Partners' Equity

Managing

Investor

General

Partners

Partner

Total

Partners' initial capital contributions

 $     40,452,761

 $    8,942,916

 $   49,395,677

Syndication costs

         (4,074,306)

                      -

      (4,074,306)

Net income (loss) - quarter ended June 30, 2005

            (534,335)

            18,241

         (516,094)

Balance, June 30, 2005 (unaudited)

        35,844,120

       8,961,157

      44,805,277

Net income - quarter ended September 30, 2005

             475,162

          118,790

           593,952

Balance, September 30, 2005 (unaudited)

        36,319,282

       9,079,947

      45,399,229

Distributions to partners

            (624,341)

        (156,085)

         (780,426)

Net income - quarter ended December 31, 2005

          1,112,661

          278,165

        1,390,826

Balance, December 31, 2005

 $     36,807,602

 $    9,202,027

 $   46,009,629

 

 F-15

 



 

PDC 2005-B LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Notes to Financial Statements

 

Statements of Cash Flows

 

Period

Period

 

 

May 18 to

May 18 to

 

 

June 30,

September 30,

 

 

2005

2005

Cash flows from operating activities:

 

 

 

Net (loss) income

 

 $     (516,094)

 $             77,858

Adjustments to reconcile net (loss) income to

 

 

 

      net cash used in operating activities:

 

 

 

Depreciation, depletion and amortization

 

                    -  

              358,600

Accretion of asset retirement obligation

 

                    -  

                     851

Unrealized loss on derivative transactions

 

                    -  

                19,935

Changes in operating assets and liabilities:

 

 

 

Increase in accounts receivable - oil and gas sales

 

                    -  

            (955,079)

Increase in due from escrow agent

 

          (84,516)

              (15,971)

Increase in accounts payable and accrued expenses

 

                    -  

              174,650

Net cash used in operating activities

 

        (600,610)

            (339,156)

 

 

 

 

Cash flows from investing activities:

 

 

 

Expenditures for oil and gas properties

 

     (1,751,471)

       (24,346,762)

Net cash used in investing activities

 

     (1,751,471)

       (24,346,762)

 

 

 

 

Cash flows from financing activities:

 

 

 

Investor Partner contributions

 

     40,452,761

         40,452,761

Managing General Partner contribution

 

       8,942,916

           8,942,916

Syndication costs paid

 

     (4,074,306)

         (4,074,306)

Net cash provided by financing activities

 

     45,321,371

         45,321,371

 

 

 

 

Net increase in cash and cash equivalents

 

     42,969,290

         20,635,453

Cash and cash equivalents at beginning of period

 

                      -

                          -

Cash and cash equivalents at end of period

 

 $  42,969,290

 $      20,635,453

 

 

 

 

 

 

F-16