Item 1.
Business
General
The Partnership was organized as a limited partnership on June 3, 2002 under the West Virginia Uniform Limited Partnership Act. Petroleum Development Corporation, (dba PDC Energy), a Nevada Corporation, is the Managing General Partner of the Partnership. Upon completion of the public sale of the Partnership units on November 12, 2002 (date of inception), the Partnership was funded and commenced business operations. The Partnership was funded with initial contributions of $9.4 million from 478 limited and additional general partners (collectively, the “Investor Partners”) and a cash contribution of $2.1 million from the Managing General Partner for the General Partner interest. After payment of syndication costs of $1.0 million and a one-time management fee to the Managing General Partner of $0.2 million, the Partnership had available cash of $10.3 million to commence Partnership activities. Upon funding, the Partnership entered into a Drilling and Operating Agreement (“D&O Agreement”) with the Managing General Partner which governs the drilling and operational aspects of the Partnership. The Partnership owns an undivided working interest in natural gas and oil wells located in Colorado from which the Partnership produces and sells natural gas and oil.
The Partnership expects continuing operations of its natural gas and oil properties until such time the Partnership’s wells are depleted or becomes uneconomical to produce, at which time that well may be sold or plugged, reclaimed and abandoned. The Partnership’s maximum term of existence extends through December 31, 2050, unless dissolved by certain conditions stipulated within the Agreement which are unlikely to occur at this time, or by written consent of the Investor Partners owning a majority of outstanding units at that time.
The address and telephone number of the Partnership and PDC’s principal executive offices, are 1775 Sherman Street, Suite 3000, Denver, Colorado 80203 and (303) 860-5800.
PDC Sponsored Drilling Program Acquisition Plan
PDC, the managing general partner of various public limited partnerships, has disclosed its intention to pursue the acquisition, starting in the fall of 2010, of the remaining third-party Investor Partner interests in the limited partnerships which PDC has sponsored, including PDC 2002-C Limited Partnership. (For additional information regarding PDC’s intention to pursue acquisition of PDC sponsored partnerships, refer to Regulation FD disclosure included in Items 2.02 and/or 7.01 of PDC’s Form 8-Ks dated March 4, 2010, June 9, 2010 and July 15, 2010, which information shall not, by reason of this reference, be deemed to be incorporated by reference in, or otherwise be deemed to be part of this report.) Under the Acquisition Plan, any offer will be subject to the terms and conditions of a to be proposed merger agreement wherein the Partnership will merge into PDC. The transaction will also be subject to PDC having sufficient available capital and the approval by a majority of the Investor Partners’ interests, excluding partnership interest owned by PDC, of each respective limited partnership. Should a purchase offer from PDC be proposed, approved by a majority of the Partnerships’ unaffiliated limited partners, and consummated, the purchase transaction would result in a liquidating cash distribution to all partners and termination of the existence of the Partnership. There is no assurance that any such acquisition will occur.
Drilling Activities
The Partnership commenced drilling activities immediately following funding on November 12, 2002. Drilling operations were completed in August 2003 when the last of the Partnership’s 14 development wells were connected to sales and gathering pipelines. The Partnership’s 14 gross wells represent 12.7 net wells, or the number of gross wells multiplied by the working interest in the wells owned by the Partnership. All of the drilled wells are located in Colorado and all wells drilled were producing as of December 31 of 2005, 2006 and 2007. The Partnership’s wells are considered developmental wells. Therefore, no exploratory drilling activity was conducted on behalf of the Partnership.
The 14 wells discussed above are the only wells to be drilled by the Partnership since all of the funds raised in the Partnership offering have been expended. Accordingly, the Partnership’s business plan going forward, including the Wattenberg Field Codell formation recompletions, is to produce and sell the natural gas and oil from the Partnership’s wells, and to make distributions to the partners as outlined in the Partnership’s cash distribution policy, discussed in Item 5, Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities. Partnership cash distributions may be withheld pursuant to Wattenberg Field Codell formation recompletion activities.
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In accordance with the D&O Agreement, the Partnership paid its proportionate share of the cost of drilling and completing each well as follows:
a)
The cost of the prospect; and
b)
The intangible well costs for each well completed and placed in production, an amount equal to the depth of the well in feet at its deepest penetration as recorded by the drilling contractor multiplied by the “intangible drilling and completion cost” in the D&O Agreement, plus the actual extra completion cost of zones completed in excess of the cost of the first zone and actual additional costs incurred in the event that an intermediate or third string of surface casing is run, rig mobilization and trucking costs, the additional cost for directional drilling and drill stem testing, sidetracking, fishing of drilling tools; and
c)
The tangible costs of drilling and completing the partnership wells and of gathering pipelines necessary to connect the well to the nearest appropriate sales point or delivery point.
Business Segments
The Partnership operates in one business segment, natural gas and oil sales.
Plan of Operations
Initial Development
With regard to the Partnership’s developmental wells drilled in Colorado, 12 wells were drilled in the Wattenberg Field and 2 wells were drilled in the Grand Valley Field.
The 12 Partnership wells in the Wattenberg Field were targeted to the Codell formation or deeper. The Wattenberg Field, located north and east of Denver, Colorado, is located within the Denver-Julesburg (“DJ”) Basin. Wells in the DJ Basin area may include as many as four productive formations. From shallowest to deepest, these are the Sussex, the Niobrara, the Codell and the J Sand. The primary producing zone for most of the Partnership’s wells is the Codell formation.
The 2 Partnership wells in the Grand Valley Field were targeted to the Mesa Verde formation. The Grand Valley Field is in the Piceance Basin, located near the western border of Colorado. The producing interval consists of a total of 150 to 300 feet of productive sandstone divided into 10 to 15 different zones. The production zones are separated by layers of nonproductive shale resulting in a total production interval of 2,000 to 4,000 feet with alternating producing and non-producing zones. The Partnership’s natural gas reserves and production is attributable to these various zones.
The typical well production profile for wells in both the Wattenberg and Grand Valley fields displays an initial high production rate and relatively rapid decline in this production rate in the first few years, followed by years of relatively lower declines. Natural gas is the primary hydrocarbon produced; however, the majority of the wells in the Wattenberg Field also produce oil. For natural gas, the sales price may include revenue from the recovery of propane and butane in the gas stream, as well as a premium for the typical high-energy content of the natural gas.
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Future Development Opportunities
Well recompletions in the Codell formation of the Partnership’s Wattenberg Field wells, which may provide for additional reserve development and natural gas and oil production, generally occur five to ten years after initial well drilling so that well resources are optimally recovered. These well recompletions would generally be expected to occur based on a favorable general economic environment and commodity price outlook. The Managing General Partner has the authority to determine whether to conduct any or all additional Codell formation well development activities and to determine the timing of this development. The timing of the development activities can be affected by the desire to optimize the economic return by further developing well resources when commodity prices are at levels to obtain the highest rate of return to the Partnership. The number and timing of the Partnership’s well recompletions will be subject to Partnership’s cash availability since borrowing is not permitted. The Managing General Partner may retain Partnership distributable cash flows, if needed, so that Partnership operations may fully develop the Partnership's wells; but if full or partial development of the Partnership's wells proves commercially unsuccessful, a reduction in cash distributions may result.
A recompletion consists of a second fracture treatment in the same formation originally fractured in the initial completion. PDC and other producers have found that the recompletions generally increase the production rate and recoverable reserves of the wells. Historically, the production resulting from PDC's Codell recompletions has been above the modeled economics; however, all recompletions have not been economically successful and future recompletions may not be economically successful. The cost of recompleting a well producing from the Codell formation is generally one third of the cost of a new well. If the recompletion work is performed, PDC will charge the Partnership for the direct costs of recompletions, and the Investor Partners and the Managing General Partner will each pay their proportionate share of costs based on the operating costs sharing ratios of the Partnership from funds retained by the Managing General Partner from distributable cash flows.
Well Development Plan
The Managing General Partner expects to commence Wattenberg Field Codell formation recompletion activities during 2011 or as soon as economically feasible, thereafter. In October 2010 the Managing General Partner began to withhold funds from distributable cash flows for some of the Partnerships, in which they are the Managing General Partner, resulting from current production. The funds retained that are necessary for the Partnership to pay for recompletion costs will materially reduce, up to 100%, distributable cash flows for a period of time not to exceed five years. As of October 2010 no funds have been witheld from the Partnership distributions. If any or all of the Partnership’s Wattenberg wells are not recompleted, the Partnership will experience a reduction in proved reserves currently assigned to these wells. Both the number of recompletions and the timing of recompletions will be based on the availability of cash withheld from distributions. The Managing General Partner believes that, based on projected recompletion costs and projected cash withholding, all partnership recompletions can be completed. Current estimated costs for these well recompletions are between $150,000 and $200,000 per recompletion. This Partnership potentially has twelve well completion opportunities. Total withholding for these activities from the Partnership’s distributable cash flows is estimated to be between $1.8 million and $2.4 million. As the optimal period approaches, the Managing General Partner will re-evaluate the feasibility of commencing those recompletions based on engineering data and a favorable commodity price environment in order to maximize the financial benefit of the recompletion.
Title to Properties
The Partnership holds record title in its name to the working interest in each well. PDC provided an assignment of working interest for the well bore, prior to the spudding of the well and effective the date of the spudding of the well, to the Partnership in accordance with the D&O Agreement. Upon completion of the drilling of all of the Partnership wells, these assignments were recorded in the applicable county. Investor Partners rely on PDC to use its best judgment to obtain appropriate title to these working interests. Provisions of the Limited Partnership Agreement (the “Agreement”), generally relieve PDC of liability resulting from errors in judgment with respect to the waiver of title defects. PDC takes those steps it deems necessary to assure that title to the working interests is acceptable for purposes of the Partnership. For additional information, see Item 2, Properties - Title to Properties.
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Well Operations
General. As operator, PDC represents the Partnership in all operating matters, including the drilling, testing, completion, recompletion and equipping of wells and the marketing and sale of the Partnership’s natural gas and oil production from the wells. PDC, in accordance with the D&O Agreement, is the named operator of record of the wells in which the Partnership owns an interest.
PDC, through the D&O Agreement, provides equipment and supplies, perform salt water disposal services and other services for the Partnership. PDC sold equipment to the Partnership as needed in the drilling or completion of Partnership wells. All equipment and services were sold at the lower of cost or competitive prices in the area of operations.
Gas Pipeline and Transmission. The transmission and gathering lines, which are owned either by PDC or other third parties and which transport the Partnership's natural gas production, are subject to seasonal curtailment and occasional limitations due to repairs, improvements or as a result of priority transportation agreements with other natural gas transporters. Seasonal curtailment typically occurs during July and August as a result of high atmospheric temperatures which reduce compressor efficiency. This reduction in production typically amounts to less than five percent of normal monthly production. The cost, timing and availability of gathering pipeline connections and service varies from area to area, well to well, and over time. When a significant amount of development work is being done in an area, production can temporarily exceed the available markets and pipeline capacity to move natural gas to more distant markets. This excess supply can lead to lower natural gas prices relative to other areas as the producers compete for the available markets by reducing prices. This excess supply can also lead to curtailments of production and periods when wells are shut-in due to lack of market.
Sale of Production. In accordance with the D&O Agreement, PDC markets the natural gas and oil produced from the Partnership’s wells on a competitive basis, at what it believes to be, the best available terms and prices generally, under contracts with indexed monthly pricing provisions. Generally, 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 multi-year contracts requiring the dedication of the natural gas produced from a well for a period ranging up to the life of the well. PDC does not charge an additional fee for the marketing of the natural gas and oil because these services are covered by the monthly well operating charge. This monthly charge is more fully described in the following Item 1, Business−Well Operations, D&O Agreement.
The gas is sold at negotiated prices based upon a number of factors, including the quality of the gas, well pressure, estimated remaining reserves, prevailing supply conditions and any applicable price regulations promulgated by the Federal Energy Regulatory Commission, or FERC. The Partnership sells oil produced by its wells to local oil purchasers at spot prices. The produced oil is stored in tanks at or near the location of the Partnership’s wells for routine pickup by oil transport trucks.
In general, the Partnership has been and expects to continue to be able to produce and sell natural gas and oil from the Partnership’s wells without significant curtailment and at locally competitive prices. The Partnership does experience limited curtailments from time to time due to pipeline maintenance and operating issues, as discussed above.
Price Risk Management. Price volatility is a very significant and a potential destabilizing factor in the natural gas and oil production industry. To help manage the risks associated with the natural gas and oil industry prices, the Partnership proactively employs strategies to reduce the effects of commodity price volatility on cash flows by utilizing commodity based derivative instruments to manage a portion of the exposure to price volatility. These instruments consist of Colorado Interstate Gas Index, or CIG, based contracts for Colorado natural gas production, basis protection swaps and New York Mercantile Exchange, or NYMEX, based contracts for Colorado oil production and natural gas production. The contracts provide price protection for committed and anticipated natural gas and oil sales. The Partnership's policies prohibit the use of natural gas and oil futures, swaps, CIG basis protection swaps or options for speculative purposes and permit utilization of derivatives only if there is an underlying physical position. While the Partnership’s derivative instruments are utilized to manage the impact of price volatility of its natural gas and oil production, the Managing General Partner does not designate any of the Partnership’s derivative as hedges; therefore the Partnership’s derivative financial instruments currently do not qualify under the terms of Statement of Financial Accounting Standards (“SFAS”) No. 133, Accounting for Derivative Instruments and Certain Hedging Activities. Thus, the Partnership is required to recognize changes in the fair value of its derivative positions in Partnership earnings each reporting period thereby resulting in the potential for significant earnings volatility. Along with realized gains or losses, these changes in fair value are classified as “Commodity price risk management gain (loss), net” on the statements of operations. See Note 2, Summary of Significant Accounting Policies−Derivative Financial Instruments, to the Partnership’s accompanying financial statements included in this report.
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The sale of the Partnership’s production is subject to market price fluctuations for natural gas sold in the spot market and under market index contracts. PDC, as Managing General Partner, continues to evaluate the potential for reducing these risks by entering into derivative transactions. The Managing General Partner may close out any portion of derivatives that may exist from time to time which may result in a realized gain or loss on that derivative transaction. The Partnership manages price risk on a portion of its future estimated production, and therefore future production not covered by derivatives is subject to the full fluctuation of market pricing. See Item 7A, Quantitative and Qualitative Disclosure About Market Risk for details on the Partnership’s outstanding derivative positions.
The Partnership utilizes financial derivatives to establish “floors,” “collars,” fixed-price “swaps” or “basis protection swaps” on the possible range of the prices realized for the sale of natural gas and oil. These are recorded on the balance sheet at fair value with changes in fair values recognized currently in the statement of operations under the caption "Commodity price risk management gain (loss), net." PDC, as Managing General Partner of the Partnership, enters into derivative transactions on behalf of the Partnership in the same manner in which it enters into transactions for itself.
·
“Floors” contain a floor price (put) whereby PDC, as Managing General Partner, receives the market price from the purchaser and the difference between the index price and floor strike price from the counterparty if the index price falls below the floor strike price, but receives no payment when the index price exceeds the floor strike price.
·
“Collars” contain a fixed floor price (put) and ceiling price (call). If the index price falls below the fixed put strike price, PDC, as Managing General Partner, receives the market price from the purchaser and receives the difference between the put strike price and the index price from the counterparty. If the index price exceeds the fixed call strike price, PDC, as Managing General Partner, receives the market price from the purchaser and pays the difference between the call strike price and the index price to the counterparty. If the index price is between the call and put strike price, no payments are due to or from the counterparty.
·
“Swaps” are arrangements that guarantee a fixed price. If the index price is below the fixed contract price, PDC, as Managing General Partner, receives the market price from the purchaser and receives the difference between the index price and the fixed contract price from the counterparty. If the index price is above the fixed contract price, PDC, as Managing General Partner, receives the market price from the purchaser and pays the difference between the index price and the fixed contract price to the counterparty. If the index price and contract price are the same, no payment is due to or from the counterparty.
In addition to the Partnership’s prior use of floors, collars and swaps derivative instruments, in December 2008, the Partnership began the utilization of “basis protection swaps” which are arrangements that guarantee a price differential for natural gas from a specified delivery point. For Partnership CIG basis protection swaps which traditionally have a negative pricing differential to NYMEX, PDC as Managing General Partner receives a payment from the counterparty if the price differential is greater than the stated terms of the contract and pays the counterparty if the price differential is less than the stated terms of the contract. If the index price and contract price are the same, no payment is due to or from the counterparty. See Item 1A, Risk Factors - The Partnership's derivative activities could result in reduced future revenue and cash flows compared to the level the Partnership might experience if no derivative instruments were in place.
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The Partnership’s allocation of derivative positions is based on the Partnership’s percentage of estimated production to total estimated production from a given area on a monthly basis. The transactions are on a production month basis. Therefore, the Partnership may participate in a derivative for a future period before it has production from that area. Prior to September 30, 2008, as estimated future production volumes increased due to continued drilling and wells placed into production, the allocation of derivative positions between PDC’s corporate interests and this Partnership, changed on a pro-rata basis. Effective September 30, 2008, PDC changed the allocations procedure whereby the allocation of derivative positions between PDC and each partnership was set at a fixed quantity. For positions entered into subsequent to September 30, 2008, specific designations of the quantities between the Managing General Partner’s corporate interests and each sponsored drilling partnership, including this Partnership, were allocated and fixed at the time the positions are entered into based on estimated future production. The Partnership believes that in a changing price environment, derivative positions are desirable to obtain more predictable cash flows and to reduce the impact of possible future price declines.
D&O Agreement. The Partnership has entered into the D&O Agreement with PDC. The D&O Agreement provides that the operator conduct and direct drilling operations, including well recompletions, and has the authority to manage the operations of the Partnership's wells. Generally, PDC has limited liability to the Partnership for losses sustained or liabilities incurred, except as may result from the operator's gross or willful negligence or misconduct. Under the terms of the D&O Agreement, PDC may subcontract certain functions as operator for Partnership wells. PDC retains responsibility for work performed by subcontractors.
To the extent the Partnership has less than a 100% working interest in a well, the Partnership pays only its proportionate share of total lease, development, and operating costs, and receives its proportionate share of production subject only to royalties and overriding royalties. The Partnership is responsible only for its obligations and is liable only for the Partnership’s proportionate working interest share of the costs of developing and operating the wells.
Under the D&O Agreement, the operator may provide all necessary labor, vehicles, supervision, management, accounting, and overhead services for normal production operations, and may deduct from Partnership revenues a fixed monthly charge for these services. The charge for these operations and field supervision fees (referred to as “well tending fees”) for each producing well are based on competitive industry rates, which vary based upon the area of operation. The well tending fees and administration fees may be adjusted annually to an amount equal to the rates initially established by the D&O Agreement multiplied by the then current average of the Oil and Gas Extraction Index and the Professional and Technical Services Index, as published by the United States Department of Labor, Bureau of Labor Statistics, provided that the charge may not exceed the rate which would be charged by the comparable operators in the area of operations. This average is commonly referred to as the Accounting Procedure Wage Index Adjustment which is published annually by the Council of Petroleum Accountants Societies, or COPAS.
Under the D&O Agreement the Partnership has the right to take in kind and separately dispose of its share of all natural gas and oil produced from the Partnership’s wells. In accordance with the D&O Agreement, the Partnership designated PDC as its agent to market its production and authorized PDC to enter into and bind the Partnership in those agreements as it deems in the best interest of the Partnership for the sale of its oil and/or natural gas. Where pipelines owned by PDC are used in the delivery of natural gas to market, PDC charges a market rate gathering fee not to exceed that which would be charged by a non-affiliated third party for a similar service.
The D&O Agreement remains in force as long as any well or wells produce, or are capable of economic production, and for an additional period of 180 days from cessation of all production, or until PDC is replaced as Managing General Partner as provided for in the D&O Agreement.
Production Phase of Operations
When Partnership wells were "completed" (i.e., drilled, fractured or stimulated, and all surface production equipment and pipeline facilities necessary to produce the well were installed), production operations commenced on each well. All Partnership wells are completed and production operations are being conducted with regard to all 14 of the Partnership’s productive wells.
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Under the provision of the D&O Agreement, PDC markets the Partnership’s natural gas to commercial end users, interstate or intrastate pipelines or local utilities, primarily under market sensitive contracts in which the price of natural gas sold varies as a result of market forces. A small percentage of leases, and thus the natural gas derived from wells drilled on those leases, may have been dedicated to particular markets at the time the Partnership drilled wells on such leases, or subsequent to, as part of the natural gas marketing arrangements. In general, the Partnership has been, and expects to continue to be able to, produce and sell natural gas from Partnership wells without significant curtailment and at competitive prices. The Partnership does experience limited curtailments from time to time due to pipeline maintenance and operating issues of the pipeline operators.
The majority of the Partnership’s wells in the Wattenberg Field in Colorado produce oil in addition to natural gas. The Managing General Partner is currently able to sell all the oil that the Partnership 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 both short and long-term purchase contracts with monthly pricing provisions.
PDC, on behalf of the Partnership, may enter into fixed price contracts, or utilize derivatives, including collars, swaps or basis protection swaps, in order to offset some or all of the price variability for particular periods of time. The use of derivatives may entail fees, including the time value of money for margin requirements, which are charged to the Partnership.
Seasonal factors, such as effects of weather on prices received and costs incurred, and availability of pipeline capacity, may impact the Partnership's results of operations. In addition, both sales volumes and prices could be subject to demand factors.
Revenues, Expenses and Distributions
The Partnership's share of production revenue from a given well is burdened by and/or subject to royalties and overriding royalties, monthly operating charges, taxes and other operating costs. In instances when distributable cash flows are insufficient to make full payment, PDC defers the collection of operating expenses until such time as scheduled expenses may be offset against future Partnership distributable cash flows. In such instances, the Partnership records a liability to PDC.
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Production, Sales, Prices and Lifting Costs
The following table sets forth information regarding the Partnership’s production volumes, natural gas and oil sales, average sales price received and average lifting cost incurred for the periods indicated.
(1)
Production as shown in the table is determined by multiplying the gross production volume of properties in which the Partnership has an interest by the percentage of the leasehold or other property interest the Partnership owns.
(2)
The Partnership utilizes commodity based derivative instruments to manage a portion of its exposure to commodity price volatility of its natural gas and oil sales.
(3)
Production costs represent natural gas and oil operating expenses which include severance and ad valorem taxes as reflected in the Partnership’s financial statements. See Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations - Production and Operating Costs.
Definitions used throughout Item 1, Business:
·
Bbl - One barrel or 42 U.S. gallons liquid volume
·
MBbl - One thousand barrels
·
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 reflect the relative energy content
·
MMcf - One million cubic feet
·
MMcfe - One million cubic feet of natural gas equivalents
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Natural Gas and Oil Reserves
All of the Partnership’s natural gas and oil reserves are located in the United States. The Managing General Partner’s Reserve Engineering Department petroleum engineers performed the Partnership’s reserve evaluation for the years 2007, 2006 and 2005. The engineers’ estimates were made using available geological and reservoir data as well as production performance data. The estimates were prepared with respect to reserve categorization, using the definitions in effect during the years 2007, 2006 and 2005 for proved reserves set forth in Regulation S-X, Rule 4-10(a) as interpreted by the SEC’s staff interpretations and guidance, since the SEC’s Modernization of Oil and Gas Reporting final rule prohibits retroactive application of the new natural gas and oil industry disclosure standards. These new SEC natural gas and oil industry disclosure rules will be implemented by the Partnership in its Annual Report on Form 10-K as of December 31, 2009.
The tables below set forth information as of December 31, 2007, regarding the Partnership’s proved reserves as estimated by the Managing General Partner’s Reserve Engineering Department petroleum engineers. Reserves cannot be measured exactly, because reserve estimates involve subjective judgment. The estimates are reviewed periodically and adjusted to reflect additional information gained from reservoir performance data, new geological and geophysical data and economic changes. Neither the present value of estimated future net cash flows nor the standardized measure is intended to represent the current market value of the estimated natural gas and oil reserves which the Partnership owns. The Partnership’s estimated proved undeveloped reserves consist entirely of the reserves attributable to the future recompletions of the Codell formation in the 12 Wattenberg Field wells. (see Item 1, Business−Plan of Operations, Future Development Opportunities.)
Estimated future net cash flows represents the estimated future gross revenues expected to be generated from the production of proved reserves, net of estimated production costs and future development costs, using price assumptions and costs, in effect at December 31, 2007. The price assumptions, which were consistent with professional standards and SEC natural gas and oil industry rules and regulations, then in effect during 2007, utilized in the Partnership’s reserve reports yield weighted average wellhead prices of $80.17 per barrel of oil and $7.61 per Mcf of natural gas. These price assumptions should not be interpreted as a prediction of future prices, nor do they reflect the value of the Partnership’s commodity hedges in place at December 31, 2007. The amounts shown do not give effect to non-property related expenses, such as direct costs - general and administrative expenses, or to depreciation, depletion and amortization. For more information regarding the SEC’s Modernization of Oil and Gas Reporting and the major provisions likely to impact the both the determination of and disclosures for the Partnership’s natural gas and oil reserves when adopted as of December 31, 2009, see Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations−Recent Accounting Standards.
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The standardized measure of discounted future estimated net cash flows is calculated in accordance with Statement of Financial Accounting Standards, or SFAS, No. 69, Disclosures About Oil and Gas Producing Activities, which requires the future cash flows to be discounted. The discount rate used was 10%. Additional information on this measure is presented in Supplemental Natural Gas and Oil Information - Unaudited, Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Natural Gas and Oil Reserves, included in this report.
Insurance
PDC, in its capacity as operator, has purchased well pollution, public liability and worker’s compensation insurance policies for its own benefit as well as the benefit of the Partnership. However such insurance may not be sufficient to cover all potential liabilities which the Partnership may be exposed to at this date or a future date. Each partner who elected to participate as an additional general partner assumed potential unlimited liability for unforeseen events such as blowouts, lost circulation, and stuck drill pipe occurring prior to converting to limited partner status. The occurrence of any such event could have resulted in unanticipated additional liability materially in excess of the per unit subscription amount. However, upon conversion to limited partner status, on October 20, 2003 all investor partners’ liability became limited based on the partnership laws in West Virginia. The remaining general partner is PDC, also the Managing General Partner.
PDC has obtained various insurance policies, as described below, and intends to maintain these policies subject to PDC's analysis of their premium costs, coverage and other factors. PDC may, in its sole discretion, increase or decrease the policy limits and types of insurance from time to time as deemed appropriate under the circumstances, which may vary materially. PDC is the named beneficiary under each policy and pays the premiums for each policy, except with respect to the insurance coverage referred to in Items 2 and 5 below in which case the Managing General Partner and the Partnership are co-insured and co-beneficiaries. Additionally, PDC as operator of the Partnership's wells requires all of PDC's subcontractors to carry liability insurance coverage with respect to the subcontractors’ activities. In the event of a loss due to the subcontractors’ performance, the insurance policies of the particular subcontractor at risk may be drawn upon before the insurance of the Managing General Partner or that of the Partnership. PDC has obtained and expects to maintain the following insurance.
1.
Worker's compensation insurance in full compliance with the laws for the states in which the operator has employees;
2.
Operator's bodily injury liability and property damage liability insurance, each with a limit of $1 million;
3.
Employer's liability insurance with a limit of not less than $1 million;
4.
Automobile public liability insurance with a limit of not less than $1 million per occurrence, covering all PDC owned or leased automobile equipment; and
5.
Operator's umbrella liability insurance with a limit of $50 million for each well location and in the aggregate.
PDC’s management, as Managing General Partner, believes that adequate insurance, including insurance by PDC’s subcontractors, has been provided to the Partnership with coverage sufficient to protect the Investor Partners against the foreseeable risks of operation, drilling recompletions and reworks. PDC has maintained liability insurance, including umbrella liability insurance, of at least two times the Partnership’s capitalization, up to a maximum of $50 million, but in no event less than $10 million during drilling or recompletion operations.
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Competition and Markets
The Partnership believes that the drilling and production capabilities and the experience of the Managing General Partner’s management and professional staff generally enables the Partnership to compete effectively. The Partnership encounters competition from other natural gas and oil companies, drilling and income programs and partnerships in its area of operation. Some of these competitors possess larger staffs and greater financial resources than that of the Partnership, which may enable them to further develop and operate Colorado producing properties more economically. During the period 2005 through 2008, the industry generally experienced increasingly stronger demand for drilling services and supplies that resulted in period-to-period price increases through the first three quarters of the 2008. As a result of the late 2008 turmoil in the financial and commodity markets and resultant industry slowdown throughout 2009, the Partnership has experienced overall reductions in its operating and drilling costs. Factors affecting competition in the industry include commodity market price, location of natural gas and oil producing facilities, availability of drilling/service rigs, pipeline capacity, quality of production and volumes produced. The Partnership believes that it can compete effectively in its area of operations. Nevertheless, the Partnership’s results of operations and distributable cash flows could be materially adversely affected by competition.
As a result of this industry competition and FERC and Congressional deregulation of natural gas and oil commodity prices, the Partnership’s sales prices are generally determined by competitive forces. The marketing of natural gas and oil produced by the Partnership is affected by a number of factors some of which are beyond the Partnership's control and the exact effect of which cannot be accurately predicted. These factors include the volume and prices of crude oil imports, the availability and cost of adequate pipeline and other transportation facilities, the marketing of competitive fuels, such as coal and nuclear energy, and other matters affecting the availability of a ready market, such as fluctuating supply and demand. Among other factors, the supply and demand balance of natural gas and crude oil in world markets may have caused significant variations in the prices of these products over recent years.
FERC Order No. 636, issued in 1992, restructured the natural gas industry by requiring natural gas pipelines to separate their storage, sales and transportation functions and establishing an industry-wide structure for "open-access" transportation service. FERC Order No. 637, issued in February 2000, further enhanced competitive initiatives, by removing price caps on short-term capacity release transactions.
FERC Order No. 637 also enacted other regulatory policies that increase the flexibility of interstate natural gas transportation, maximize shippers' supply alternatives, and encourage domestic gas production in order to meet projected increases in gas demand. These increases in demand come from a number of sources, including as boiler fuel to meet increased electric power generation needs and as an industrial fuel that is environmentally preferable to alternatives such as nuclear power and coal. This trend has been evident over the past year, particularly in the western U.S., where natural gas is the preferred fuel for environmental reasons, and electric power demand has directly increased the demand for natural gas.
The combined impact of FERC Order No. 636 and No. 637 has been to increase competition among natural gas suppliers from the different natural gas producing regions in the U.S.
In 1995, the North American Free Trade Agreement, or NAFTA, eliminated trade and investment barriers in the United States, Canada, and Mexico, increasing foreign competition for gas production. Legislation that Congress may consider with respect to natural gas and oil may increase or decrease the demand for the Partnership's production in the future, depending on whether the legislation is directed toward decreasing demand or increasing supply.
Members of the Organization of Petroleum Exporting Countries, or OPEC, establish prices and production quotas for petroleum products of OPEC members from time to time. PDC is unable to predict what effect, if any, future OPEC actions will have on the quantity of, or prices received for, natural gas and oil produced and sold from the Partnership's wells.
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The Partnership’s well fields are crossed by pipelines belonging to DCP Midstream LP (“DCP”), Williams Production, RMT (“Williams”) and others. These companies have all traditionally purchased substantial portions of their supply from Colorado producers. Transportation on these systems requires that delivered natural gas meet quality standards and that a tariff be paid for quantities transported.
Sales of natural gas from the Partnership's wells to DCP and Williams are made on the spot market via open access transportation arrangements through Williams or other pipelines. As a result of FERC regulations that require interstate gas pipeline companies to separate their merchant activities from their transportation activities and require these companies to release available capacity on both a short and a long-term basis, local distribution companies have taken an increasingly active role in acquiring their own natural gas supplies. Consequently, PDC believes pipelines and local distribution companies (utilities) are buying natural gas directly from natural gas producers and marketers, and retail unbundling efforts are causing many end-users to buy their own reserves. PDC also believes that activity by state regulatory commissions to review local distribution company procurement practices more carefully and to unbundle retail sales from transportation has caused natural gas purchasers to minimize their risks in acquiring and attaching natural gas supply and has increased competition in the natural gas marketplace.
Natural Gas and Oil Pricing
PDC markets the natural gas and oil from Partnership wells in Colorado subject to market sensitive contracts, the price of which increases or decreases with market forces beyond control of the Partnership. Currently, PDC sells Partnership gas in the Piceance Basin to Williams, which has an extensive gathering and transportation system in this Basin. In the Wattenberg Field, the gas is sold primarily to DCP, which gathers and processes the gas and liquefiable hydrocarbons produced. Natural gas produced in Colorado may be impacted by changes in market prices on a national level, as well as changes in the market for natural gas within the Rocky Mountain Region. Sales may be affected by capacity interruptions on pipelines transporting natural gas out of the region.
Through December 31, 2008, PDC sold substantially all of the crude oil from the Partnership’s wells to Teppco Crude Oil, LP (“Teppco”). The oil is picked up at the well site and trucked to either refineries or oil pipeline interconnects for redelivery to refineries. Oil prices fluctuate not only with the general market for oil as may be indicated by changes in the NYMEX, but also due to changes in the supply and demand at the various refineries. The cost of trucking or transporting the oil to market affects the price the Partnership ultimately receives for the oil. Beginning January 1, 2009, the Partnership began selling the majority of its crude oil to Suncor Energy Marketing, Inc. (“Suncor”).
Governmental Regulation
While the prices of natural gas and oil are set by the market, other aspects of the Partnership's business and the natural gas and oil industry in general are heavily regulated. The availability of a ready market for natural gas and oil production depends on several factors beyond the Partnership's control. These factors include regulation of production, federal and state regulations governing environmental quality and pollution control, the amount of natural gas and oil available for sale, the availability of adequate pipeline and other transportation and processing facilities and the marketing of competitive fuels. State and federal regulations generally are intended to protect consumers from unfair treatment and oppressive control, to reduce the risk to the public and workers from the drilling, completion, production and transportation of natural gas and oil, to prevent waste of natural gas and oil, to protect rights of owners in a common reservoir and to control contamination of the environment. Pipelines are subject to the jurisdiction of various federal, state and local agencies. PDC management, as Managing General Partner, believes that the Partnership is in compliance with such statutes, rules, regulations and governmental orders, although there can be no assurance that this is or will remain the case. The following summary discussion of the regulation of the United States natural gas and oil industry is not intended to constitute a complete discussion of the various statutes, rules, regulations and environmental orders to which the Partnership's operations may be subject.
Environmental Regulation
The Partnership’s operations are subject to numerous laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. Public interest in the protection of the environment has increased dramatically in recent years. The trend of more expansive and tougher environmental legislation and regulations could continue. To the extent laws are enacted or other governmental action is taken that restricts drilling or imposes environmental protection requirements that result in increased costs and reduced access to the natural gas industry in general, our business and prospects could be adversely affected. In December 2008, the State of Colorado’s Oil and Gas Conservation Commission finalized new broad-based wildlife protection and environmental regulations for the natural gas and oil industry which are expected to increase the Partnership’s well recompletion costs and ongoing level of production and operating costs. Partnership expenses relating to preserving the environment have risen since the period covered by this annual report (2007-2005) and are expected, as a consequence of the factors described in the following Item 1A, Risk Factors, to continue to rise in 2010 and beyond. While environmental regulations have had no materially adverse effect on the Partnership’s operations to date, no assurance can be given that environmental regulations or interpretations of such regulations will not in the future, result in a curtailment of production or otherwise have a materially adverse effect on Partnership results of operations or distributable cash flows. See Note 8, Commitments and Contingencies, Stormwater Permit.
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The Partnership generates wastes that may be subject to the Federal Resource Conservation and Recovery Act, or RCRA, and comparable state statutes. The U.S. Environmental Protection Agency, or EPA, and various state agencies have limited the approved methods of disposal for certain hazardous and non-hazardous wastes. Furthermore, certain wastes generated by our operations that are currently exempt from treatment as "hazardous wastes" may in the future be designated as "hazardous wastes," and therefore be subject to more rigorous and costly operating and disposal requirements.
Proposed Regulation
Various legislative proposals and proceedings that might affect the petroleum and natural gas industries occur frequently in Congress, FERC, state commissions, state legislatures, and the courts. These proposals involve, among other things, imposition of direct or indirect price limitations on natural gas production, expansion of drilling opportunities in areas that would compete with Partnership production, imposition of land use controls, landowners' "rights" legislation, alternative fuel use requirements and/or tax incentives and other measures. The petroleum and natural gas industries historically has been very heavily regulated; therefore, there is no assurance that the less stringent regulatory approach recently pursued by FERC and Congress will continue. The Partnership cannot determine to what extent its future operations and earnings will be affected by new legislation, new regulations, or changes in existing regulation, at federal, state or local levels. For more information regarding proposed and enacted regulations effecting the oil and gas industry, see the following Item 1A, Risk Factors−The current trend is to increase regulation of the natural gas and oil industry. The Partnership is subject to complex federal, state, local and other laws and regulations that could adversely affect the cost, manner or feasibility of doing business.
Operating Hazards
The Partnership's production operations include a variety of operating risks, including but not limited to the risk of fire, explosions, blowouts, cratering, pipe failure, casing collapse, abnormally pressured formations, and environmental hazards such as natural gas leaks, ruptures and discharges of toxic gas. The occurrence of any of these could result in substantial losses to the Partnership due to injury and loss of life, severe damage to and destruction of property, natural resources and equipment, pollution and other environmental damage, clean-up responsibilities, regulatory investigation, criminal proceedings and penalties and suspension of operations. Pipeline, gathering and transportation operations are subject to the many hazards inherent in the natural gas industry. These hazards include damage to wells, pipelines and other related equipment, damage to property caused by hurricanes, floods, fires and other acts of God, inadvertent damage from construction equipment, leakage of natural gas and other hydrocarbons, fires and explosions and other hazards that could also result in personal injury and loss of life, pollution and suspension of operations.
Any significant problems related to Partnership wells could adversely affect the Managing General Partner’s ability to conduct operations. In accordance with customary industry practice, the Partnership maintains insurance against some, but not all, potential risks; however, there can be no assurance that such insurance will be adequate to cover any losses or exposure for liability. The occurrence of a significant event not fully insured against could materially adversely affect Partnership operations and financial condition. The Managing General Partner cannot predict whether insurance will continue to be available at premium levels that justify its purchase or whether insurance will be available at all. Furthermore, the Partnership is not insured against economic losses resulting from damage or destruction to third party property, such as the Rockies Express pipeline; such an event could result in significantly lower regional prices or the Partnership’s inability to deliver natural gas. As of the date of this filing, the Managing General Partner has no knowledge that such events have occurred.
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Available Information
The Partnership is subject to the reporting and information requirements of the Securities Exchange Act of 1934, as amended, and is as a result obligated to file periodic reports, proxy statements and other information with the SEC. The SEC maintains a website that contains the annual, quarterly, and current reports, proxy and information statements, and other information regarding the Partnership, which the Partnership electronically files with the SEC. The address of that site is http://www.sec.gov. The Central Index Key, or CIK, for the Partnership is 0001224952. You can read and copy any materials the Partnership files with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Room 1850, Washington, D.C. 20549. You may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330.
Item 1A.
Item 1A.
Risk Factors
The Partnership encourages you to carefully consider the following risk factors in addition to the other information included in this Annual Report. Each of these risk factors could adversely affect the Partnership’s operations, financial condition, and cash distributions as well as adversely affect the value of each partner’s equity account.
Risks Related to the Global Economic Environment
There may be a reoccurrence of the 2009 global economic environment which increased the magnitude and the likelihood of the occurrence of the negative consequences discussed in many of the risk factors that follow. In particular, consider the risks related to the rapid deterioration of demand for natural gas and oil resulting from the economic environment and the related negative effects on natural gas and oil pricing. Further reductions in natural gas and oil prices could result in existing Partnership wells being uneconomical to recomplete which would reduce remaining Partnership proved reserves. These factors could limit the Managing General Partner’s ability to execute the Partnership business plan and result in lower Partnership production, adversely impacting Partnership income and Investor Partner distributions. Additionally, the global economic environment also increases the Partnership’s credit risk associated with derivative financial institutional counterparty default or natural gas and oil purchaser non-payment, thus potentially impacting Partnership liquidity and production operating levels. Lastly, inability to ascertain the ultimate depth and duration of the economic environment could cause the Partnership to refrain from recompleting some or all of the Wattenberg Field wells in order to maintain higher liquidity or distributable cash flows; the Managing General Partner’s uncertainty and caution could result in significantly reduced well recompletions and hence reduced future reserves, production and natural gas and oil sales revenues. All of these risks could have a significant effect on the Partnership’s business, financial results and Partnership distributions. Any additional deterioration in the domestic or global economic conditions will further amplify these results.
There may be a reoccurrence of the 2009 disruptions in the global financial markets and the related economic environment may further decrease the demand for natural gas and oil and their respective commodity prices, thereby limiting the Partnership’s production and adversely affecting Partnership profitability and Investor Partner distributions. During much of 2009, prices for natural gas and oil decreased over 60% from the 2008 peak. The well-publicized global financial market disruptions and the related economic environment may further decrease demand for natural gas and oil and therefore lower natural gas and oil prices. If there is such an additional reduction in demand, the continued production of gas may increase current oversupply and result in still lower gas prices. There is no certainty how long this low price environment will continue. The Partnership operates in a highly competitive industry, and certain competitors may have lower operating costs in such an environment. Inability of third parties to finance and build additional pipelines out of the Rockies and elsewhere could cause significant negative pricing effects. Any of the above factors could adversely affect the Partnership’s operating results and reduce cash distributions to the Investor Partners.
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Risks Pertaining the Natural Gas and Oil Industry and Partnership’s Operations
The natural gas and oil business is speculative and may be unprofitable and result in the total loss of investment. The natural gas and oil business is inherently speculative and involves a high degree of risk and the possibility of a total loss of investment. The Partnership's business activities may result in unprofitable well operations, not only from non-productive wells and recompletions, but also from wells that do not produce oil or natural gas in sufficient quantities or quality to return a profit on the amounts expended. The prices of natural gas and oil play a major role in the profitability of the Partnership. Partnership wells may not produce sufficient natural gas and oil for investors to receive a profit or even to recover their initial investment. Only four out of 77 partnerships sponsored by PDC have, to date, generated cash distributions in excess of investor subscriptions without giving effect to tax savings.
Competition in the natural gas and oil industry is intense, which may adversely affect the Partnership’s ability to succeed. The industry is intensely competitive, and the Partnership competes with other companies that have greater resources. Many of these companies not only explore for and produce natural gas and oil, but also carry on refining operations and market petroleum and other products on a regional, national or worldwide basis. These companies may be able to pay more to operate productive natural gas and oil properties or more economically develop natural gas and oil properties than the Partnership. Larger competitors may be able to absorb the burden of present and future federal, state, local and other laws and regulations more easily than the Partnership can, which can adversely affect the Partnership’s competitive position. The Partnership’s ability to more fully exploit the Partnership’s reserves in the future will be dependent upon the Managing General Partner’s ability to evaluate and select the most promising Wattenberg Field recompletion opportunities and to consummate transactions in this highly competitive environment. In addition, because many companies in the natural gas and oil industry have greater financial and human resources, the Managing General Partner may be at a disadvantage in producing natural gas and oil properties. These factors could adversely affect the success of Partnership operations, profitability and distributable cash flows.
Natural gas and oil prices fluctuate unpredictably and a decline in prices of natural gas and oil prices can significantly affect the value of the Partnership’s assets, financial results and distributable cash flows. The Partnership’ revenue, profitability and partner distributions depend in large part, upon the prices and demand for natural gas and oil. The markets for these commodities are very volatile, and even relatively modest drops in prices can significantly affect the Partnership’s financial results. Changes in natural gas and oil prices have a significant effect on the Partnership’s cash flow and on the value of the Partnership’s reserves. Prices for natural gas and oil may fluctuate widely in response to relatively minor changes in the supply of and demand for natural gas and oil, market uncertainty and a variety of additional factors that are beyond the Partnership’s control, including national and international economic and political factors and federal and state legislation. The prices in much of 2009 have been too low to economically justify many drilling operations, including some well recompletions, and it is uncertain how long such low pricing shall persist. Borrowing is not permitted by the Agreement, so that if distributable cash flows are not sufficient to meet cash requirements for Partnership operations or all or some of the expected Wattenberg Field Codell recompletions, possible loss of properties, a decline in natural gas and oil reserves and a decline in the Partnership’s investor equity could result.
Lower natural gas and oil prices may not only reduce Partnership revenues, but also may reduce the amount of natural gas and oil that can be produced economically. As a result, the Partnership may have to make substantial additional downward adjustments to its estimated proved reserves. If this occurs or if Partnership estimates of production data factors change, accounting rules may require the Partnership to write-down operating assets to fair value, as a non-cash charge to earnings. The Partnership assesses impairment of capitalized costs of proved natural gas and oil properties by comparing net capitalized costs to estimated undiscounted future net cash flows on a field-by-field basis using estimated future production based upon prices at which the Managing General Partner reasonably estimates such products may be sold.
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The Partnership’s natural gas and oil production is located in the Rocky Mountain Region, making it vulnerable to risks associated with operating in a single major geographic area. The Partnership’s producing properties are located in the Rocky Mountain Region, which means that the Partnership’s remaining natural gas and oil resource development opportunity is geographically concentrated to its natural gas and oil properties located in that area. Because the Partnership’s operations are not as diversified geographically as many of its competitors, the success of Partnership operations, profitability and cash distributions may be disproportionately exposed to the effect of any regional events, including fluctuations in prices of natural gas and oil produced from the wells in the region, natural disasters, restrictive governmental regulations, transportation capacity constraints, curtailment of production or interruption of transportation, and any resulting delays or interruptions of production from existing or anticipated well recompletions. Natural gas prices in the Rocky Mountain Region have fallen disproportionately, both moderately in the historical long-term and more significantly in short-term cycles. One short-term cycle of falling Rocky Mountain natural gas pricing when compared to other U.S. markets, occurred during the period 2005 though 2007 covered by this Annual Report while a second occurred during the last four months of 2008, due in part to continuing constraints in transporting natural gas from producing properties in the region. Because of the concentration of the Partnership’s operations in the Rocky Mountain Region, these price decreases are more likely to have a material adverse effect on the Partnership’s revenue, profitability and cash flow than those of its more geographically diverse competitors. In late 2008 the Partnership entered into a significant multi-year basis hedge minimizing the price risk of the Partnership’s operational concentration in the Rocky Mountain region. Although 2010 natural gas prices in the Rocky Mountain Region have not been as steeply discounted to NYMEX, as occurred during this Annual Report period (2007-2005), in part due to additional interstate pipeline transportation capacity added by the phased-in Rockies Express Pipeline completion during 2008-2009, there can be no assurance the more relative parity in commodity pricing will continue into the future.
Seasonal weather conditions and lease stipulations adversely affect the Partnership’s ability to conduct production activities in its areas of operation. Seasonal weather conditions and lease stipulations designed to protect various wildlife habitats affect natural gas and oil operations in the Rocky Mountains where well recompletion and other natural gas and oil activities are restricted or prohibited by lease stipulations, or prevented by weather conditions, for up to six months out of the year. This limits operations in those areas and can intensify competition during those months for 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, and could result in a reduction of cash distributions to the Investor Partners.
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 individual investor partner might anticipate a reduction in cash distributions. Producing natural gas and oil reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. The rate of decline will change if production from existing wells declines in a different manner than the Managing General Partner estimated or can change due to other circumstances, as discussed in the next risk factor, below. Thus, the Partnership’s future natural gas and oil reserves and production and, therefore, its distributable cash flows, are highly dependent on efficiently recompleting the Partnership’s current wells. In the future, PDC expects to rework or recomplete Partnership wells; however, PDC has not withheld money from the initial investment for that future work. Since the Partnership utilized substantially all of the capital raised in the offering for the drilling and completion of the Partnership’s wells, the Managing General Partner will have to retain Partnership revenues necessary for these purposes. Retaining Partnership revenues will result in a reduction of cash distributions to the investors. Future development of the Partnership's wells may prove commercially unsuccessful and the further-developed Partnership wells may not generate sufficient funds from production to increase distributions to Investor Partners to cover revenues retained. If future development of the Partnership's wells is not commercially successful using funds retained from current production revenues, lower future operational revenues could result in a reduced level of cash distributions to the Investor Partners of the Partnership.
Delay in Partnership natural gas or oil production could reduce the Partnership’s profitability and cash distributions to the Investor Partners. The Partnership’s inability to recomplete wells in a timely fashion may result in production delays. In addition, marketing demands that tend to be seasonal may reduce or delay production from wells. Wells drilled for the Partnership may have access to only one potential market. Local conditions including but not limited to closing businesses, conservation, shifting population, pipeline maximum operating pressure constraints, and development of local oversupply or deliverability problems could halt or reduce sales from Partnership wells. Any of these delays in the production and sale of the Partnership's natural gas and oil could reduce the Partnership's profitability, and in that event, the cash distributions to the Investor Partners of the Partnership would decline.
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The inability of one or more of the Partnership’s customers or derivative counterparties to meet their obligations may adversely affect Partnership profitability and timing of distributions to Investor Partners. Substantially all of the Partnership’s accounts receivable results from natural gas and oil sales to a limited number of third parties in the energy industry. This concentration of customers may affect the Partnership’s overall credit risk in that these entities may be similarly affected by recent changes in economic and other conditions. In addition, Partnership natural gas and oil derivatives positions expose the Partnership to credit risk in the event of nonperformance by counterparties.
The Partnership's derivative activities could result in reduced revenue and cash flows compared to the level the Partnership might experience if no derivative instruments were in place. The Managing General Partner uses derivative instruments for a portion of the Partnership’s natural gas and oil production to achieve a more predictable cash flow and to reduce exposure to adverse fluctuations in the prices of natural gas and oil. These arrangements expose the Partnership to the risk of financial loss in some circumstances, including when purchases or sales are different than expected, the counter-party to the derivative contract defaults on its contract obligations, or when there is a change in the expected differential between the underlying price in the derivative agreement and actual prices that we receive. In addition, derivative arrangements may limit the benefit from changes in the prices for natural gas and oil. Since the Managing General Partner does not designate its derivatives as hedges, the Partnership does not currently qualify for use of hedge accounting treatment under SFAS No. 133, Accounting for Derivative Instruments and Certain Hedging Activities, as amended; therefore, changes in the fair value of derivatives are recorded in the Partnership’s income statements. The Partnership’s net income is subject to greater volatility than would be reported if its derivative instruments qualified for hedge accounting. For instance, if natural gas and oil prices rise significantly, it could result in significant non-cash losses each quarter which could have a material negative effect on Partnership net income.
The current trend is to increase regulation of the natural gas and oil industry. The Partnership is subject to complex federal, state, local and other laws and regulations that could adversely affect the cost, manner or feasibility of doing business. The Partnership’s operations are regulated extensively at the federal, state and local levels. Environmental and other governmental laws and regulations have increased the costs to plan, design, drill, install, operate and abandon natural gas and oil wells. Under these laws and regulations, the Partnership could also be liable for personal injuries, property damage and other damages. Failure to comply with these laws and regulations may result in the suspension or termination of the Partnership’s operations and subject the Partnership to administrative, civil and criminal penalties. Moreover, public interest in environmental protection has increased in recent years, and environmental organizations have opposed, with some success, certain drilling projects. Compliance with these regulations and possible liability resulting from these laws and regulations could result in a decline in profitability of the Partnership and a reduction in cash distributions to the Investor Partners of the Partnership. The Partnership’s activities are subject to the regulations regarding conservation practices and protection of correlative rights. These regulations affect our operations and limit the quantity of natural gas and/or oil we may produce and market. A major risk inherent in our drilling plans is the need to obtain drilling permits from state and local authorities. Because the Partnership may consider recompleting various of its Wattenberg wells if the economic environment improves, for which permits will be required, delays in obtaining regulatory approvals or drilling permits or the failure to obtain a drilling permit for a well or the receipt of a permit with unreasonable conditions or costs could have a material adverse effect on the Managing General Partner’s ability to develop the Partnership’s properties. Additionally, the natural gas and oil regulatory environment could change in ways that might substantially increase the financial and managerial costs of compliance with these laws and regulations and, consequently, adversely affect the Partnership’s ability to pay distributions to Investor Partners.
Illustrative of this trend are the regulations implemented in 2009 by the State of Colorado, which focus on the natural gas and oil industry. These multi-faceted regulations significantly enhance requirements regarding natural gas and oil permitting, environmental requirements and wildlife protection. Permitting delays and increased costs could result from these final regulations. Other potential or recently enacted laws and regulations affecting the Partnership include the following:
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·
The U.S. Environmental Protection Agency, or EPA, has recently focused on citizen concerns about the risk of water contamination and public health problems from drilling and hydraulic fracturing activities. The EPA has held public meetings around the country on this issue that have been well publicized and well attended. This renewed focus could lead to additional federal and state laws and regulations affecting the Partnership’s well recompletions, fracturing and operations. Additional laws, regulations or other changes could significantly reduce the Partnership’s future Codell formation development opportunities, increase the Partnership’s costs of operations, and reduce the Partnership’s distributable cash flows, in addition to undermining the demand for the natural gas and oil the Partnership produces.
·
Several bills in Congress, if passed, would establish a "cap and trade" system regarding greenhouse gas emissions. Companies would be assigned emission "allowances" under these bills which would decline each year. In addition, new EPA greenhouse gas monitoring and reporting regulations may affect us and the third parties that process our natural gas and oil.
·
New or increased severance taxes have been proposed in several states, which could adversely affect the existing operations in these states and the economic viability of future well completions.
·
In July 2010, the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”) was signed into law. The Dodd-Frank Act regulates derivative transactions, including the Partnership’s natural gas and oil hedging swaps. These swaps are broadly defined to include most of the Partnership’s hedging instruments. The law requires the issuance of new regulations and administrative procedures related to derivatives within one year. The effect of such future regulations on the Partnership’s business is currently uncertain. In particular, note the following:
i.
The Dodd-Frank Act may decrease the Managing General Partner’s ability to enter into hedging transactions which would expose the Partnership to additional risks related to commodity price volatility. Commodity price decreases could then have an immediate significant adverse affect on the Partnership’s revenues and impair the Partnership’s ability to have certainty with respect to a portion of the Partnership’s distributable cash flows. A reduction in cash flows may lead to decreased Investor Partner cash distributions or fewer well recompletions and therefore, decreased Partnership’s proved reserves and future production.
ii.
The Managing General Partner expects that the cost to hedge will increase as a result of fewer counterparties in the market and the pass-through of increased counterparty costs. The Partnership’s derivative counterparties may be subject to significant new capital, margin and business conduct requirements imposed as a result of the new legislation.
iii.
The Dodd-Frank Act contemplates that most swaps will be required to be cleared through a registered clearing facility and traded on a designated exchange or swap execution facility. There are some exceptions to these requirements for entities that use swaps to hedge or mitigate commercial risk. While the Partnership may ultimately be eligible for such exceptions, the scope of these exceptions currently is somewhat uncertain, pending further definition through rulemaking proceedings.
iv.
The above factors could also affect the pricing of derivatives and make it more difficult for the Managing General Partner to enter into hedging transactions on behalf of the Partnership, on favorable terms.
The Partnership further references Item 1, Business− Government Regulation and Proposed Regulation, for a detailed discussion of the laws and regulations that materially affected the Partnership activities during the periods (2007-2005) covered by this Annual Report.
Environmental hazards involved in drilling gas and oil wells may result in substantial liabilities for the Partnership, a decline in profitability of the Partnership and a reduction in cash distributions to the Investor Partners. There are numerous natural hazards involved in the drilling and operation 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 it is possible that 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 Investor Partners of the Partnership.
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The Partnership’s estimated natural gas and oil reserves are based on many assumptions that may turn out to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions may materially affect the quantities and present value of the Partnership’s reserves as well as the Partnership’s future cash flows and results of operations. Natural gas and oil reserve engineering requires subjective estimates of underground accumulations of natural gas and oil and assumptions concerning future natural gas and oil prices, production levels, and operating and development costs over the economic life of the properties. As a result, estimated quantities of proved reserves and projections of future production rates and the timing of recompletion expenditures may be inaccurate. The Managing General Partner’s Reserve Engineering Department petroleum engineers performed the Partnership’s reserve evaluation for the years 2007, 2006 and 2005. These petroleum engineers prepare the Partnership’s estimates of natural gas and oil reserves using pricing production, cost, tax and other information which the Managing General Partner provides. The reserve estimates are based on certain assumptions, including assumptions required by the SEC relating to natural gas and oil prices, production levels, and operating and development costs that may prove incorrect. Any significant variance from these assumptions to actual figures could greatly affect:
·
the estimates of reserves;
·
the economically recoverable quantities of natural gas and oil attributable to the Partnership’s properties;
·
future depreciation, depletion and amortization ("DD&A") rates and amounts;
·
impairments in the value of Partnership assets;
·
estimates of the future net cash flows; and
·
timing of the Partnership’s Wattenberg Field well recompletions.
The accuracy of proved reserves and future net revenues estimates 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 natural gas and oil prices, drilling and operating expenses, and other matters. Although the estimated proved reserves represent reserves the Partnership reasonably believes it is certain to recover, actual future production, natural gas and oil prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable natural gas and oil 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 the Partnership’s natural gas and oil reserves, which in turn could adversely affect cash flows and results of operations. In addition, estimates of proved reserves may be adjusted to reflect many factors, many of which are beyond the Partnership’s control, including production history, results of development, and prevailing natural gas and oil prices which are volatile and often fluctuate greatly.
The standardized measure of estimated proved reserves, in accordance with SFAS 69, Disclosures About Oil and Gas Producing Activities, which assumes a 10% discount factor, will not necessarily equal the current fair market value of the estimated natural gas and oil reserves. In accordance with the reserve reporting requirements of the SEC, the estimated discounted future net cash flows from proved reserves are generally 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 natural gas and oil properties will affect the timing of future net cash flows from estimated proved reserves and their related present value estimate.
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Special Risks of an Investment in the Partnership
“Material weaknesses” identified in the Partnership’s internal control over financial reporting and resulting ineffective disclosure controls and procedures could have a material adverse effect on the reliability of Partnership financial statements, its ability to file Partnership public reports on time and provide for accurate and timely Investor Partner distributions. Management of the Managing General Partner assessed the effectiveness of the Partnership’s internal control over financial reporting as of December 31, 2007 and pursuant to this assessment, identified three material weaknesses in the Partnership’s internal control over financial reporting. The existence of any material weakness means there is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the Partnership’s annual or interim financial statements will not be prevented or detected on a timely basis. The three material weaknesses relate to the Partnership’s failure to maintain effective controls over some key financial statement spreadsheets that support all significant balance sheet and income statement accounts, the failure to ensure proper accounting for derivative activities and the failure to maintain sufficient documentation to adequately assess the operating effectiveness of internal control over reporting for the transactions that are directly related to and processed by the Partnership. For a more detailed discussion of the Partnership’s material weaknesses, see Item 9A(T), Controls and Procedures, of this report. As a result of these material weaknesses, management of the Managing General Partner concluded that the Partnership’s disclosure controls and procedures were not effective as of December 31, 2007. Failure by the Partnership to maintain effective internal control over financial reporting and/or effective disclosure controls and procedures could prevent the Partnership from being able to prevent fraud and/or provide reliable financial statements and other public reports or make timely and accurate Investor Partner distributions. Such circumstances could harm the Partnership’s business and operating results, cause Investor Partners to lose confidence in the accuracy and completeness of the Partnership’s financial statements and reports, and have a material adverse effect on the Partnership’s ability to fully develop and utilize Partnership assets. These failures may also adversely affect the Partnership’s ability to file our periodic reports with the SEC on time.
The partnership units are not registered and there is no public market for the units. As a result, an individual investor partner may not be able to sell his or her units. There is and will be no public market for the units nor will a public market develop for the units. Investor Partners may not be able to sell their Partnership interests or may be able to sell them only for less than fair market value. A sale or transfer of units by an individual investor partner requires PDC’s, as Managing General Partner, prior written consent. For these and other reasons, an individual investor partner 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 individual investor partner must be able to bear the economic risk of investing in the Partnership for an indefinite period of time.
The general partners, including the Managing General Partner, are individually liable for Partnership obligations and liabilities that arose prior to conversion to limited partners that may exceed 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 was organized, general partners of a limited partnership have unlimited liability with respect to the Partnership. Therefore, the additional general partners of the Partnership were liable individually and as a group for all obligations and liabilities of creditors and claimants, whether arising out of contract or tort, in the conduct of the Partnership's operations until such time as the additional general partners converted to limited partners on October 20, 2003. Upon completion of the drilling phase of the Partnership's wells, all additional general partnership units were converted into units of limited partnership interests and thereafter became limited partners of the Partnership. 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.
Sufficient insurance coverage may not be available for the Partnership, thereby increasing the risk of loss for the General 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 general partners could be exposed to additional financial risk due to the reduced insurance coverage and due to the fact that they would continue to be individually liable for obligations and liabilities of the Partnership that arose prior to conversion to limited partners, which occurred on October 20, 2003. 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, or should the Partnership suffer a significant uninsured casualty loss, the amount of cash distributions to the investors will be reduced.
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The Managing General Partner may not have sufficient funds to repurchase limited partnership units. As a result of PDC, the Managing General Partner, being a general partner in several partnerships and a capital contributing partner to a joint venture, as well as an actively operating corporation, the Partnership’s net worth is at risk of reduction if PDC suffers a significant financial loss. Because the Investor Partners may request the Managing General Partner to repurchase the units in the Partnership, subject to certain conditions and restrictions, a significant adverse financial reversal for PDC could result in the Managing General Partner’s inability to pay for Partnership obligations or the repurchase of investor units. As a result, an individual investor partner may not be able to liquidate his or her investment in the Partnership.
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. The partnership agreement provides that PDC as the Managing General Partner will indemnify all additional general partners for the amounts of their obligations and losses which exceed insurance proceeds and the Partnership's assets. 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.
Through their involvement in the Partnership and other non-partnership activities, the Managing General Partner and its affiliates have interests which conflict with those of the Investor Partners; actions taken by the Managing General Partner in furtherance of its own interests could result in the Partnership being less profitable and a reduction in cash distributions to the Investor Partners. PDC's continued active participation in natural gas and oil activities for its own account and on behalf of other partnerships 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. The following is an itemization of the material conflicts of interest of PDC as Managing General Partner of the Partnership and of PDC’s affiliates:
·
PDC has no plans through 2010 or beyond to sponsor additional drilling programs; however joint ventures arrangements could conflict with the interests of the Partnership. PDC and affiliates have the right to organize and manage natural gas and oil joint venture arrangements, whose business purpose is generally similar to the Partnership, and to conduct production operations now and in the future on its own behalf or for joint venture partners. This situation could lead to a conflict between the position of PDC as Managing General Partner of the Partnership and the position of PDC or its affiliates as a capital contributing partner to joint venture natural gas and oil properties development entity.
·
PDC has a fiduciary duty as Managing General Partner to the Partnership. PDC acts as managing general partner currently for 33 limited partnerships, including this Partnership, and is accountable to all of the partnerships as a fiduciary. PDC therefore has a duty to exercise good faith and deal fairly with the investor partners of each partnership. PDC’s actions taken on behalf of one or more of these partnerships could be disadvantageous to the Partnership and could fall short of the full exercise of its fiduciary duty to the Partnership.
·
There are and will continue to be transactions between PDC, its affiliates and the Partnership. PDC, as operator of the Partnership, has and will continue to provide drilling, completion and operation services to the Partnership’s wells. Although the prices that PDC has charged, and will charge, to the Partnership for the supplies and services provided by PDC and affiliates to the Partnership will be competitive with the prices charged by unaffiliated persons for the same supplies and services, PDC will benefit financially from this relationship.
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·
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 being less profitable. In that event, Investor Partners could anticipate a reduction of cash distributions.
·
PDC, the managing general partner of various public limited partnerships, has disclosed its intention to pursue the acquisition, within the next three years beginning in the fall of 2010, of the remaining third-party Investor Partner interests in the limited partnerships which PDC has sponsored, which includes the Partnership. Any such transaction, if proposed, will also be subject to PDC having sufficient available capital. Should a purchase offer from PDC be proposed, approved by a majority of the respective partnership’s unaffiliated limited partners, and consummated, the purchase transaction would result in a liquidating cash distribution to all partners and termination of the existence of that partnership. There is no assurance that any such acquisition of any or all of PDC’s sponsored drilling program partnerships will occur. For additional information regarding PDC’s disclosed partnership acquisition intensions, see Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations−PDC Sponsored Drilling Program Acquisition Plan.
The Partnership and other partnerships sponsored by PDC, as Managing General Partner, may compete with each other for well recompletion opportunities, equipment, contractors, and personnel; as a result, the Partnership may find it more difficult to operate effectively and profitably. PDC operates and manages other partnerships formed for substantially the same purposes as those of the Partnership. PDC will operate and manage these partnerships for the foreseeable future. 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 in need of equipment, contractors and PDC personnel), which may make it more difficult and more costly to obtain equipment and 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 corporate interests as well as the affairs of the 33 limited partnerships PDC has organized in previous programs, the Partnership will not receive PDC's full attention and efforts at all times.
The Managing General Partner, with respect to its own corporate interests, the Partnership and various other limited partnerships sponsored by the Managing General Partner, have been delinquent in filing periodic reports with the SEC. Consequently, Investor Partners are unable to review the delinquent partnerships’ respective financial statements as a source of information for evaluating their investment in the Partnership. PDC, as an actively operating corporation, and various limited partnerships which PDC has sponsored and for which PDC serves as the Managing General Partner are subject to reporting requirements of the Exchange Act and are obligated to file annual and quarterly reports with the SEC in accordance with the rules of the SEC. In the course of preparing corporate financial statements for the quarter ended June 30, 2005, PDC identified accounting errors in its prior period financial statements. As a result, on October 17, 2005, PDC’s Board of Directors, Audit Committee and management concluded that PDC’s previously issued financial statements could not be relied upon and would be restated. PDC, as Managing General Partner, made similar determinations regarding the financial statements of certain of the limited partnerships which are subject to the Exchange Act reporting obligations. Since June 2007, PDC has become compliant with its corporate Exchange Act filing and reporting obligations. Additionally, Rockies Region 2007 Limited Partnership, Rockies Region 2006 Limited Partnership, Rockies Region Private Limited Partnership, PDC 2005-A Limited Partnership, PDC 2005-B Limited Partnership, PDC 2004-A Limited Partnership, PDC 2004-B Limited Partnership, PDC 2004-C Limited Partnership and PDC 2004-D Limited Partnership have completed all required SEC filings through June 30, 2010. PDC 2003-A Limited Partnership, PDC 2003-B Limited Partnership, PDC 2003-C Limited Partnership and PDC 2003-D Limited Partnership have completed all required SEC filings through December 31, 2009, but are delinquent on all subsequent quarterly filing requirements. PDC 2002-D Limited Partnership has completed and PDC 2002-C Limited Partnership (with this filing) will have completed all required SEC filings through December 31, 2007, but is delinquent on all subsequent quarterly and annual filing requirements. All remaining limited partnerships sponsored by PDC which are subject to the Exchange Act have been, and continue to be, delinquent in filing their respective periodic reports in accordance with the requirements of the Exchange Act. Until these partnerships file their delinquent periodic reports, investors will be unable to review the financial statements of the various limited partnerships as an additional source of information they can use in their evaluation of their investment in the Partnership. Currently the Managing General Partner has in place a compliance effort addressing the delinquent reports of the various limited partnerships. However, due to the amount of effort, time and financial resources required to bring the limited partnerships into compliance with Exchange Act periodic reporting requirements, the Partnership and the various limited partnerships may be unable to bring their delinquent reports current and may be unable in the future to file their required periodic reports with the Securities and Exchange Commission in a timely manner.
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Item 1B.
Item 1B.
Unresolved Staff Comments
None
Item 2.
Item 2.
Properties
The Partnership’s properties (the “Properties”) consist of working interests in gas and oil wells for the wells drilled by the Partnership. The acreage associated with the spacing units is designated by state rules and regulations in conjunction with local practice. See the section titled Item 1, Business Drilling Activities and Plan of Operations for additional information on the Partnership’s properties.
The Partnership commenced drilling activities immediately following funding on November 12, 2002. Drilling operations were completed in August 2003 when the last of the Partnership’s 14 productive development wells were connected to pipelines. The Partnership’s 14 gross wells represent 12.7 net wells, or the number of gross wells multiplied by the working interest in the wells owned by the Partnership. All of the drilled developmental well prospects are located in Colorado and all 14 wells drilled were completed and producing at December 31 of 2007, 2006 and 2005. Productive wells consist of producing wells and wells capable of producing natural gas and oil in commercial quantities. The 14 wells are the only wells to be drilled by the Partnership since all of the funds raised in the Partnership offering have been expended. The details of these drilling areas are further outlined below.
The Wattenberg Field, located north and east of Denver, Colorado, is in the Denver-Julesburg (“DJ”) Basin. The typical well production profile has an initial high production rate and relatively rapid decline, followed by years of relatively shallow decline. Natural gas is the primary hydrocarbon produced; however, many wells will also produce oil. The purchase price for the natural gas may include revenue from the recovery of propane and butane in the gas stream, as well as a premium for the typical high-energy content of the natural gas. Wells in the area may include as many as four productive formations. From shallowest to deepest, these producing formations include the Sussex, the Niobrara, the Codell and the J Sand. The primary producing zone in most wells is the Codell sand. The Partnership owns 12 wells located in this field.
The Grand Valley Field is in the Piceance Basin, located near the western border of Colorado. Wells in the Piceance Basin generally produce natural gas along with small quantities of oil. The producing interval consists of a total of 150 to 300 feet of productive sandstone divided in 10 to 15 different zones. The production zones are separated by layers of nonproductive shale resulting in a total interval of 2,000 to 4,000 feet with alternating producing and non-producing zones. The natural gas reserves and production are divided into these numerous smaller zones. The Partnership owns 2 wells located in this field.
Production
Production of natural gas and oil commenced during the first quarter of 2003, peaked at 435,000 Mcfe during the quarter ended September 30, 2003 and has decreased as anticipated based on the projected production decline curves. A complete disclosure of quarterly production volumes, prices and sales is presented in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations in this report.
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Natural Gas and Oil Reserves
The Partnership’s gas and oil reserves are located in the United States. The Managing General Partner’s Reserve Engineering Department petroleum engineers performed the Partnership’s reserve evaluation for the years 2007, 2006 and 2005. The engineers’ estimates were made using available geological and reservoir data as well as production performance data. The estimates were prepared with respect to reserve categorization, using the definitions using the definitions in effect during the years 2007, 2006 and 2005 for proved reserves set forth in SEC Regulation S-X, Rule 4-10(a) as interpreted by the SEC’s staff interpretations and guidance, since the SEC’s Modernization of Oil and Gas Reporting final rule prohibits retroactive application of the new natural gas and oil industry disclosure standards. These new SEC natural gas and oil industry disclosure rules will be implemented by the Partnership in its Annual Report on Form 10-K as of December 31, 2009. See Supplemental Natural Gas and Oil Information - Unaudited, Net Proved Natural Gas and Oil Reserves for additional information regarding the Partnership’s reserves. For more information regarding the SEC’s Modernization of Oil and Gas Reporting and the major provisions likely to impact the both the determination of and disclosures for the Partnership’s natural gas and oil reserves when adopted as of December 31, 2009, see Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations−Recent Accounting Standards.
Title to Properties
The Partnership holds record title in its name to the working interest in each well. PDC provided an assignment of working interest for the well bore prior to the spudding of the well and effective the date of the spudding of the well, to the Partnership in accordance with the Drilling and Operation Agreement. Upon completion of the drilling of all of the Partnership wells, these assignments were recorded in the applicable county. Investor Partners rely on PDC to use its best judgment to obtain appropriate title to these working interests. Provisions of the Agreement generally relieve PDC from errors in judgment with respect to the waiver of title defects. PDC takes those steps it deems necessary to assure that title to the working interests is acceptable for purposes of the Partnership.
The Partnership's leases are direct interests in producing acreage. The Partnership believes it holds good and defensible title to its developed properties, in accordance with standards generally accepted in the natural gas and oil industry. As is customary in the industry, a perfunctory title examination was conducted by PDC at the time the undeveloped properties were acquired by PDC. Prior to the commencement of drilling operations, a title examination is conducted and curative work is performed with respect to discovered defects which are deemed to be significant. Title examinations have been performed with respect to substantially all of the Partnership's producing properties.
The Partnership’s properties are subject to royalty, overriding royalty and other outstanding interests customary to the industry. The properties may also be subject to additional burdens, liens or encumbrances customary to the industry. The Managing General Partner is not aware of any additional burdens, liens or encumbrances, if any, which may materially interfere with the commercial use of the properties.
Item 3.
Item 3.
Legal Proceedings
The Registrant is not currently subject to any material pending legal proceedings.
See Note 8, Commitments and Contingencies to the accompanying financial statements for additional information related to litigation.
Item 4.
Item 4.
[Removed and Reserved]
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PART II
Item 5.
Item 5.
Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
At June 30, 2010, the Partnership had 479 Investor Partners holding 471.9 units and one Managing General Partner. The investments held by the Investor Partners are in the form of limited partnership interests. Investor Partners' interests are transferable; however, no assignee of units in the Partnership can become a substituted partner without the written consent of the transferor and the Managing General Partner. As of June 30, 2010, the Managing General Partner has repurchased 13.03 units of Partnership interests from Investor Partners.
Market. There is no public market for the Partnership units nor will a public market develop for these units in the future. Investor Partners may not be able to sell their Partnership interests or may only be able to sell their Partnership interest for less than fair market value. No transfer of a unit may be made unless the transferee satisfies relevant suitability requirements, as imposed by federal and state law or the Partnership Agreement. The Partnership may require that the transferor provide an opinion of legal counsel stating that the transfer complies with applicable securities laws. A sale or transfer of units by an individual investor partner requires PDC’s, as Managing General Partner, prior written consent. For these and other reasons, an individual investor partner must anticipate that he or she may have to hold his or her partnership interests indefinitely and may not be able to liquidate his or her investment in the Partnership. Consequently, an individual investor partner must be able to bear the economic risk of investing in the Partnership for an indefinite period of time.
Cash Distribution Policy. PDC plans to make distributions of Partnership cash on a monthly basis, but no less often than quarterly, subject to funds being available for distribution. PDC will make cash distributions of 80% of distributable cash to the Investor Partners, including any Investor Partner units purchased by the Managing General Partner, and 20% of distributable cash to the Managing General Partner, throughout the term of the Partnership. Cash is distributed to the Investor Partners and PDC currently as a return of capital in the same proportion as their proportional interest in the net income of the Partnership.
PDC cannot presently predict amounts of future cash distributions, if any, from the Partnership. However, PDC expressly conditions any and all future cash distributions upon the Partnership having sufficient cash available for distribution. Sufficient cash available for distribution is defined generally as cash generated by the Partnership in excess of the amount the Managing General Partner determines is necessary or appropriate to provide for the conduct of the Partnership's business, to comply with applicable law, to comply with any other agreements or to provide for future distributions to unit holders. In this regard, PDC reviews the accounts of the Partnership at least quarterly for the purpose of determining the sufficiency of distributable cash available for distribution. Amounts will be paid to Investor Partners only after payment of fees and expenses to the Managing General Partner and its affiliates and only if there is sufficient cash available.
The ability of the Partnership to make or sustain cash distributions depends upon numerous factors. PDC can give no assurance that any level of cash distributions to the Investor Partners of the Partnership will be attained, that cash distributions will equal or approximate cash distributions made to investor partners of prior drilling programs sponsored by PDC, or that any level of cash distributions can be maintained. Fully developing all of the Partnership’s properties would require substantial capital expenditures. Because of the restrictions set forth in the Agreement on borrowing money and making assessments on limited partnership units, the Partnership would generally be unable to fund such capital expenditures without retaining all or a substantial portion of the Partnership’s cash flow.
The commencement of Wattenberg Field Codell formation recompletion activities would reduce or eliminate Partnership distributions to investors while the work is being conducted and paid for. Depending upon the level of withholding and the results of operations, it is possible that investors could have taxable income from the Partnership without any corresponding distributions in the future. If PDC were to be successful in a potential future acquisition effort of this Partnership, liquidation of the Partnership and a final payout would result in cessation of all future cash payments. The exchange by an investor partner of limited partnership units for cash pursuant to any merger would be a taxable transaction for U.S. federal income tax purposes. The effects of a potential acquisition may be different for each investor partner. For more information concerning the Partnership’s Wattenberg Field recompletion activities see Item 1, Business-Future Development Opportunities and additional information regarding PDC’s disclosed partnership acquisition intensions, see Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations−PDC Sponsored Drilling Program Acquisition Plan.
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Investor Partners are urged to consult a tax advisor to determine all of the relevant federal, state and local tax consequences of the Wattenberg Field Codell formation recompletion activities and any potential merger. The above discussion is not intended as a substitute for careful tax planning, and third-party Investor Partners should depend upon the advice of their own tax advisor concerning the effects of the Wattenberg Field recompletions and any potential merger.
The following table presents cash distributions made to the Partnership’s investors for the periods described:
The volume and rate of production from producing wells naturally declines with the passage of time and is generally not subject to the control of management. The cash flow generated by the Partnership's activities and the amounts available for distribution to the Partnership's Investor Partners will, therefore, decline in the absence of significant increases in the prices that the Partnership receives for its natural gas and oil production, or significant increases in the production of natural gas and oil from the successful additional development of these properties, if any. The funds necessary for any additional development would be withheld from the Partnership's distributable cash flows. As a result, there may be a decrease in the funds available for distribution, and the distributions to the Investor Partners would then decrease. For more information regarding recompletion of the Partnership’s Wattenberg Field wells see Item 1, Business−Business Strategy, Future Development Opportunities on page 3. For more information concerning the Partnership’s cash flows from operations see Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations−Liquidity and Capital Resources.
Unit Repurchase Program. Investor Partners may request that the Managing General Partner repurchase limited partnership 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. In any calendar year, the Managing General Partner is conditionally obligated to purchase Investor Partner units aggregating up to 10% of the initial subscriptions if requested by an individual investor partner, subject to PDC’s financial ability to do so and upon receipt of opinions of counsel that the repurchase will not cause the Partnership to be treated as a “publically traded partnership” or result in the termination of the Partnership for federal income tax purposes. If accepted, repurchase requests are fulfilled by the Managing General Partner on a first-come, first-serve basis. In addition to the above repurchase program, individual investor partners periodically offered and PDC repurchased units on a negotiated basis before the third anniversary of the date of the first cash distribution.
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The following table presents information about the Managing General Partner’s limited partner unit repurchases under the unit repurchase program during the periods described below:
In addition to the above repurchase program, individual investor partners periodically offer and PDC repurchases units on a negotiated basis before the third anniversary of the date of the first cash distribution. The following table presents information about the Managing General Partner’s negotiated-basis limited partner unit repurchases during the periods described below:
Item 6.
Item 6.
Selected Financial Data
Not applicable
Item 7.
Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis, as well as other sections in this Form 10-K, should be read in conjunction with the Partnership’s accompanying financial statements and related notes to the financial statements included in this report. Further, the Partnership encourages the reader to revisit the Special Note Regarding Forward-Looking Statements on page 1 of the report.
PDC Sponsored Drilling Program Acquisition Plan
PDC, the managing general partner of various public limited partnerships, has disclosed its intention to pursue the acquisition, within the next three years beginning in the fall of 2010, of the remaining third-party Investor Partner interests in the limited partnerships which PDC has sponsored, including PDC 2002-C Limited Partnership. (For additional information regarding PDC’s intention to pursue acquisition of PDC sponsored partnerships, refer to Regulation FD disclosure included in Items 2.02 and/or 7.01 of PDC’s Form 8-Ks dated March 4, 2010, June 9, 2010 and July 15, 2010, which information shall not, by reason of this reference, be deemed to be incorporated by reference in, or otherwise be deemed to be part of, this report.) Under the Acquisition Plan, any offer will be subject to the terms and conditions of a to be proposed merger agreement wherein the Partnership will merge into PDC. The transaction will also be subject to PDC having sufficient available capital and the approval by a majority of the Investor Partners’ interests, excluding partnership interest owned by PDC, of each respective limited partnership. Should a purchase offer from PDC be proposed, approved by a majority of the Partnerships’ unaffiliated limited partners, and consummated, the purchase transaction would result in a liquidating cash distribution to all partners and termination of the existence of the Partnership. There is no assurance that any such acquisition will occur.
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Partnership Overview
The Partnership was funded on November 12, 2002 with initial contributions of $9.4 million from the Investor Partners and a cash contribution of $2.1 million from the Managing General Partner. After payment of syndication costs of $1.0 million and a one-time management fee to PDC of $0.2 million, the Partnership had available cash of $10.3 million to commence Partnership natural gas and oil well drilling activities.
The Partnership began exploration and development activities immediately after funding. In the fourth quarter of 2002, PDC commenced drilling on behalf of the Partnership. As of December 31, 2007, a total of 14 wells (12.7 net) have been drilled and were in production in Colorado. These 14 wells are the only wells the Partnership has drilled because all of the capital contributions have been utilized. The completed wells produce primarily natural gas, with some associated crude oil. Sales of produced natural gas and oil commenced during the first quarter of 2003 as wells were connected to pipelines and peaked during the third quarter of 2003 when all completed wells were connected to pipelines. As expected for wells in this area, the Partnership has experienced a steady decline in quarterly production.
Future Development Opportunities
The Partnership’s wells will produce until they are depleted or until they are uneconomical to produce; however, Partnership well recompletions in the Codell formation of Wattenberg Field wells may provide for additional reserve development and production. The well recompletions are generally planned to occur five to ten years after initial well drilling so that well resources are optimally recovered and would generally be expected to occur within a favorable general economic environment and commodity price outlook. The Managing General Partner expects to commence recompletion activities during 2011 or as soon as economically feasible, thereafter. In October 2010 the Managing General Partner began to withhold funds from distributable cash flows for some of the Partnerships, in which they are the Managing General Partner, resulting from current production. The funds retained that are necessary for the Partnership to pay for recompletion costs will materially reduce, up to 100%, distributable cash flows for a period of time not to exceed five years. See Item 1, Business−Plan of Operations, Future Development Opportunities for more information about the Codell recompletion development activities. As of October 2010 no funds have been withheld from the Partnership distributions.
Implementation of the Wattenberg Field Codell formation recompletions would reduce or eliminate Partnership distributions to investors while the work is being conducted and paid for. Depending upon the level of withholding and the results of operations, it is possible that Investor Partners could have taxable income from the Partnership without any corresponding distributions in the future. Investor Partners are urged to consult a tax advisor to determine all of the relevant federal, state and local tax consequences of the Wattenberg Field recompletion activities. The above discussion is not intended as a substitute for careful tax planning, and third-party Investor Partners should depend upon the advice of their own tax advisors concerning the effects of the Wattenberg Field recompletion activities.
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Results of Operations
The following table sets forth selected information regarding the Partnership’s results of operations, including production volumes, natural gas and oil sales, average sales prices received, average sales price including realized derivative gains and losses, production and operating costs, depreciation, depletion and amortization costs, other operating income and expenses for the years ended December 31, 2007, 2006 and 2005.
(1)
Production is determined by multiplying the gross production volume of properties in which the Partnership has an interest by the average percentage of the leasehold or other property interest the Partnership owns.
(2)
A ratio of energy content of natural gas and oil (six Mcf of natural gas equals one Bbl of oil) was used to obtain a conversion factor to convert oil production into equivalent Mcf of natural gas.
(3)
Natural gas and oil production costs represent natural gas and oil operating expenses which include production taxes.
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Definitions used throughout Management’s Discussion and Analysis of Financial Condition and Results of Operations.
·
Bbl - One barrel or 42 U.S. gallons liquid volume
·
MBbl - One thousand barrels
·
Mcf - One thousand cubic feet
·
MMcf - One million 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
·
MMcfe - One million cubic feet of natural gas equivalents
·
MMbtu - One million British Thermal Units
Natural Gas and Oil Sales
The table below shows sales and production information for each quarter for the years ended December 31, 2007, 2006 and 2005. Natural gas and oil sales exclude the impact of commodity-based derivatives, which are reflected in the line “Commodity price risk management gain (loss), net” in the statements of operations. (In thousands except for per Mcf, per Bbl and per Mcfe amounts and percentage changes)
*As restated
The 39% decrease in natural gas and oil sales in 2007 as compared to 2006 was due to a 31% decrease in production volumes along with a 12% decrease in the average sales price per Mcfe. Decreased volumes and decreased commodity prices contributed $.5 million and $0.1 million, respectively, to the total $0.6 million decrease in 2007 as compared to 2006. During the second quarter of 2007 increased line pressure and one well being shut in resulted in lower production volumes.
The 14% decrease in natural gas and oil sales in 2006 as compared to 2005 was due to a 11% decrease in production volumes along with a 4% decrease in the average sales price per Mcfe. Decreased volumes and decreased commodity prices contributed $0.2 million and $0.1 million, respectively, to the total $0.3 million decrease in 2006 as compared to 2005.
Generally, the year over year changes in production volumes are consistent with the historically declining production curves for wells drilled in the Wattenberg and Grand Valley fields. The Partnership expects to experience continued declines in both natural gas and oil production volumes over the well’s life cycles until such time that the Partnership’s Wattenberg wells may be successfully recompleted. Subsequent to successful recompletion, production will once again begin to decline.
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Natural Gas and Oil Pricing
Financial results depend upon many factors, particularly the prices of natural gas and oil and the Managing General Partner’s ability to market the Partnership’s production effectively. Natural gas and oil prices have been among the most volatile of all commodity prices. These price variations have a material impact on Partnership financial results. Natural gas and oil prices also vary by region and locality, especially in the Rocky Mountain Region, depending upon the distance to markets, and the supply and demand relationships. This can be especially true in the Rocky Mountain Region in which all of the Partnership’s wells are located. The combination of increased drilling activity and the lack of substantial local market demand can result in a local market oversupply situation from time to time. The Managing General Partner believes such a situation existed in the Rocky Mountain Region during 2007, with production exceeding the local market demand and pipeline transportation capacity to non-local markets. Management also believes these factors resulted, beginning in the second quarter of 2007 and continuing into the fourth quarter of 2007, in a decrease in the price of Rocky Mountain natural gas, as measured by the Colorado Interstate Gas, or CIG, Index (per MMbtu) compared to the New York Mercantile Exchange, or NYMEX, Index price (per MMbtu).
Commodity Price Risk Management Gain (Loss), Net
The Managing General Partner is authorized to utilize natural gas and oil commodity derivative instruments to manage price risk for PDC as well as sponsored drilling partnerships. The Managing General Partner sets these instruments for itself, the Partnership and other sponsored partnerships jointly by area of operation. Prior to September 30, 2008, as production volumes changed, the allocation of derivative positions between PDC’s corporate interests and each of the sponsored drilling partnerships changed on a pro-rata basis. Effective September 30, 2008, PDC changed the allocations procedure whereby the allocation of derivative positions between PDC and each partnership was set at a fixed quantity. Existing positions are allocated based on fixed quantities for each position and new positions will have specific designations relative to the applicable partnership. Realized and unrealized gains and losses resulting from derivative positions are reported on the statement of operations as “Commodity price risk management gain (loss), net.” The net gains/losses are comprised of the change in fair value of derivative positions related to the Partnership’s production and underlying derivative contracts entered into by the Managing General Partner on behalf of the Partnership.
In periods of rising prices, the Partnership will generally record losses on its derivative positions as fair values exceed contract prices determining the Partnership’s natural gas and oil sales. Conversely, in periods of decreasing prices, the Partnership will generally recognize gains on its derivative positions. Since December 31, 2007, through the filing of this report, the Partnership continues to experience volatility in natural gas and oil prices resulting in fluctuations in realized and unrealized derivative positions.
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The following table presents the realized and unrealized gains and losses recorded for each of the quarterly and annual periods identified:
In 2007, the Partnership recorded an approximately fifty thousand commodity price risk management, net loss for the year, primarily the result of recording an approximately $0.1 million unrealized loss, that was partially offset by an approximately fifty thousand realized gain. The unrealized losses recognized for the quarters ended March 31 and December 31, 2007, were due to increasing natural gas prices. The significant decline in the CIG market during the fall of 2007 resulted in the realized gain in 2007. When forward prices for natural gas and oil prices increase as they did in the first and fourth quarters of 2007, the Partnership’s derivative portfolio, which includes floors, ceilings and swaps, decreases in value, resulting in unrealized loss positions. Due to the volatility of commodity prices during the period of this Annual Report (2007-2005), large quarter to quarter fluctuations in “Commodity price risk management gain (loss), net,” took place.
In 2006, the Partnership recorded a $0.1 million commodity price risk management, net gain for the year, as a result of the unrealized gain of $0.1 million recognized during the year due to falling natural gas prices. This trend in natural gas pricing was especially evident during the quarter ended March 31, 2006.
In 2005, the Partnership recorded a $0.1 million commodity price risk management, net loss for the year, primarily the result of recording realized losses. Disruptions in Gulf of Mexico production caused by Hurricanes Katrina and Rita accentuated the overall upward trend in natural gas commodity pricing that existed throughout 2005 which resulted in the Partnership’s quarterly realized and unrealized losses. Unseasonably moderate temperatures during the post and early-heating seasons provided the temporary natural gas commodity reductions that resulted in the unrealized gains recorded during the quarters ended June 30 and December 31, 2005.
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Production and Operating Costs
Production and Operating Costs include production taxes and transportation costs which vary with revenues and production, well operating costs charged on a per well basis and other direct costs incurred in the production process.
*As restated
Typically, as production is expected to continue to decline, production costs per unit can be expected to increase in the future until such time as the Partnership successfully recompletes the Wattenberg Field wells.
Generally, natural gas and oil production costs vary with changes in total natural gas and oil sales and production volumes. Production taxes are estimates by the Managing General Partner based on tax rates determined using published information. These estimates are subject to revision based on actual amounts determined during future filings by the Managing General Partner with the taxing authorities. Production taxes vary directly with total natural gas and oil sales. Transportation costs vary directly with production volumes. Fixed monthly well operating costs increase on a per unit basis as production decreases per the historical decline curve. In addition, general oil field services and all other costs vary and can fluctuate based on services required. These costs include water hauling and disposal, equipment repairs and maintenance, snow removal and service rig workovers.
Production and operating costs increased on a per unit basis in 2006 and 2007 compared to 2005 due primarily to increased costs in the Grand Valley Field related to the Partnership’s utilization of new pipeline capacity and improved well site access, as well incremental lease operating expenditures for fluid removal and well rework at Partnership wells in this field.
Direct Costs - General and Administrative
Direct costs - general and administrative consist primarily of professional fees for financial statement audits, income tax return preparation and legal matters. Such costs were relatively low in 2005 and 2006 and increased in 2007 as a result of accounting and audit fees of approximately $51,000 associated with the preparation of the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2005. Additionally, the Partnership experienced increases in general costs in 2007 due to the royalty litigation settlement of approximately $68,000. For additional information regarding the settlement, see Note 8, Commitments and Contingencies to the accompanying financial statement included in this report.
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Depreciation, Depletion and Amortization
The Partnership recorded depreciation, depletion and amortization ("DD&A") expense in 2007, 2006 and 2005 as follows:
*As restated
Depreciation, depletion and amortization (DD&A) expense results solely from the depreciation, depletion and amortization of well equipment and lease costs. The Partnership’s calculation of DD&A expense is primarily based upon year-end proved developed producing natural gas and oil reserve estimates and associated production volumes. For 2007, 2006 and 2005 the Partnership’s natural gas and oil reserve quantities were determined by valuing in-ground natural gas and oil resources, at the price of natural gas and oil as of December 31, 2007, 2006 and 2005, respectively. Typically as valuation prices increase, the estimated volumes of natural gas and oil reserves may increase, resulting in a decrease in the rate of DD&A for each Mcfe produced. If valuation prices decrease the estimated volumes of natural gas and oil reserves may also decrease, resulting in an increase in the DD&A rate for each Mcfe produced.
The variances in the per Mcfe rates for quarterly periods ending March 31, June 30 and September 30 and annual periods during 2007 and 2006 compared to their respective prior-year-period, are primarily the result of the changing production mix between the Partnership’s Wattenberg and Grand Valley Fields, which have significantly different DD&A rates. These annual declines in Partnership year-to-year well production reduced the Partnership’s annual DD&A expense by approximately $0.3 million and fifty thousand during 2007 and 2006, respectively, compared to the previous year.
The decrease in the per Mcfe rate for the quarter ended December 31, 2007 is primarily the result of the effect of upward reserve revisions at December 31, 2007, compared to the previous year, in which proved developed producing reserves were revised downward.
See Supplemental Natural Gas and Oil Information - Unaudited, Net Proved Natural Gas and Oil Reserves for additional information regarding the Partnership’s reserves reported as of December 31, 2007, 2006 and 2005. The Partnership’s natural gas and oil reserve estimates were prepared with respect to reserve categorization, using the SEC’s definitions in effect during the years 2007, 2006, and 2005 since the SEC’s Modernization of Oil and Gas Reporting final rule prohibits retroactive application of the new natural gas and oil industry disclosure standards. For more information regarding the SEC’s Modernization of Oil and Gas Reporting, see Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations−Recent Accounting Standards.
Interest Income
Interest income increased from 2005 to 2006 due to substantially higher interest rates applied to the slightly higher level of undistributed revenues held by the Managing General Partner during the year ended December 31, 2006, along with additional interest the Managing General Partner will distribute to Investor Partners on production tax obligation over-withholding during the years 2003 through 2006. Interest income increased from 2006 to 2007 due to the slightly higher interest rates on the production tax obligation over-withholding amounts which offset the effect of significantly lower level of undistributed revenues held by the Managing General Partner during the year ended December 31, 2007. For more information on the production tax obligation over-withholding by the Managing General Partner, see Note 9, Restatements.
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Liquidity and Capital Resources
The Partnership completed its drilling activities as of October 2003, thus the Partnership’s operations are expected to be conducted with available funds and revenues generated from natural gas and oil production activities. Natural gas and oil production from the Partnership’s existing properties, which commenced in first quarter 2003 and peaked during the third quarter 2003, declined significantly through 2005. Production has declined gradually during subsequent years and is expected to continue a gradual decline in the rate of production over the remaining lives of the wells.
Partnership well recompletions in the Codell formation of Wattenberg Field wells may provide for additional reserve development and production. These well recompletions generally occur five to ten years after initial well drilling so that well resources are optimally recovered and would be expected to occur within a favorable general economic environment and commodity price outlook. As this optimal time approaches, the Managing General Partner will evaluate the timing of when the Partnership should initiate recompletion activities on those wells based on a favorable economic environment and commodity price structure in order to maximize returns. Since borrowing is not permitted by the Limited Partnership Agreement, well recompletion activities will be funded through the retention of revenues and reduction of Partner cash distributions. Engineering data and economic conditions supported the economic feasibility of future recompletions, however, no assurances can be given that future recompletion activities will be feasible or economic. See Item 1, Business−Plan of Operations, Future Development Opportunities and Partnership Overview−Future Development Opportunities in this Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations for more information about the Wattenberg Field Codell formation recompletion activities.
Information related to the natural gas and oil reserves of the Partnership’s wells is discussed in detail in Supplemental Oil & Gas Information - Unaudited, Net Proved Natural Gas and Oil Reserves.
Changes in market prices for natural gas and oil, the Partnership’s production levels, impact of realized gains and losses on the Partnership’s natural gas and oil derivative instruments and changes in costs are the principal determinants of the level of the Partnership cash flow from operations. Natural gas and oil sales for the twelve months ended December 31, 2007 and 2006 were approximately 39% and 14% lower, respectively, than the same period in the prior year, resulting from a 12% and 4% decrease, respectively, in average natural gas and oil prices and a 31% and 11% decrease, respectively, in natural gas and oil production.
Changes in market prices for natural gas and oil directly affect the level of cash flow from operations, as noted in Item 1A, Risk Factors. While a decline in natural gas and oil prices would affect the amount of cash from operations that could be generated, the Partnership has natural gas and oil derivative positions in place which reduce the impact of price changes on cash provided by operations for a substantial portion of the expected production through 2013.
The value of the Partnership’s current derivatives positions may change based on changes in natural gas and oil futures markets, the investors’ view of underlying natural gas and oil supply and demand trends and changes in volumes produced. Partnership natural gas and oil derivatives as of December 31, 2007 are detailed in Note 4, Derivative Financial Instruments to the accompanying financial statements included in this Annual Report.
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Working Capital
The following table sets forth the working capital position of the Partnership:
Cash Flows from Financing and Investing Activities
The Partnership was funded in December 2002 with initial contributions of $9.4 million from Investor Partners and a cash contribution of $2.1 million from PDC, the Managing General Partner. After payment of syndication cost of $1.0 million and a one-time management fee to the Managing General Partner of $0.2 million, the Partnership had available cash of $10.3 million to commence Partnership activities. In November 2002, $10.3 million was paid to the Managing General Partner for reimbursement for capital expenditures relating to natural gas and oil properties. The expenditures were paid in accordance with the D&O Agreement as more fully described in Item 1, Business - Drilling Activities. There were no additional investing activities in 2007 or 2006 and investing activities for 2005 were immaterial.
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The Partnership initiated monthly cash distributions to investors in June 2003 and has distributed $7.4 million of its operating cash flows from its November 12, 2002 date of inception through December 31, 2007. The following table sets forth the quarterly cash distributions to the Managing General Partner and the Investor Partners during the years 2007, 2006 and 2005.
Cash Flows from Operating Activities
Net cash provided by operating activities was $0.8 million in 2007 compared to $1.7 million in 2006, a decrease of $0.9 million. Variances between the two periods in cash provided by operating activities were due primarily to a decrease in natural gas and oil sales receipts of approximately $0.8 million.
Net cash provided by operating activities was $1.7 million in 2006 compared to $1.3 million in 2005, an increase of $0.4 million. Variances between the two periods in cash provided by operating activities were due primarily to the following:
·
A decrease in natural gas and oil sales receipts of $0.1 million; offset by
·
An increase in accounts receivable of $0.4 million; an increase in due from Managing General Partner-other, net of $0.3 million.
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The following table presents operating cash flows for the quarters ended March 31, June 30, September 30 and December 31 for the years indicated:
Contractual Obligations and Contingent Commitments
The table below sets forth the Partnership's contractual obligations and contingent commitments as of December 31, 2007, 2006 and 2005.
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Critical Accounting Policies and Estimates
The Managing General Partner has identified the following accounting policies as critical to the understanding of the results of the operations of the Partnership. The following is not a comprehensive list of all of the Partnership’s 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, and as a result, are subject to an inherent degree of uncertainty. 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 historical experience, 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 in the accompanying financial statements. The Partnership's critical accounting policies and estimates are as follows:
Natural Gas and Oil Properties
The Partnership accounts for its natural gas and oil 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 natural gas and oil reserves. Property acquisition costs are depreciated or depleted on the unit-of-production method based on estimated proved natural gas and oil reserves.
The Partnership’s estimates of proved reserves are based on quantities of natural gas and oil that geologic and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Estimates of proved reserves may change, either positively or negatively, as additional information becomes available and as contractual, economic and political conditions change. The Partnership’s net proved reserve estimates have been adjusted as necessary to reflect all contractual agreements, royalty obligations and interests owned by others at the time of the estimate. Petroleum engineers perform an annual reserve and economic evaluation of all the Partnership’s properties on a well-by-well basis as of December 31.
Proved developed reserves are the quantities of natural gas and oil expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped reserves are those reserves expected to be recovered from existing wells where a relatively major expenditure is required for completion. The Partnership’s proved undeveloped reserves relate to future well recompletions in the Codell formation of the Wattenberg Field. These recompletions, which are expected to start in 2011 or later as part of the well development plan, generally occur five to 10 years after initial well drilling. Funding for these recompletions is expected to be provided by withholding distributions from investors beginning in the spring of 2011. Currently, the Partnership expects recompletion activities to be completed through approximately 2014. The time frame of recompletion activity is impacted by individual well decline curves as well as to the objective to maximize the financial impact of the recompletion.
The process of estimating and evaluating natural gas and oil reserves is complex, requiring significant decisions in the evaluation of available geological, geophysical, engineering and economic data. The data for a given property may also change substantially over time as a result of numerous factors, including additional development activity, evolving production history and a continual reassessment of the viability of production under changing economic conditions. As a result, revisions in existing reserve estimates occur from time to time. Although every reasonable effort is made to ensure that reserve estimates reported represent our most accurate assessments possible, the subjective decisions and variances in available data for various properties increase the likelihood of significant changes in these estimates over time. Because estimates of reserves significantly affect DD&A expense, a change in estimated reserves could have a material effect on the Partnership’s financial statements.
In accordance with Statement of Financial Accounting Standards, SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, the Partnership periodically assesses its proved natural gas and oil properties for possible impairment, upon a triggering event, by comparing net capitalized costs to estimated undiscounted future net cash flows on a field-by-field basis using estimated future production based upon estimated prices at which the Partnership reasonably estimates the commodity could be sold. The estimates of future prices may differ from current market prices of natural gas and oil. Downward revisions in estimates to the Partnership’s reserve quantities, expectations of falling commodity prices or rising operating costs may result in a triggering event and therefore a possible impairment of the Partnership’s natural gas and oil properties. If, when assessing impairment, net capitalized costs exceed undiscounted future net cash flows, impairment is based on estimated fair value utilizing a future discounted cash flow analysis and is measured by the amount by which the net capitalized costs exceed fair value. Although cash flow estimates used by the Partnership are based on the relevant information available at the time the estimates are made, estimates of future cash flows are, by nature, highly uncertain and may vary significantly from actual results.
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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 upon delivery 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 gas and prevailing supply and demand conditions. As a result, the Partnership’s revenues from the sale of natural gas will decrease if market prices decline and increase if market prices increase. The Managing General Partner may from time to time enter into derivative agreements, which may either “collar” or “swap” a price range or provide for basis protection in order to reduce the impact of market price fluctuations. The Partnership believes that the pricing provisions of its natural gas contracts are customary in the industry.
The Partnership currently uses the “Net-Back” method of accounting for transportation arrangements of natural gas sales. The Managing General Partner sells natural gas at the wellhead and recognizes revenues based on the wellhead sales price since transportation costs downstream of the wellhead are incurred by the Partnership’s customers and reflected in the wellhead price.
Sales of oil are recognized when persuasive evidence of a sales arrangement exists, the oil is verified as produced and is delivered from storage tanks at well locations to a purchaser, collection of revenue from the sale is reasonably assured, and the sales price is determinable. The Partnership does not refine any of its oil production. The Partnership’s crude oil production is sold to purchasers at or near the Partnership’s wells under short-term purchase contracts at prices and in accordance with arrangements that are customary in the oil industry.
Accounting for Derivatives Contracts at Fair Value
The Managing General Partner does not designate any of the Partnership’s derivative as hedges; therefore the Partnership’s derivative financial instruments do not qualify under the terms of Statement of Financial Accounting Standards (“SFAS”) No. 133, Accounting for Derivative Instruments and Certain Hedging Activities. Derivatives are reported on the accompanying balance sheets at fair value on a gross asset and liability basis. Changes in fair value of derivatives are recorded in “Commodity price risk management gain (loss), net” in the accompanying statements of operations. The measurement of fair value is based on actively quoted market prices, if available. Otherwise, validation of a contract's fair value is performed internally and, while the Partnership uses common industry practices to develop its valuation techniques, changes in its pricing methodologies or the underlying assumptions could result in significantly different fair values. If pricing information from external sources is not available, measurement involves the use of judgment and estimates. These estimates are based on valuation methodologies the Partnership considers appropriate. For individual contracts, the use of different assumptions could have a material effect on the contract's estimated fair value.
Asset Retirement Obligations
The Partnership applies the provisions of SFAS 143, Accounting for Asset Retirement Obligations and Financial Accounting Standards Board, or FASB, Interpretation No. 47, Accounting for Conditional Asset Retirement Obligations, and accounts for asset retirement obligations by recording the fair value of its plugging and abandonment obligations when incurred, 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. Periodically, the asset retirement obligations are accreted, over the estimated lives of the related assets, for the change in present value. The initial capitalized costs are depleted over the useful lives of the related assets, through charges to DD&A expense. If the fair value of the estimated asset retirement obligation changes, an adjustment is recorded to both the asset retirement obligation and the asset retirement cost. Revisions in estimated liabilities can result from revisions of estimated inflation rates, escalating retirement costs and changes in the estimated timing of settling asset retirement obligations. See Note 7, Asset Retirement Obligations to the accompanying financial statements, for a reconciliation of asset retirement obligation activity.
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Recent Accounting Standards
See Note 2, Summary of Significant Accounting Policies to the accompanying financial statements included in this report, for recently issued and implemented accounting standards including the SEC’s published final rule, Modernization of Oil and Gas Reporting which will become effective for the Partnership’s Annual Report on Form 10-K for the year ending December 31, 2009, since early adoption is not permitted.
The most significant provision of the new industry accounting and reporting final rule is the change in the method for determining the December 31, 2009 valuation price for in-ground natural gas and oil resources, which will be used to determine economically producible natural gas and oil reserve quantities. The 2009 year-end valuation price will be based on the application of the 12-month average of the first-day-of-the-month natural gas and oil commodity price during each month of 2009 while the 2008 year-end valuation price will be based on the single-day natural gas and oil commodity price on December 31, 2008. An economically producible quantity, under the new oil and gas reporting rules, is one where the revenue provided by its sale is reasonably likely to exceed the cost to deliver that quantity to market. A second provision of the SEC’s modernized oil and gas industry reporting rules is the revised definition for hydrocarbon resources classified as proved undeveloped reserves, or PUD’s. In order to substantiate natural gas and oil reserve quantities so categorized under the new rules, which may require a relatively major expenditure for their development, the Partnership will be required to have made a final investment decision to develop those additional reserves under a defined plan that is within five years of being initiated. The Partnership’s adoption of this final rule, subsequent SEC interpretations and guidance and accounting pronouncements did not have a material impact on the Partnership’s financial statements, related disclosure and management’s discussion and analysis. For more information regarding the Partnership’s natural gas and oil reserves for 2007, 2006 and 2005, see the Supplemental Natural Gas and Oil Information-Unaudited, Net Proved Natural Gas and Oil Reserves that accompanies the financial statements included in this Annual Report.
In June 2009, the FASB issued FAS No. 168, The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles which will become effective for the Partnership’s quarterly and annual SEC reporting beginning September 30, 2009 and after, since early adoption is not permitted. This standard replaces FAS No. 162, The Hierarchy of Generally Accepted Accounting Principles, and establishes only two levels of U.S. GAAP: authoritative and non-authoritative. The FASB Accounting Standards Codification (the “Codification”) will be referred to in footnotes and management’s discussion and analysis through the use of the Codification’s topical organization structure in the Partnership’s SEC filings for reporting periods after September 30, 2009. The Codification is the current source of authoritative, nongovernmental U.S. generally accepted accounting principles (“GAAP”), except for rules and interpretive releases of the SEC, which are sources of authoritative GAAP for SEC registrants. However, authoritative accounting references cited in this Annual Report on Form 10-K will retain the historical authoritative GAAP standard reference which existed and was in effect, during the years 2007, 2006 and 2005.
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Item 7A.
Item 7A.
Quantitative and Qualitative Disclosure About Market Risk
Market-Sensitive Instruments and Risk Management
The Partnership's primary market risk exposure includes commodity price risk and credit risk exposure. Management of the Managing General Partner has established risk management processes to monitor and manage this market risk.
Commodity Price Risk
The Partnership is exposed to the effect of market fluctuations in the prices of natural gas and oil as they relate to the Partnership’s natural gas and oil sales activities. Price risk represents the potential risk of loss from adverse changes in the market price of natural gas and oil commodities. The Managing General Partner employs established policies and procedures to manage the risks associated with these market fluctuations using commodity derivatives. The Partnership's policy prohibits the use of natural gas and oil derivative instruments for speculative purposes. The Managing General Partner manages price risk on only a portion of the Partnership’s anticipated production, so the remaining portions of the Partnership’s production is subject to the full fluctuation of market pricing.
Derivative arrangements are entered into by the Managing General Partner on behalf of the Partnership. None of the Partnership’s derivative instruments are designated as hedging instruments and do not qualify as hedges in accordance with the provisions of SFAS No. 133, Accounting for Derivative Instruments and Certain Hedging Activities. Accordingly, all gains and losses, realized and unrealized, are recognized in the statement of operations in the period of change. See Note 2, Summary of Significant Accounting Policies and Note 4, Derivative Financial Instruments to the accompanying financial statements for additional disclosure regarding the Partnership’s derivative instruments including, but not limited to, a summary of the open derivative positions as of December 31, 2007. Changes in the fair value of the Partnership’s share of derivatives are recorded in the statement of operations under “Commodity price risk management gain (loss), net.”
Valuation of a contract’s fair value is performed internally and, while the Managing General Partner uses common industry practices to develop the Partnership’s valuation techniques, changes in pricing methodologies or the underlying assumptions could result in different fair values. While the Managing General Partner believes these valuation methods are appropriate and consistent with those used by other market participants, the use of different methodologies, or assumptions, to determine the fair value of certain financial instruments could result in a different estimate of fair value.
Risk Management Strategies
The Partnership’s results of operations and operating cash flows are affected by changes in market prices for natural gas and oil. To mitigate a portion of the exposure to adverse market changes, the Managing General Partner has entered into various derivative contracts. As of December 31, 2007, the Partnership's natural gas and oil derivative instruments were comprised of “collars” and “swaps.” These instruments generally consist of CIG-based contracts for Colorado gas production and NYMEX-based contracts for Colorado oil production. In addition to the collars, swaps and basis protection swaps currently allocated to the Partnership, the Managing General Partner previously utilized “floor” contracts to protect against natural gas and oil price declines in subsequent periods. Through October 31, 2007, the Partnership’s natural gas derivative instruments were comprised of natural gas floors and collars while its oil derivative instruments were comprised of oil floors.
·
“Collars” contain a fixed floor price (put) and ceiling price (call). If the index price falls below the fixed put strike price, PDC, as Managing General Partner, receives the market price from the purchaser and receives the difference between the put strike price and index price from the counterparty. If the index price exceeds the fixed call strike price, PDC, as Managing General Partner, receives the market price from the purchaser and pays the difference between the call strike price and index price to the counterparty. If the index price is between the call and put strike price, no payments are due to or from the counterparty.
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·
“Swaps” are arrangements that guarantee a fixed price. If the index price is below the fixed contract price, PDC, as Managing General Partner, receives the market price from the purchaser and receives the difference between the index price and the fixed contract price from the counterparty. If the index price is above the fixed contract price, PDC, as Managing General Partner, receives the market price from the purchaser and pays the difference between the index price and the fixed contract price to the counterparty. If the index price and contract price are the same, no payment is due to or from the counterparty.
·
“Basis protection swaps” are arrangements that guarantee a price differential for natural gas from a specified delivery point. For CIG basis protection swaps, which traditionally have negative differentials to NYMEX, PDC, as Managing General Partner, receives a payment from the counterparty if the price differential is greater than the stated terms of the contract and pays the counterparty if the price differential is less than the stated terms of the contract. If the index price and contract price are the same, no payment is due to or from the counterparty.
·
“Floors” contain a floor price (put) whereby PDC, as Managing General Partner, receives the market price from the purchaser and the difference between the index price and floor strike price from the counterparty if the index price falls below the floor strike price, but receives no payment when the index price exceeds the floor strike price.
The Managing General Partner enters into derivative instruments for Partnership production to reduce the impact of price declines in future periods. While these derivatives are structured to reduce the 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 in the physical market. The Partnership believes the derivative instruments in place continue to be effective in achieving the risk management objectives for which they were intended.
The following table presents monthly average CIG and NYMEX closing prices for natural gas and oil in 2007, 2006 and 2005, as well as average sales prices the Partnership realized for the respective commodity.
As of December 31, 2007 and 2005, the fair value of the Partnership’s derivative instruments were a net liability of $43,990 and $21,554, respectively, compared to a net asset of $44,753 as of December 31, 2006. Based on a sensitivity analysis as of June 30, 2010, it was estimated that a 10% increase in natural gas and oil prices, inclusive of basis, over the entire period for which the Partnership has derivatives currently in place would result in a decrease in unrealized gains of $107,000 and a 10% decrease in natural gas and oil prices would result in an increase in unrealized gains of $108,000.
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This table identifies the Partnership’s derivative positions related to natural gas and oil sales activities in effect as of June 30, 2010 on the Partnership’s production.
This table identifies the Partnership’s derivative positions related to natural gas and oil sales activities in effect as of December 31, 2007 on the Partnership’s production.
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This table identifies the Partnership’s derivative positions related to natural gas and oil sales activities in effect as of December 31, 2006 on the Partnership’s production.
This table identifies the Partnership’s derivative positions related to natural gas and oil sales activities in effect as of December 31, 2005 on the Partnership’s production.
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Credit Risk
Credit risk represents the loss that the Partnership would incur if a counterparty fails to perform under its contractual obligations. 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 from counterparties.
The Managing General Partner attempts to reduce credit risk by diversifying its counterparty exposure and entering into transactions with high-quality counterparties. When exposed to credit risk, the Managing General Partner analyzes the counterparties’ financial condition prior to entering into an agreement, establishes credit limits and monitors the appropriateness of those limits on an ongoing basis. The Managing General Partner monitors counterparty creditworthiness through credit reports and rating agency reports.
The Managing General Partner has not experienced any counterparty defaults previous to, or during, the years ended December 31, 2007, 2006 and 2005, respectively, therefore, no valuation allowance was recorded by the Partnership during those years. Furthermore, while the Managing General Partner believes these valuation methods are appropriate and consistent with that used by other market participants, the use of different methodologies or assumptions, to determine fair value of certain financial instruments could result in a different estimate of fair value.
Disclosure of Limitations
As the information above includes only those exposures that existed at June 30, 2010, 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.
Item 8.
Financial Statements and Supplementary Data
The financial statements are attached to this Form 10-K beginning at page.
Item 9.
Item 9.
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
Previous Independent Registered Public Accounting Firm
As previously reported on Form 8-K filed with the SEC on October 26, 2006, on October 20, 2006, Petroleum Development Corporation, the Managing General Partner of PDC 2002-C Limited Partnership (the "Registrant"), recommended, and the Audit Committee of the Board of Directors of Petroleum Development Corporation ratified, the dismissal of KPMG LLP ("KPMG") as the Registrant's independent registered public accounting firm. The Registrant does not have its own audit committee and, therefore, relies upon and utilizes the services of the Managing General Partner’s audit committee.
The audit report of KPMG on the Registrant's financial statements as of December 31, 2004, 2003 and 2002, and for the years ended December 31, 2004, December 31, 2003, and the period from November 12, 2002 (date of inception) to December 31, 2002, did not contain an adverse opinion or a disclaimer of opinion, and were not qualified or modified as to uncertainty, audit scope, or accounting principles. The Registrant filed a Form 8-K on November 15, 2005 reporting under Item 4.02 that the previously filed financial statements should no longer be relied upon as the Registrant had determined that the financial statements required restatement for matters related to the accounting for derivatives, the calculation of depreciation and depletion, and the assessment of impairments. Prior to this filing, the Registrant had not filed audited financial statements since its December 31, 2004 10-K. For more information regarding this matter, see our Form 12b-25 filed with the Securities and Exchange Commission on April 3, 2006.
In connection with the audits of the two fiscal years ended December 31, 2004, and the subsequent period through October 20, 2006, there were no: (1) disagreements with KPMG on any matter of accounting principles or practices, financial statement disclosure, or auditing scope or procedure, which disagreement(s), if not resolved to their satisfaction, would have caused them to make reference in connection with their report to the subject matter of the disagreement(s), or (2) reportable events, except that:
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1.
The following material weaknesses in internal control over financial reporting were identified by Management which related to the year ended December 31, 2004, and the subsequent period through October 20, 2006, as follows:
·
The Registrant did not have effective policies and procedures, or personnel with sufficient technical expertise to properly account for derivative transactions in accordance with generally accepted accounting principles. Specifically, the Registrant's policies and procedures relating to derivatives transactions were not designed effectively such that each of the requirements for hedge accounting were evaluated appropriately with respect to the Registrant's commodity based derivatives.
·
The Registrant did not have effective policies and procedures, or personnel with sufficient technical expertise to ensure compliance with appropriate accounting principles for its natural gas and oil properties. Specifically, the Registrant's policies and procedures were not designed effectively to ensure that the calculation of depreciation and depletion and the determination of impairments were performed in accordance with the applicable authoritative accounting guidance.
·
The Registrant did not have effective policies and procedures, or personnel with sufficient technical expertise to ensure that its accounting for asset retirement obligations complied with generally accepted accounting principles. Specifically, the Registrant's policies and procedures regarding the estimate of the fair value of the asset retirement obligations were not designed effectively to ensure that it was estimated in accordance with SFAS No. 143, Asset Retirement Obligations.
·
The Registrant did not have effective policies and procedures to ensure the timely reconciliation, review and adjustment of significant balance sheet and income statement accounts, which resulted in the identification of material misstatements in certain significant balance sheet and income statement accounts during the Registrant's closing process.
2.
In connection with KPMG's audit of the Managing General Partner's 2006 financial statements, the Managing General Partner, identified that the Managing General Partner had over-withheld production taxes from revenue distributions made to its 75 drilling partnerships' limited partners, including the limited partners of the Registrant. See Explanatory Note on Page 1 for discussion concerning the over-withholding of production taxes by PDC.
KPMG was authorized to respond fully to the inquiries of the successor independent registered public accounting firm concerning the subject matter of the foregoing.
The Registrant provided KPMG with a copy of the foregoing statements and requested that KPMG furnish the Registrant with a letter addressed to the SEC stating whether KPMG agrees with the foregoing statements, and, if not, stating the respects in which KPMG does not agree. A letter from KPMG is attached as Exhibit 16 to the Form 8-K filed with the SEC on October 20, 2006.
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New Independent Registered Public Accounting Firm
As previously reported on Form 8-K filed with the SEC on October 26, 2006, on October 25, 2006, the Audit Committee of the Managing General Partner and its Board of Directors ratified the engagement of Schneider Downs & Co., Inc. ("SD") as the Registrant's new independent registered public accounting firm.
During the fiscal years ended December 31, 2004 and 2003, and through October 25, 2006, the Registrant had not consulted with SD regarding either (i) the application of accounting principles to a specified transaction, either completed or proposed; or the type of audit opinion that might be rendered on the Registrant's financial statements, and neither a written report was provided to the Registrant nor oral advice was provided that SD concluded was an important factor considered by the Registrant in reaching a decision as to the accounting, auditing or financial reporting issue; or (ii) any matter that was either the subject of a disagreement, as that term is defined in Item 304(a)(1)(iv) of SEC Regulation S-K, or a reportable event required to be reported under Item 304(a)(1)(v) of Regulation S-K.
Item 9A(T).
Item 9A(T).
Controls and Procedures
The Partnership has no direct management or officers. The management, officers and other employees that provide services on behalf of the Partnership are employed by the Managing General Partner.
(a) Evaluation of Disclosure Controls and Procedures
As of December 31, 2007, PDC, as Managing General Partner on behalf of the Partnership, carried out an evaluation, under the supervision and with the participation of the Managing General Partner's management, including the Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of the Partnership's disclosure controls and procedures. Disclosure controls and procedures are defined in Exchange Act Rules 13a-15(e) and 15d-15(e) as the controls and procedures of an issuer that are designed to ensure that information required to be disclosed by the issuer in the reports it files or submits under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to the issuer’s management, including its principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure. Based upon the evaluation, the Managing General Partner’s Chief Executive Officer and Chief Financial Officer concluded that the Partnership’s disclosure controls and procedures were not effective as of December 31, 2007 due to the existence of the material weaknesses described below in Management’s Report on Internal Control Over Financial Reporting included in this Item 9A(T).
(b) Management’s Report on Internal Control Over Financial Reporting
Management of PDC, the Managing General Partner of the Partnership, is responsible for establishing and maintaining adequate internal control over financial reporting of the Partnership. Internal control over financial reporting is defined in Exchange Act Rules 13a-15(f) and 15d-15(f) as a process designed by, or under the supervision of, the issuer’s principal executive and principal financial officers, or persons performing similar functions, and effected by the issuer’s board of directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America and includes those policies and procedures that:
·
Pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of the assets of the issuer;
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·
Provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with accounting principles generally accepted in the United States of America and that receipts and expenditures of the issuer are being made only in accordance with authorizations of management and directors of the issuer; and
·
Provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the issuer’s assets that could have a material effect on the financial statements of the issuer.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with policies or procedures may deteriorate.
Management of the Managing General Partner has assessed the effectiveness of the Partnership’s internal control over financial reporting as of December 31, 2007, based upon the criteria established in “Internal Control - Integrated Framework” issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, management of the Managing General Partner concluded that the Partnership did not maintain effective internal control over financial reporting as of December 31, 2007 due to the material weaknesses discussed below. A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the registrant’s annual or interim financial statements will not be prevented or detected on a timely basis. Management of PDC, the Managing General Partner, identified the following material weaknesses related to the effectiveness of the Partnership’s internal control over financial reporting as of December 31, 2007:
·
The support for the Partnership’s general ledger depends in part on the effectiveness of controls of the Managing General Partner’s spreadsheets. The overall ineffectiveness of the Managing General Partner's spreadsheet controls could have a material effect on the Partnership’s financial statements. The Partnership did not maintain effective controls to ensure the completeness, accuracy, and validity of key financial statement spreadsheets generated by the Managing General Partner. These spreadsheets are utilized by the Partnership to support significant balance sheet and income statement accounts.
·
The support for the Partnership’s derivative calculations depends in part on the effectiveness of controls of the Managing General Partner’s process. The overall ineffectiveness of the Managing General Partner's derivative controls could have a material effect on the Partnership’s financial statements. The Partnership did not maintain effective controls to ensure that the Managing General Partner had policies and procedures, or personnel with sufficient technical expertise to record derivative activities in accordance with generally accepted accounting principles.
·
For the transactions that are directly related to and processed by the Partnership, the Partnership failed to maintain sufficient documentation to adequately assess the operating effectiveness of internal control over financial reporting. More specifically, the Partnership’s financial close and reporting narrative failed to adequately describe the process, identify key controls and assess segregation of duties.
In addition, the Partnership identified the following material weaknesses related to the effectiveness of the Partnership’s internal control over financial reporting as of December 31, 2006 and 2005:
·
The Partnership did not have effective policies and procedures, or personnel with sufficient technical expertise to ensure compliance with appropriate accounting principles for its natural gas and oil properties. Specifically, the Partnership’s policies and procedures were not designed effectively to ensure that the calculation of depreciation and depletion and the determination of impairments were performed in accordance with the applicable authoritative accounting guidance. This material weakness was remediated as of December 31, 2007.
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·
The Partnership did not have effective policies and procedures to ensure the timely reconciliation, review and adjustment of significant balance sheet and income statement accounts, which resulted in the identification of material misstatements in certain significant balance sheet and income statement accounts during the Partnership’s closing process. This material weakness was remediated as of December 31, 2007.
The accompanying Annual Report on Form 10-K does not include an attestation report of the Partnership’s independent registered public accounting firm regarding internal control over financial reporting pursuant to Item 308T (a)(4) of Regulation S-K.
(c) Remediation of Material Weaknesses in Internal Control
Beginning in the first quarter of 2008, management of the Managing General Partner undertook remediation initiatives related to the following material weaknesses in the Partnership’s internal controls over financial reporting as of December 31, 2007:
·
The support for the Partnership’s general ledger depends in part on the effectiveness of controls of the Managing General Partner’s spreadsheets. The overall ineffectiveness of the Managing General Partner's spreadsheet controls could have a material effect on the Partnership’s financial statements. The Partnership did not maintain effective controls to ensure the completeness, accuracy, and validity of key financial statement spreadsheets generated by the Managing General Partner. These spreadsheets are utilized by the Partnership to support significant balance sheet and income statement accounts.
·
The support for the Partnership’s derivative calculations depends in part on the effectiveness of controls of the Managing General Partner’s process. The overall effectiveness of the Managing General Partner's derivative controls could have a material effect on the Partnership’s financial statements. The Partnership did not maintain effective controls to ensure that the Managing General Partner had policies and procedures, or personnel with sufficient technical expertise to record derivative activities in accordance with generally accepted accounting principles.
The remediation initiatives that were undertaken during 2008 include:
During the first quarter of 2008, the Managing General Partner implemented the general ledger, accounts receivable, cash receipts, revenue, financial reporting, and joint interest billing modules as part of a new broader financial system. The Managing General Partner also implemented a Partnership distribution module in 2009. The new financial system enhanced operating efficiencies and provided more effective management of Partnership business operations and processes. The Managing General Partner has taken the necessary steps to monitor and maintain appropriate internal controls during this period of change. These steps include documenting all new business process changes related to the new financial system; testing all new business processes on the new financial system; and conducting training related to the new business processes and to the new financial system software. The Managing General Partner expects the implementation of the new financial system will strengthen the overall systems of internal controls due to enhanced automation and integration of related processes. The Managing General Partner continues to modify the design and documentation of internal control processes and procedures related to the new financial system to supplement and complement existing internal controls over financial reporting. The system changes were developed to integrate systems and consolidate information, and were not undertaken in response to any actual or perceived deficiencies in the Partnership's internal control over financial reporting. Testing of the controls related to these new systems was included in the scope of the Managing General Partner's assessment of the Partnership's internal control over financial reporting for 2008.
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During the third quarter of 2008, the Managing General Partner improved controls over certain key financial statement spreadsheets that support all significant balance sheet and income statement accounts. Specifically, the Managing General Partner enhanced the spreadsheet policy to provide additional clarification and guidance with regard to risk assessment and enforced controls over: 1) the security and integrity of the data used in the various spreadsheets, 2) access to the spreadsheets, 3) changes to spreadsheet functionality and the related approval process and documentation and 4) increased management’s review of the spreadsheets.
During the third quarter of 2008, in addition to accredited derivative training attended by key personnel, the Managing General Partner created and documented a desktop procedure to: 1) ensure the completeness and accuracy of the Managing General Partner’s derivative activities and 2) supplement key controls previously existing in the process. Further, the desktop procedure provides for a more robust review of the Managing General Partner’s derivative process. This procedure continued to be enhanced throughout the fourth quarter of 2008.
Based on the changes in the Managing General Partner’s internal control over financial reporting discussed above, the Managing General Partner has concluded that the first two material weaknesses described above which were identified as of December 31, 2007, had been remediated as of December 31, 2008.
The remediation initiatives that were undertaken during 2009 include:
In the second quarter, the Partnership developed and implemented a plan to improve controls over certain key financial statement spreadsheets that support all significant balance sheet and income statement accounts. The Partnership also created and documented a procedural framework to ensure the completeness and accuracy of the Partnership’s derivative activities. Additionally, the Partnership has completed the development of a revised financial close and reporting narrative that adequately describes the process, identifies key controls and assesses segregation of duties.
In the third quarter, the Partnership developed documentation that describes the business processes and identifies key controls for internal control over financial reporting that assisted the Managing General Partner in adequately assessing internal control over financial reporting for the Partnership. In addition, the Partnership developed documentation and procedures to adequately assess segregation of duties. The controls and procedures were tested prior to December 31, 2009. At present, the Partnership has not quantified the total cost of this initiative; however, the majority of this cost is expected to be paid by the Managing General Partner.
Based on the changes in the Managing General Partner’s internal control over financial reporting discussed above, the Managing General Partner has concluded that the third material weakness described above which was identified as of December 31, 2007, had been remediated as of December 31, 2009.
(d) Other Changes in Internal Control Over Financial Reporting
Through the end of 2009, PDC made the following changes in PDC’s internal control over financial reporting (as such defined in Rules 13a-15(f) and 15d-15(f) of the Securities Exchange Act of 1934) that have materially affected or are reasonably likely to materially affect the Partnership’s internal control over financial reporting:
Effective July 1, 2009, as part of PDC’s broader financial reporting system, PDC implemented a new partnership investor distribution accounting module to the existing accounting software. PDC has taken the necessary steps to monitor and maintain appropriate internal controls during this period of change. These steps included procedures to preserve the integrity of the data converted and a review by the business owners to validate data converted. Additionally, PDC provided training related to the business process changes and the financial reporting system software to individuals using the financial reporting system to carry out their job responsibilities, as well as, those who rely on the financial information. PDC anticipates that the implementation of this module will strengthen the overall systems of internal controls due to enhanced automation and integration of related processes. PDC is modifying the design and documentation of internal control process and procedures relating to the new module to supplement and complement existing internal control over financial reporting. The system changes were undertaken to integrate systems and consolidate information and were not undertaken in response to any actual or perceived deficiencies in PDC’s internal control over financial reporting. Testing of the controls related to these new systems is ongoing and was included in the scope of PDC’s assessment of its internal control over financial reporting for 2009.
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PDC, the Managing General Partner, made no changes in the Partnership’s internal control over financial reporting, as previously defined above, during the quarters ended March 31 and June 30, 2010 that have materially affected or are reasonably likely to materially affect the Partnership’s internal control over financial reporting.
The Managing General Partner continues to evaluate the ongoing effectiveness and sustainability of the changes PDC made in internal control over financial reporting, and, as a result of the ongoing evaluation, may identify additional changes to improve internal control over financial reporting.
Item 9B.
Item 9B.
Other Information
None
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PART III
Item 10.
Item 10.
Directors, Executive Officers and Corporate Governance
The Partnership has no employees of its own and has authorized the Managing General Partner to manage the Partnership’s business in accordance with the D&O Agreement. PDC’s directors and executive officers and other key employees receive direct remuneration, compensation or reimbursement solely from PDC, and not the Partnership, with respect to services rendered in their capacity to act on behalf of the Partnership.
Board Management and Risk Oversight
PDC, a publicly-owned Nevada corporation, was organized in 1955. The common stock of PDC is traded on the NASDAQ Global Select Market under the symbol "PETD." The business and affairs of the Partnership are managed by the Managing General Partner through the D&O Agreement, by or under the direction of PDC’s Board of Directors (the “Board”), in accordance with Nevada law and PDC’s By-Laws. The directors’ fiduciary duty is to exercise their business judgment in the best interests of PDC’s shareholders, and in that regard, as Managing General Partner, the best interests of the Partnership and other sponsored drilling partnerships. The Board has adopted Corporate Governance Guidelines that govern the structure and functioning of the Board and establish the Board’s policies on a number of corporate governance issues. With respect to the separation of the offices of Chairman and Chief Executive Officer, or CEO, the Board believes it is most prudent to address this issue as a part of its succession planning process and to make a final determination based on the facts and circumstances at the time of the Chairman’s election, annually or as circumstances warrant.
The Managing General Partner’s Board seeks to understand and oversee critical business risks. Risks are considered in every business decision, not just through Board oversight of the Managing General Partner’s Risk Management system. The Board realizes, however, that is not possible to eliminate all risk, nor is it desirable, and that appropriate risk-taking is essential to achieve the Managing General Partner’s objectives. The Board risk oversight structure provides that management report on critical business risk issues to the Planning and Finance Committee, which includes in part, an oversight function concerning PDC’s liquidity, operational and credit risk management. In this regard, the Planning and Finance Committee also provides similar risk assessment and management process oversight functions for sponsored drilling program partnerships, which includes the Partnership. Other Board committees, however, are active in managing the risks related to such committee’s oversight areas. For example, the Audit Committee reviews many risks and related controls in areas that it considers fundamental to the integrity and reliability for the PDC’s financial statements, such as counterparty risks and derivative program risks. The Managing General Partner’s Board has established the Audit Committee, including a subcommittee which focuses specifically on financial reporting matters of PDC’s sponsored drilling partnerships, to assist the Board in monitoring not only the integrity of the Managing General Partner’s financial reporting systems and internal controls but also PDC’s legal and regulatory compliance. The Board has created a Special Committee that has considered, upon Board request, the potential repurchase of certain of the sponsored drilling partnerships for which PDC serves as Managing General Partner. The Special Committee has not been asked to consider a repurchase of PDC 2002-C Limited Partnership at this time.
As the Managing General Partner, PDC actively manages and conducts the business of the Partnership under the authority of the D&O Agreement. PDC’s executive officers are full-time employees who devote the entirety of their daily time to the business and operations of PDC. Included in each executive’s responsibilities to PDC is a time commitment, as may be reasonably required of their expertise, to conduct the primary business affairs of the Partnership that include the following:
·
Profitable development and cost-effective production operations of the Partnership’s natural gas and oil reserves;
·
Market-responsive natural gas and oil marketing and prudent field operations cost management which support maximum cash flows; and
·
Technology-enhanced compliant Partnership administration including the following: accounting; revenue and cost allocation; cash management; tax and regulatory agency reporting and filing; and Investor Partner Relations.
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Although the Partnership has not adopted a formal Code of Ethics, the Managing General Partner, has implemented a Code of Business Conduct and Ethics, as amended (“the Code of Conduct”) that applies to all Directors, officers, employees, agents and representatives of the Managing General Partner and consultants. The Managing General Partner’s principal executive officer, principal financial officer and principal accounting officer are subject to additional specific provisions under the Code of Conduct. The Managing General Partner’s Code of Conduct is posted on PDC’s website at www.petd.com.
The Corporate Governance section of the Managing General Partner’s internet site contains additional information, including PDC’s Certificate of Incorporation and By-Laws, written charters for each Board committee and Board policy statements. PDC's internet address is www.petd.com. PDC will make available to Investor Partners audited financial statements of PDC for the most recent fiscal year and unaudited financial statements for interim periods. PDC also posts these audited financial statements filed with the SEC, on its internet site.
Petroleum Development Corporation (dba PDC Energy)
The executive officers and directors of PDC, their principal occupations for the past five years and additional information is set forth below:
Richard W. McCullough was appointed Chief Executive Officer of the Company in June 2008 and Chairman of PDC’s Board of Directors in November 2008. From November 2006 until November 2008, he served as the Chief Financial Officer of the Company. Prior to joining PDC, Mr. McCullough served from July 2005 to November 2006 as an energy consultant. From January 2004 to July 2005, he was President and Chief Executive Officer of Gasource, LLC, a marketer of long-term, natural gas supplies in Dallas, Texas. From 2001 to 2003, Mr. McCullough served as an investment banker with J.P. Morgan Securities, Atlanta, Georgia, in the public finance utility group supporting bankers nationally in all natural gas matters. Additionally, Mr. McCullough has held senior positions with Progress Energy, Deloitte and Touche, and the Municipal Gas Authority of Georgia. He holds BS and MS degrees from the University of Southern Mississippi and was a practicing Certified Public Accountant for eight years. Mr. McCullough serves as Chairman of the Executive Committee and serves on the Planning and Finance Committee.
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Gysle R. Shellum was appointed Chief Financial Officer in 2008. Prior to joining the Company, Mr. Shellum served as Vice President, Finance and Special Projects of Crosstex Energy, L.P., Dallas, Texas. Mr. Shellum served in this capacity from September 2004 through September 2008. From March 2001 until September 2004, Mr. Shellum served as a consultant to Value Capital, a private consulting firm in Dallas, Texas, where he worked on various projects, including corporate finance and Sarbanes-Oxley Act compliance. Crosstex Energy, L.P. is a publicly traded Delaware limited partnership whose securities are listed on the NASDAQ Global Select Market and is an independent midstream energy company engaged in the gathering, transmission, treating, processing and marketing of natural gas and natural gas liquids.
R. Scott Meyers was appointed Chief Accounting Officer on April 2, 2009. Prior to joining PDC, Mr. Meyers served as a Senior Manager with Schneider Downs Co., Inc., an accounting firm based in Pittsburgh, Pennsylvania. Mr. Meyers served in such capacity from April 2008 to March 2009. Prior thereto, from November 2002 to March 2008, Mr. Meyers was employed by PricewaterhouseCoopers LLP, the last two and one-half years serving as Senior Manager.
Barton R. Brookman, Jr. was appointed Senior Vice President Exploration and Production in March 2008. Previously, Mr. Brookman served as Vice President Exploration and Production since joining PDC in July 2005. Prior to joining PDC, Mr. Brookman worked for Patina Oil and Gas and its predecessor Snyder Oil for 17 years in a series of positions of increasing responsibility, ending his service as Vice President of Operations of Patina.
Daniel W. Amidon was appointed General Counsel and Secretary in July 2007. Prior to his current position, Mr. Amidon was employed by Wheeling-Pittsburgh Steel Corporation beginning in July 2004; he served in several positions including General Counsel and Secretary. Prior to his employment with Wheeling-Pittsburgh Steel, Mr. Amidon worked for J&L Specialty Steel Inc. from 1992 through July 2004 in positions of increasing responsibility, including General Counsel and Secretary. Mr. Amidon practiced with the Pittsburgh law firm of Buchanan Ingersoll PC from 1986 through 1992.
Lance Lauck was appointed Senior Vice President Business Development in August 2009. Previously Mr. Lauck served as Vice President - Acquisitions and Business Development for Quantum Resources Management LLC from 2006 - 2009. From 1988 until 2006, he held various management positions at Anadarko Petroleum Corporation in the areas of acquisitions and divestitures, corporate mergers and business development.
Joseph E. Casabona served as Executive Vice President and member of the Board of Directors of Denver-based Energy Corporation of America, a natural gas exploration and development company, from 1985 until his retirement in May 2007. Mr. Casabona’s responsibilities included strategic planning as well as executive oversight of drilling operations in the continental U.S. and internationally. In 2008, Mr. Casabona became Chief Executive Officer of Paramax Resources Ltd, a junior public Canadian oil & gas company (PMXRF) engaged in the business of acquiring and exploration of oil and gas prospects, primarily in Canada and Idaho. Mr. Casabona serves as Chairman of the Planning and Finance Committee and serves on the Audit Committee.
Anthony J. Crisafio, a Certified Public Accountant, has served as an independent business consultant for more than fifteen years, providing financial and operational advice to businesses in a variety of industries and stages of development. He also serves as an interim Chief Financial Officer and Advisory Board member for a number of privately held companies and has been a Certified Public Accountant for more than thirty years. Mr. Crisafio served as the Chief Operating Officer, Treasurer and member of the Board of Directors of Cinema World, Inc. from 1989 until 1993. From 1975 until 1989, he was employed by Ernst & Young and was a partner with Ernst & Young from 1986 to 1989. He was responsible for several Securities and Exchange Commission (“SEC”) registered client engagements and gained significant experience with oil and gas industry clients and mergers and acquisitions. Mr. Crisafio serves as the Chairman of the Audit Committee and serves on the Compensation Committee.
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Kimberly Luff Wakim, an attorney and a Certified Public Accountant, is a Partner with the Pittsburgh, Pennsylvania law firm Thorp, Reed & Armstrong LLP, where she serves as a member of the Executive Committee and is the Practice Group Leader for the Bankruptcy and Financial Restructuring Practice Group. Ms. Wakim has practiced law with Thorp, Reed & Armstrong LLP since 1990. Ms. Wakim was previously an auditor with Main Hurdman (now KPMG) and was Assistant Controller for PDC from 1982 to 1985. She has been a member of AICPA and the West Virginia Society of CPAs for more than fifteen years. Ms. Wakim serves as Chairman of the Compensation Committee and serves on the Audit Committee and the Nominating and Governance Committee.
Larry F. Mazza is President and Chief Executive Officer of MVB Bank, Inc. in Fairmont, West Virginia. He has been Chief Executive Officer since March 2005, and added the duties of President in January of 2009. Prior to 2005, Mr. Mazza served as Senior Vice President Retail Banking for BB&T and its predecessors in West Virginia, where he was employed from June 1986 to March 2005. A Certified Public Accountant for 26 years, Mr. Mazza also was previously an auditor with KPMG. Mr. Mazza serves on the Nominating and Governance Committee and the Compensation Committee.
David C. Parke is a Managing Director in the investment banking group of Boenning & Scattergood, Inc., West Conshohocken, Pennsylvania, a full-service investment banking firm. Prior to joining Boenning & Scattergood in November 2006, he was a Director with Mufson Howe Hunter & Company LLC, Philadelphia, Pennsylvania, an investment banking firm, from October 2003 to November 2006. From 1992 through 2003, Mr. Parke was Director of Corporate Finance of Investec, Inc. and its predecessor Pennsylvania Merchant Group Ltd., investment banking companies. Prior to joining Pennsylvania Merchant Group, Mr. Parke served in the corporate finance departments of Wheat First Butcher & Singer, now part of Wachovia Securities, and Legg Mason, Inc., now part of Stifel Nicolaus. Mr. Parke serves on the Planning and Finance Committee, the Compensation Committee and on the Nominating and Governance Committee.
James M. Trimble has served as Managing Director of Grand Gulf Energy, Limited (ASX:GGE), a public company traded on the Australian Exchange, since August 2006. In January 2005, Mr. Trimble founded and has since served as President and Chief Executive Officer of the U.S. subsidiary Grand Gulf Energy Company LLC, an exploration and development company focused primarily on drilling in mature basins in Texas, Louisiana and Oklahoma. From 2000 through 2004, Mr. Trimble was Chief Executive Officer of Elysium Energy and then Tex-Cal Energy LLC, both were privately held oil and gas companies that he was brought in to take through troubled workout solutions. Prior to this, he was Senior Vice President of Exploration and Production for Cabot Oil and Gas (NYSE:COG). From November 2002 until May 2006, he also served as a Director of Blue Dolphin Energy, an independent oil and gas company with operations in the Gulf of Mexico. Mr. Trimble serves on the Planning and Finance Committee and the Compensation Committee.
Jeffrey C. Swoveland is President and Chief Executive Officer of ReGear Life Sciences, Inc. in Pittsburgh, Pennsylvania (previously named Coventina Healthcare Enterprises), which develops and markets medical device products, where he was previously Chief Operating Officer. From 2000 until 2007, Mr. Swoveland served as Chief Financial Officer of Body Media, Inc., a life-science company specializing in the design and development of wearable body monitoring products and services. Prior thereto, Mr. Swoveland held various positions, including Vice-President of Finance, Treasurer and interim Chief Financial Officer with Equitable Resources, Inc., a diversified natural gas company, from 1994 to September 2000. Mr. Swoveland serves as a member of the Board of Directors of Linn Energy, LLC, a public, independent natural gas and oil company. Mr. Swoveland serves as Presiding Independent Director, and serves on the Audit Committee, the Planning and Finance Committee and Executive Committee.
Audit Committee
The Audit Committee is composed entirely of persons whom the Board has determined to be independent under NASDAQ Listing Rule 5605(a)(2), Section 301 of the Sarbanes-Oxley Act of 2002 and Section 10A(m)(3) of the Exchange Act. Anthony J. Crisafio chairs the Audit Committee; other members are Directors Wakim, Casabona and Swoveland. The Board has determined that all four members of the Audit Committee qualify as financial experts as defined by SEC regulations and that all of the Audit Committee members are independent of management.
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Item 11.
Item 11.
Executive Compensation
The Partnership does not have any employees or executives of its own. None of PDC's officers or directors receive any direct remuneration, compensation or reimbursement from the Partnership. These persons receive compensation solely from PDC. The Managing General Partner does not believe that PDC’s executive and non-executive compensation structure available to officers or directors who act on behalf of the Partnership is reasonably likely to have a materially adverse effect on the Partnership’s operations or conduct of PDC when carrying out duties and responsibilities to the Partnership, as Managing General Partner under the Agreement, or as operator under the D&O Agreement. The management fee and other amounts paid to the Managing General Partner by the Partnership are not used to directly compensate or reimburse PDC’s officers or directors. No management fee was paid to PDC in 2007, 2006 or 2005 as the Partnership is not required to pay a management fee other than a one-time fee paid in the initial year of formation per the Agreement. The Partnership pays a monthly fee for each producing well based upon competitive industry rates for operations and field supervision and $75 per well per month for Partnership related general and administrative expenses that include accounting, engineering and management of the Partnership by the Managing General Partner. See Item 13, Certain Relationships and Related Transactions, and Director Independence for a discussion of compensation paid by the Partnership to the Managing General Partner.
Compensation Committee Interlocks and Insider Participation
There are no Compensation Committee interlocks.
Item 12.
Item 12.
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
The following table presents information as of June 30, 2010 concerning the Managing General Partner’s interest in the Partnership and other persons known by the Partnership to own beneficially more than 5% of the interests in the Partnership. Each partner exercises sole voting and investing power with respect to the interest beneficially owned.
(1)
Additional general partner units were converted to limited partner interests on October 20, 2003, which was at the completion of the Partnership’s well drilling phase of operations.
(2)
Petroleum Development Corporation (dba PDC Energy), 1775 Sherman Street Suite 3000, Denver, Colorado 80203.
(3)
No current director or officer of PDC owns interest in PDC’s sponsored drilling partnerships. Pursuant to the Partnership Agreement individual investor partners may present their units to PDC for purchase subject to certain conditions; however, PDC is not obligated to purchase more than 10% of the total outstanding units during any calendar year.
(4)
The Percentage of “Total Partnership Interests Beneficially Owned” by PDC, with respect to its limited partnership units repurchased, is determined by multiplying the percentage of limited partnership units repurchased by PDC to total limited partnership units, by the limited partners’ percentage ownership in the Partnership. [(13.03 units/471.91 units)*80% limited partnership ownership]
(5)
In addition to this ownership percentage of limited partnership interest, Petroleum Development Corporation (dba PDC Energy) owns a Managing General Partner interest of 20%.
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Item 13.
Item 13.
Certain Relationships and Related Transactions, and Director Independence
Compensation to the Managing General Partner and Affiliates
The Managing General Partner transacts all of the Partnership’s business on behalf of the Partnership. See Note 3, Transactions with Managing General Partner and Affiliates to the accompanying financial statements, for information regarding compensation to and transactions with the Managing General Partner and affiliates.
Related Party Transaction Policies and Approval
The Limited Partnership Agreement and the Drilling and Operating Agreement with Petroleum Development Corporation (dba PDC Energy) govern related party transactions, including those described in Note 3, Transactions with Managing General Partner and Affiliates to the accompanying financial statements. The Partnership does not have any written policies or procedures for the review, approval or ratification of transactions with related persons outside of the referenced agreements.
Other Agreements and Arrangements
Executive officers of the Managing General Partner were eligible to invest in an executive drilling program, as approved by the Board of Directors.
These executive officers profited from their participation in the executive drilling program because they invested in wells at cost and did not have to pay drilling compensation, management fees or broker commissions and therefore obtained an interest in the wells at a reduced price than that which was charged to the investing partners in a partnership. Investor partners participating in drilling through a partnership were generally charged a profit or markup above the cost of the wells; management fees and commissions at rates which are generally similar to those for this Partnership outlined in Note 3, Transactions with Managing General Partner and Affiliates to the accompanying financial statements.
Through the executive drilling program, certain former executive officers of PDC invested in the wells developed by PDC in which the Partnership invested. The executive program allowed PDC to sell working interests to PDC executive officers in the wells that PDC developed for the Partnership. Participating officers thereby own parallel undivided working interests in all of the wells that the Partnership has invested in. Prior to the funding of the Partnership, each executive officer who chose to participate in the executive program advised PDC of the dollar amount of his investment participation, and thereby acquired a working interest in the wells in which the Partnership acquired a working interest, the acquired working interest being parallel to the working interest of the Partnership and the investor partners. The officers’ percentage in each well is proportionate to the Partnership’s working interest among all of the Partnership’s wells based upon the officers’ investment amount. PDC had the option to sell working interests in these wells, also prior to the funding of the Partnership, to other parties unaffiliated with PDC prior to the funding of the Partnership. No executive officer of PDC elected participation in the Partnership’s drilling program wells. Accordingly, as of June 30, 2010, no current executive officer of the Managing General Partner owns any beneficial interest in the Partnership.
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Director Independence
The Partnership has no directors. The Partnership is managed by the Managing General Partner. See Item 10, Directors, Executive Officers and Corporate Governance.
Item 14.
Item 14.
Principal Accountant Fees and Services
The following table presents amounts charged by the Partnership’s independent registered public accounting firm, Schneider Downs & Co., Inc. (“SD”) for the years described:
(1)
Audit fees consist of professional service fees billed for audit of the Partnership’s annual financial statements which accompany this Comprehensive Annual Report on Form 10-K for the three years ended December 31, 2007, including reviews of the condensed interim financial statements that accompany this Annual Report. SD became the Partnership’s independent registered public accounting firm on October 25, 2006. During the years ended December 31, 2007, 2006 and 2005 there were no other audit-related billings from the Partnership’s independent registered public accounting firm, Schneider Downs & Co., Inc.
(2)
Audit fees billed from the Partnership’s previous independent registered public accounting firm, KPMG LLP (“KPMG”), during 2005 were $51,000 for the audit of the Partnership’s financial statements in the annual reports on Form 10-K for the year ended December 31, 2004 and review of quarterly reports on Form 10-Q for the quarters ended March 31 and June 30, 2005.
Audit Committee Pre-Approval Policies and Procedures
The Sarbanes-Oxley Act of 2002 requires that all services provided to the Partnership by its independent registered public accounting firm be subject to pre-approval by the Audit Committee or authorized Audit Committee member. The Partnership has no Audit Committee. The Audit Committee of PDC, as Managing General Partner, has adopted policies and procedures for pre-approval of all audit services and non-audit services to be provided by the Partnership's independent registered public accounting firm. Services necessary to conduct the annual audit must be pre-approved by the Audit Committee annually. Permissible non-audit services to be performed by the independent registered public accounting firm may also be approved on an annual basis by the Audit Committee if they are of a recurring nature. Permissible non-audit services to be conducted by the independent registered public accounting firm, which are not eligible for annual pre-approval, must be pre-approved individually by the full Audit Committee or by an authorized Audit Committee member. Actual fees incurred for all services performed by the independent registered public accounting firm will be reported to the Audit Committee after the services are fully performed. The duties of the Audit Committee are described in the committee charter, which is available at the Managing General Partner PDC’s website under Corporate Governance.
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Item 15.
Item 15.
Exhibits, Financial Statement Schedules
(a)
The index to Financial Statements is located on page.
(b)
Exhibits index.
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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 2002-C Limited Partnership
By its Managing General Partner
Petroleum Development Corporation, (dba PDC Energy)
By /s/ Richard W. McCullough
Richard W. McCullough
Chairman and Chief Executive Officer
Of Petroleum Development Corporation (dba PDC Energy)
October 27, 2010
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/ Richard W. McCullough
Chairman and Chief Executive Officer
October 27, 2010
Richard W. McCullough
Petroleum Development Corporation
(dba PDC Energy)
Managing General Partner of the Registrant
(Principal executive officer)
/s/ Gysle R. Shellum
Chief Financial Officer
October 27, 2010
Gysle R. Shellum
Petroleum Development Corporation
(dba PDC Energy)
Managing General Partner of the Registrant
(Principal financial officer)
/s/ R. Scott Meyers
Chief Accounting Officer
October 27, 2010
R. Scott Meyers
Petroleum Development Corporation
(dba PDC Energy)
Managing General Partner of the Registrant
(Principal accounting officer)
/s/ Kimberly Luff Wakim
Director
October 27, 2010
Kimberly Luff Wakim
Petroleum Development Corporation
(dba PDC Energy)
Managing General Partner of the Registrant
/s/ Anthony J. Crisafio
Director
October 27, 2010
Anthony J. Crisafio
Petroleum Development Corporation
(dba PDC Energy)
Managing General Partner of the Registrant
/s/ Jeffrey C. Swoveland
Director
October 27, 2010
Jeffrey C. Swoveland
Petroleum Development Corporation
(dba PDC Energy)
Managing General Partner of the Registrant
/s/ Joseph E. Casabona
Director
October 27, 2010
Joseph E. Casabona
Petroleum Development Corporation
(dba PDC Energy)
Managing General Partner of the Registrant
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PDC 2002-C LIMITED PARTNERSHIP
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Partners
PDC 2002-C Limited Partnership:
We have audited the accompanying balance sheets of PDC 2002-C Limited Partnership as of December 31, 2007, 2006 and 2005 and the related statements of operations, partners’ equity and cash flows for each of the years in the three-year period ended December 31, 2007. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audits. The financial statements of PDC 2002-C Limited Partnership for the periods from November 12, 2002 (date of inception) to December 31, 2004, before the restatement described in Note 9, were reported on by another independent registered public accounting firm that has subsequently withdrawn its opinions on those financial statements. Since the prior period financial statements have not been presented herein, the restatements have been effected as an adjustment to the Partners’ Equity balance as of January 1, 2005.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Partnership is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal controls over financial reporting as a basis for designing audit procedures that are appropriate for the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Partnership’s internal control over financial reporting. Accordingly, we express no such opinion. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of PDC 2002-C Limited Partnership as of December 31, 2007, 2006 and 2005, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2007 in conformity with accounting principles generally accepted in the United States of America.
As discussed in Note 3 to the financial statements, the Partnership has had significant related party transactions with the Managing General Partner Petroleum Development Corporation and its subsidiaries.
/s/ Schneider Downs & Co., Inc.
Pittsburgh, Pennsylvania
October 27, 2010
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PDC 2002-C LIMITED PARTNERSHIP
Balance Sheets
As of December 31, 2007, 2006 and 2005
See accompanying notes to financial statements.
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PDC 2002-C LIMITED PARTNERSHIP
Statements of Operations
For the Years Ended December 31, 2007, 2006 and 2005
See accompanying notes to financial statements.
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PDC 2002-C LIMITED PARTNERSHIP
Statements of Partners' Equity
For the Years Ended December 31, 2007, 2006 and 2005
See accompanying notes to financial statements.
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PDC 2002-C LIMITED PARTNERSHIP
Statements of Cash Flows
For the Years Ended December 31, 2007, 2006 and 2005
See accompanying notes to financial statements.
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PDC 2002-C LIMITED PARTNERSHIP
Notes to Financial Statements
Note 1 - Organization
The PDC 2002-C Limited Partnership (the “Partnership” or the “Registrant”) was organized as a limited partnership on June 3, 2002, in accordance with the laws of the State of West Virginia for the purpose of engaging in the exploration and development of natural gas and oil properties. Business operations of the Partnership commenced on November 12, 2002, upon closing of an offering for the sale of Partnership units.
Purchasers of partnership units subscribed to and fully paid for 17.00 units of limited partner interests and 454.91 units of additional general partner interests at $20,000 per unit. As of June 30, 2010, there were 479 Investor Partners. Petroleum Development Corporation (dba PDC Energy) (“PDC”) is the designated Managing General Partner of the Partnership and owns a 20% Managing General Partner ownership in the Partnership. According to the terms of the Limited Partnership Agreement, revenues, costs and cash distributions of the Partnership are allocated 80% to the limited and additional general partners (collectively, the “Investor Partners”), which are shared pro rata based upon the amount of their investment in the Partnership, and 20% to the Managing General Partner. Through June 30, 2010, the Managing General Partner has repurchased 13.03 units of Partnership interests from Investor Partners at an average price of $6,920 per unit.
Upon completion of the drilling phase of the Partnership's wells, all additional general partners units were converted into units of limited partner interests and thereafter became limited partners of the Partnership.
In accordance with the terms of the Limited Partnership Agreement (the “Agreement”), the Managing General Partner manages all activities of the Partnership and acts as the intermediary for substantially all Partnership transactions.
Executive Drilling Program
Executive officers of the Managing General Partner were eligible to invest in an executive drilling program, as approved by the Board of Directors. These executive officers profited from their participation in the executive drilling program because they invested in wells at cost and did not have to pay drilling compensation, management fees or broker commissions and therefore obtained an interest in the wells at a reduced price than that which was charged to the investing partners in a partnership. Investor partners participating in drilling through a partnership were generally charged a profit or markup above the cost of the wells, management fees and commissions at rates similar to those for this Partnership outlined in Note 3, Transactions with Managing General Partner and Affiliates.
Through the executive drilling program, certain former executive officers of PDC invested in the wells developed by PDC in which the Partnership invested. The executive program allowed PDC to sell working interests to PDC executive officers in the wells that PDC developed for the Partnership. Participating officers thereby own parallel undivided working interests in all of the wells that the Partnership has invested in. Prior to the funding of the Partnership, each executive officer who chose to participate in the executive program advised PDC of the dollar amount of his investment participation, and thereby acquired a working interest in the wells in which the Partnership acquired a working interest, the acquired working interest being parallel to the working interest of the Partnership and the investor partners. The officers’ percentage in each well is proportionate to the Partnership’s working interest among all of the Partnership’s wells based upon the officers’ investment amount. PDC had an option to sell working interests in these wells, also prior to the funding of the Partnership, to other parties unaffiliated with PDC prior to funding of the Partnership. No executive officer of PDC elected participation in the Partnership’s drilling program wells. Accordingly, as of June 30, 2010, no current executive officer of the Managing General Partner owns any beneficial interest in the Partnership.
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PDC 2002-C LIMITED PARTNERSHIP
Notes to Financial Statements
Note 2 - Summary of Significant Accounting Policies
Basis of Presentation
The financial statements include only those assets, liabilities and results of operations of the partners which relate to the business of the Partnership.
Cash and Cash Equivalents
The Partnership considers all highly liquid investments with original maturities of three months or less to be cash equivalents. The Partnership maintains substantially all of its cash and cash equivalents in a bank account at one financial institution. Prior to October 3, 2008, the balance in the Partnership’s account was insured by Federal Deposit Insurance Corporation, or FDIC, up to $100,000. As a result of the Emergency Economic Stability Act, the FDIC limit was raised to $250,000 effective October 3, 2008 through December 31, 2009 and subsequently extended through December 31, 2013. The Partnership has not experienced losses in any such accounts to date and limits the Partnership’s exposure to credit loss by placing its cash and cash equivalents with high-quality financial institutions.
Accounts Receivable and Allowance for Doubtful Accounts
The Partnership’s accounts receivable are from purchasers of natural gas and oil production. The Partnership sells substantially all of its natural gas and oil to customers who purchase natural gas and oil from other partnerships managed by the Partnership’s Managing General Partner. Inherent to the Partnership’s industry is the concentration of natural gas and oil sales made to few customers. This industry concentration has the potential to impact the Partnership’s overall exposure to credit risk, either positively or negatively, in that its customers may be similarly affected by changes in economic, industry or other conditions. As of December 31, 2007, 2006 and 2005, the Partnership did not record an allowance for doubtful accounts. Historically, neither PDC nor any of the other partnerships managed by the Partnership’s Managing General Partner have experienced significant losses on accounts receivable. The Managing General Partner periodically reviews accounts receivable for credit risks resulting from changes in the financial condition of its customers. The Partnership did not incur any losses on accounts receivable for the years ended December 31, 2007, 2006 and 2005.
Due from (to) Managing General Partner - Other, Net
The Managing General Partner transacts business on behalf of the Partnership. Other than natural gas and oil revenues which have not been received by the Managing General Partner at the balance sheet date and the Partnership’s portion of unexpired derivatives instruments, which are included in separate balance sheet captions, all other unsettled transactions with PDC and its affiliates are recorded net on the balance sheet under the caption “Due from (to) Managing General Partner - other, net” and are more fully described in Note 3 Transactions with Managing General Partner and Affiliates. In addition, certain amounts recorded by the Partnership as assets in the account “Due from (to) Managing General Partner - other, net” include amounts that are being held as restricted cash by the Managing General Partner, on behalf of the Partnership, for which PDC serves as Managing General Partner.
Additionally, certain amounts representing royalties on Partnership production through 2007, which were deducted from subsequent Partner distributions, were recorded by the Partnership as liabilities in the account “Due from (to) Managing General Partner-other, net.” These amounts as of December 31, 2007, which total approximately $68,000, represent the Partnership’s share of the court approved royalty litigation payment and settlement, more fully described in Note 8, Commitments and Contingencies.
PDC maintains performance bonds in the form of certificates of deposit for plugging, reclaiming and abandoning of the Partnership’s wells as required by governmental agencies. If a government agency were required to access these performance bonds to cover plugging, reclaiming or abandonment costs on a Partnership well, the Partnership would be obligated to fund any amounts in excess of funds previously withheld by PDC to cover these expenses.
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PDC 2002-C LIMITED PARTNERSHIP
Notes to Financial Statements
Natural Gas and Oil Properties
The Partnership accounts for its natural gas and oil properties (the “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 natural gas and oil reserves. Property acquisition costs are depreciated or depleted on the unit-of-production method based on estimated proved natural gas and oil reserves. Petroleum engineers annually perform a new reserve evaluation of the Partnership’s natural gas and oil wells as of December 31. The Managing General Partner’s Reserve Engineering Department petroleum engineers performed the Partnership’s reserve evaluation for the years 2007, 2006 and 2005. See Supplemental Natural Gas and Oil Information - Unaudited, Net Proved Natural Gas and Oil Reserves for additional information regarding the Partnership’s reserve reporting. In accordance with the Agreement, all capital contributed to the Partnership after deducting syndication costs and a one-time management fee is to be used solely for the drilling of natural gas and oil wells. The Partnership does not maintain an inventory of undrilled leases.
Partnership estimates of proved reserves are based on quantities of natural gas and oil that engineering and geological analysis demonstrates, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic conditions. The petroleum engineers prepare the annual reserve and economic evaluation of all properties on a well-by-well basis. Additionally, the Partnership adjusts natural gas and oil reserves for major well rework or abandonment during the year as needed. The process of estimating and evaluating natural gas and oil reserves is complex, requiring significant decisions in the evaluation of available geological, geophysical, engineering and economic data. The data for a given property may also change substantially over time as a result of numerous factors, including additional development activity, evolving production history and a continual reassessment of the viability of production under changing economic conditions. As a result, revisions in existing reserve estimates occur from time to time. Although every reasonable effort is made to ensure that reserve estimates represent the Partnership’s most accurate assessments possible, the subjective decisions and variances in available data for various properties increase the likelihood of significant changes in these estimates over time. Because estimates of reserves significantly affect the Partnership’s depreciation, depletion and amortization (“DD&A”) expense, a change in the Partnership’s estimated reserves could have an effect on the Partnership’s net income.
In accordance with Statement of Financial Accounting Standards, SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, the Partnership assesses its proved natural gas and oil properties for possible impairment, upon a triggering event, 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 the Partnership reasonably estimates the commodity to be sold. The estimates of future prices may differ from current market prices of natural gas and oil. Downward revisions in estimates to the Partnership’s reserve quantities, expectations of falling commodity prices or rising operating costs could result in a triggering event and therefore a possible impairment of the Partnership’s natural gas and oil properties. If net capitalized costs exceed undiscounted future net cash flows, impairment is based on estimated fair value utilizing a future discounted cash flow analysis and is measured by the amount by which the net capitalized costs exceed their fair value. Due to the availability of the required annual reserve report (which is a triggering event) during the fourth quarter of 2007, the Partnership reviewed its proved natural gas and oil properties for impairment and determined that no impairments occurred in any periods presented. Since its operations commenced in December 2002, the Partnership has recorded impairment expense of approximately $1.8 million, which was recorded in the first quarter of 2004.
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PDC 2002-C 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. 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 gas supplies.
The Partnership currently uses the “Net-Back” method of accounting for transportation arrangements of natural gas sales. The Managing General Partner markets the Partnership’s natural gas at the wellhead and recognizes revenues based on the wellhead sales price since transportation costs downstream of the wellhead are incurred by the Partnership’s customers and reflected in the wellhead price.
Sales of oil are recognized when persuasive evidence of a sales arrangement exists, the oil is verified as produced and is delivered from storage tanks at well locations to a purchaser, collection of revenue from the sale is reasonably assured and the sales price is determinable. The Partnership is currently able to sell all the oil that it can produce under existing sales contracts with petroleum refiners and marketers. The Partnership does not refine any of its oil production.
The Partnership’s crude oil production is sold to purchasers at or near the Partnership’s wells under short-term purchase contracts at prices and in accordance with arrangements that are customary in the oil industry.
Major Customers. The following table presents the individual customers constituting 10% or more of the Partnership’s natural gas and oil sales, for the periods indicated:
The Partnership presents any taxes collected from customers and remitted to a government agency on a net basis in its statements of operations in accordance with EITF 06-3, How Taxes Collected from Customers and Remitted to Governments Should be Presented in the Income Statement.
Asset Retirement Obligations
The Partnership applies the provisions of SFAS No. 143, Accounting for Asset Retirement Obligations and Financial Accounting Standards Board, or FASB, Interpretation No. 47, Accounting for Conditional Asset Retirement Obligations, and accounts for asset retirement obligations by recording the fair value of its plugging and abandonment obligations when incurred, 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. The asset retirement obligations are accreted, over the estimated life of the related asset, for the change in present value. The initial capitalized costs are depleted over the useful lives of the related assets, through charges to DD&A expense. If the fair value of the estimated asset retirement obligation changes, an adjustment is recorded to both the asset retirement obligation and the asset retirement cost. Revisions in estimated liabilities can result from revisions of estimated inflation rates, escalating retirement costs and changes in the estimated timing of settling asset retirement obligations. See Note 7, Asset Retirement Obligations for a reconciliation of asset retirement obligation activity.
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PDC 2002-C LIMITED PARTNERSHIP
Notes to Financial Statements
Derivative Financial Instruments
The Partnership accounts for derivative financial instruments in accordance with SFAS Statement No. 133 Accounting for Derivative Instruments and Certain Hedging Activities, as amended. During the years ended December 31, 2007, 2006 and 2005, respectively, none of the Partnership’s derivative instruments were designated as hedging instruments and did not qualify as hedges in accordance with the provisions of SFAS No. 133. Accordingly, the Partnership recognizes all derivative instruments as either an asset or liability on the balance sheet at fair value and the change in the fair value is recorded in “Commodity price risk management (loss) gain, net,” on the Partnership’s statements of operations. 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 either “Due from Managing General Partner - derivatives” in the case of a net holding gain or “Due to Managing General Partner - derivatives” in the case of a net holding loss. Realized gains or losses that have not yet been distributed to the Partnership or paid by the Partnership are included in the balance sheet caption “Due from Managing General Partner other, net.” Undistributed realized gains amounted to $13,353 and $1,984 as of December 31, 2007 and 2006, respectively, and undistributed realized losses amounted to $29,145 as of December 31, 2005.
Valuation of a contract’s fair value is performed internally and, while the Managing General Partner uses common industry practices to develop the Partnership’s valuation techniques, changes in pricing methodologies or the underlying assumptions could result in different fair values. While the Managing General Partner believes these valuation methods are appropriate and consistent with those used by other market participants, the use of different methodologies, or assumptions, to determine the fair value of certain financial instruments could result in a different estimate of fair value.
Credit risk represents the loss that the Partnership would incur if a counterparty fails to perform under its contractual obligations. 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 from counterparties.
The Managing General Partner attempts to reduce credit risk by diversifying its counterparty exposure and entering into transactions with high-quality counterparties. When exposed to credit risk, the Managing General Partner analyzes the counterparties’ financial condition prior to entering into an agreement, establishes credit limits and monitors the appropriateness of those limits on an ongoing basis. PDC, the Managing General Partner has had no counterparty default losses. The Managing General Partner monitors their creditworthiness through credit reports and rating agency reports.
The Managing General Partner has not experienced any counterparty defaults previous to, or during, the years ended December 31, 2007, 2006 and 2005; therefore, no valuation allowance was recorded by the Partnership at December 31, 2007, 2006 and 2005.
Income Taxes
Since the taxable income or loss of the Partnership is reported in the separate tax returns of the individual investor partners, no provision has been made for income taxes by the Partnership.
Production Tax Liability
The Partnership is responsible for production taxes which are primarily made up of severance and property taxes to be paid to the states and counties in which the Partnership produces natural gas and oil. The Partnership’s share of these taxes is expensed to the account “Production and operating costs.” The Partnership’s production taxes payable are included in the caption “Accounts payable and accrued expenses” on the Partnership’s balance sheets.
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Notes to Financial Statements
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 Partnership 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 natural gas and oil reserves, future cash flows from natural gas and oil properties which are used in assessing impairment of long-lived assets, estimated production and severance taxes, asset retirement obligations and valuation of derivative instruments.
Recently Issued Accounting Standards
Fair Value Measurements and Disclosures
In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements, which replaces several existing pronouncements, defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. SFAS No. 157, which the Partnership adopted on January 1, 2008, applies broadly to financial and nonfinancial assets and liabilities that are measured at fair value under other authoritative accounting pronouncements, but does not expand the application of fair value accounting to any new circumstances.
In February 2008, the FASB issued FASB Staff Position, or FSP, FAS No. 157-2, Effective Date of FASB Statement No. 157, which delayed the effective date of SFAS No. 157 by one year (to January 1, 2009) for nonfinancial assets and liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually). The Partnership’s adoption of SFAS 157 did not have a material effect on the Partnership financial statements.
In October 2008, the FASB issued FSP FAS No. 157-3, Determining the Fair Value of a Financial Asset in a Market That Is Not Active, which applies to financial assets within the scope of accounting pronouncements that require or permit fair value measurements in accordance with SFAS No. 157. This FSP clarifies the application of SFAS No. 157 in a market that is not active and defines additional key criteria in determining the fair value of a financial asset when the market for that financial asset is not active. FSP FAS No. 157-3 was effective upon issuance and did not have a material impact on the Partnership’s financial statements.
In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities. SFAS No. 159 permits entities to choose to measure, at fair value, many financial instruments and certain other items that are not currently required to be measured at fair value. The objective is to improve financial reporting by providing entities with the opportunity to mitigate volatility in reported earnings caused by measuring related assets and liabilities differently without having to apply complex hedge accounting provisions. SFAS No. 159 establishes presentation and disclosure requirements designed to facilitate comparisons between entities that choose different measurement attributes for similar types of assets and liabilities. The statement will be effective as of the beginning of an entity's first fiscal year beginning after November 15, 2007. The Partnership has not and does not intend to measure additional financial assets and liabilities at fair value.
In August 2009, the FASB issued Accounting Standards Update, or ASU, No. 2009-05, Measuring Liabilities at Fair Value which provides amendments to Accounting Standards Codification, or ASC, Topic 820, Fair Value Measurements and Disclosure, to reduce potential ambiguity in financial reporting when measuring the fair value of liabilities. These changes clarify existing guidance that in circumstances in which a quoted price in an active market for the identical liability is not available, an entity is required to measure fair value using either a valuation technique that uses a quoted price of either a similar liability or a quoted price of an identical or similar liability when traded as an asset, or another valuation technique that is consistent with the principles of fair value measurements, such as an income approach (e.g., present value technique). This guidance also states that both a quoted price in an active market for the identical liability and a quoted price for the identical liability when traded as an asset in an active market when no adjustments to the quoted price of the asset are required are Level 1 fair value measurements. These changes become effective for the Partnership on October 1, 2009. The Partnership determined that these changes did not have a material effect on the Partnership’s financial statements.
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Notes to Financial Statements
In January 2010, the FASB issued ASU No. 2010-06, Fair Value Measurements and Disclosures (Topic 820): Improving Disclosures about Fair Value Measurements which requires some new disclosures and clarifies existing disclosure requirements. The ASU requires gross presentation of activities within the Level 3 roll forward, whereby entities must present separately information about purchases, sales, issuances and settlements. The update also added a new requirement to disclose fair value transfers in and out of Levels 1 and 2 and describe the reasons for the transfers. These changes will be effective for the Partnership’s financial statements issued for the first interim or annual reporting period beginning after December 15, 2009, except for gross presentation of the Level 3 roll forward, which will become effective for annual reporting periods beginning after December 15, 2010. The Partnership’s adoption did not have a material effect on the Partnership’s financial statements and related disclosures.
Derivatives and Hedging Disclosures
In April 2007, the FASB issued FASB Interpretation (“FIN”) No. 39-1, Amendment of FASB Interpretation No. 39, to amend certain portions of Interpretation 39. FIN 39-1 replaces the terms “conditional contracts” and “exchange contracts” in Interpretation 39 with the term “derivative instruments” as defined in Statement 133. FIN 39-1 also amends Interpretation 39 to allow for the offsetting of fair value amounts for the right to reclaim cash collateral or receivable, or the obligation to return cash collateral or payable, arising from the same master netting arrangement as the derivative instruments. FIN 39-1 applies to fiscal years beginning after November 15, 2007, with early adoption permitted. The Partnership’s adoption of FSP FIN 39-1 did not have a material effect on the financial statements.
In March 2008, the FASB issued FAS No. 161, Disclosures about Derivative Instruments and Hedging Activities-An Amendment of FASB Statement No. 133, which changes the disclosure requirements for derivative instruments and hedging activities. Enhanced disclosures are required to provide information about (a) how and why an entity uses derivative instruments, (b) how derivative instruments and related hedged items are accounted for under Statement 133 and its related interpretations and (c) how derivative instruments and related hedged items affect an entity’s financial position, financial performance and cash flows. The Partnership will adopt the provisions of FAS No. 161 effective January 1, 2009. The adoption of FAS No. 161 did not have a material impact on the Partnership’s financial statements. For more information on the Partnership’s derivative accounting, see Note 4, Derivative Financial Instruments.
Business Combinations
In December 2007, the FASB issued FAS No. 141 (revised 2007), Business Combinations (“FAS No. 141(R)”). FAS No. 141(R) requires an acquirer to recognize the assets acquired, the liabilities assumed and any noncontrolling interest in the acquiree at their acquisition-date fair values. FAS No. 141(R) also requires disclosure of the information necessary for investors and other users to evaluate and understand the nature and financial effect of the business combination. Additionally, FAS No. 141(R) requires that acquisition-related costs be expensed as incurred. The provisions of FAS No. 141(R) will become effective for acquisitions completed on or after January 1, 2009; however, the income tax provisions of FAS No. 141(R) will become effective as of that date for all acquisitions, regardless of the acquisition date. FAS No. 141(R) amends FAS No. 109, Accounting for Income Taxes, to require the acquirer to recognize changes in the amount of its deferred tax benefits recognizable due to a business combination either in income from continuing operations in the period of the combination or directly in contributed capital, depending on the circumstances. FAS No. 141(R) further amends FAS No. 109 and FASB Interpretation No. (“FIN”) 48, Accounting for Uncertainty in Income Taxes, to require, subsequent to a prescribed measurement period, changes to acquisition-date income tax uncertainties to be reported in income from continuing operations and changes to acquisition-date acquiree deferred tax benefits to be reported in income from continuing operations or directly in contributed capital, depending on the circumstances. In April 2009, the FASB issued FSP FAS No. 141(R)-1, Accounting for Assets Acquired and Liabilities Assumed in a Business Combination That Arise from Contingencies (“FSP 141(R)-1”), amending the guidance of FAS No. 141(R) to require that assets acquired and liabilities assumed in a business combination that arise from contingencies be recognized at fair value if fair value can be reasonably estimated and if not, the asset and liability would generally be recognized in accordance with FAS No. 5, Accounting for Contingencies, and FASB Interpretation No. 14, Reasonable Estimation of the Amount of a Loss. Further, FSP 141(R)-1 requires that certain acquired contingencies be treated as contingent consideration and measured both initially and subsequently at fair value. The Partnership will adopt the provisions of FAS No. 141(R) and FSP 141(R)-1 effective January 1, 2009, for which the provisions will be applied prospectively in the Partnership’s accounting for future acquisitions, if any. The adoption did not have an impact on the Partnership’s financial statements.
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Notes to Financial Statements
Consolidations
In December 2007, the FASB issued FAS No. 160, Non-controlling Interests in Consolidated Financial Statements-An Amendment of ARB No. 51 (“FAS No. 160”). FAS No. 160 requires the accounting and reporting for minority interests to be recharacterized as non-controlling interests and classified as a component of equity. Additionally, FAS No. 160 establishes reporting requirements that provide sufficient disclosures which clearly identify and distinguish between the interests of the parent and the interests of the non-controlling owners. The Partnership will adopt the provisions of FAS No. 160 effective January 1, 2009. The Partnership’s adoption did not have a material effect on the Partnership’s financial statements.
In June 2009, the FASB issued FAS No. 167, Amendments to FASB Interpretation No. 46(R), to improve financial reporting by enterprises involved with variable interest entities by addressing (1) the effects on certain provisions of FIN 46 (revised December 2003) (“FIN 46(R)”), Consolidation of Variable Interest Entities, as a result of the elimination of the qualifying special-purpose entity concept in FAS No. 166, Accounting for Transfers of Financial Assets, and (2) constituent concerns about the application of certain key provisions of FIN 46(R), including those in which the accounting and disclosures under the Interpretation do not always provide timely and useful information about an enterprise’s involvement in a variable interest entity. This statement is effective for financial statements issued for fiscal years beginning after November 15, 2009, with earlier adoption prohibited. The Partnership’s adoption of FAS No. 167 did not have an impact on the Partnership’s financial statements, related disclosure and management’s discussion and analysis.
Natural Gas and Oil Reserve Estimation and Reporting
In January 2009, the SEC published its final rule, Modernization of Oil and Gas Reporting, which modifies the SEC’s reporting and disclosure rules for natural gas and oil reserves. The revised reporting and disclosure requirements are effective for the Partnership’s Annual Report on Form 10-K for the year ending December 31, 2009. Early adoption is not permitted.
The most significant provision of the new industry accounting and reporting final rule is the change in the method for determining the December 31, 2009 valuation price for in-ground natural gas and oil resources, which will be used to determine economically producible natural gas and oil reserve quantities. The 2009 year-end valuation price will be based on the application of the 12-month average of the first-day-of-the-month natural gas and oil commodity price during each month of 2009 while the 2008 year-end valuation price will be based on the single-day natural gas and oil commodity price on December 31, 2008. An economically producible quantity, under the new oil and gas reporting rules, is one where the revenue provided by its sale is reasonably likely to exceed the cost to deliver that quantity to market. A second provision of the SEC’s modernized oil and gas industry reporting rules is the revised definition for hydrocarbon resources classified as proved undeveloped reserves, or PUD’s. In order to substantiate natural gas and oil reserve quantities so categorized under the new rules, which may require a relatively major expenditure for their development, the Partnership will be required to have made a final investment decision to develop those additional reserves under a defined plan that is within five years of being initiated.
Related to efforts by the SEC to provide investors with a more meaningful and comprehensive understanding of natural gas and oil reserves, the FASB issued the following accounting pronouncements:
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Notes to Financial Statements
·
On January 6, 2010, the FASB issued ASU No. 2010-03 Extractive Activities - Oil and Gas (Topic 932): Oil and Gas Reserve Estimation and Disclosures, an update of ASC Topic 932 Extractive Activities - Oil and Gas, which substantially aligns the reserve estimation, disclosure requirements, and definitions of Topic 932 with the disclosure requirements of the Final Rule issued by the SEC.
·
On April 20, 2010, the FASB issued ASU No. 2010-14 Accounting for Extractive Activities - Oil and Gas: Amendments to Paragraph 932-10-S99-1 which is a technical amendment for the SEC’s Modernization of Oil and Gas Reporting Final Rule to ASC Topic 932 Extractive Activities - Oil and Gas, SEC Materials that incorporates selected SEC and SEC Staff content into The Codification for reference by public companies.
The Partnership’s adoption of this final rule, subsequent SEC interpretations and guidance and accounting pronouncements did not have a material effect on the Partnership’s financial statements, related disclosure and management’s discussion and analysis.
Subsequent Events
In May 2009, the FASB issued FAS No. 165, Subsequent Events. FAS No. 165 establishes general standards of accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued. Specifically, FAS No. 165 sets forth the period after the balance sheet date during which management of a reporting entity should evaluate events or transactions that may occur for potential recognition or disclosure in the financial statements, the circumstances under which an entity should recognize events or transactions occurring after the balance sheet date in its financial statements, and the disclosures that an entity should make about events or transactions that occurred after the balance sheet date. FAS No. 165 is effective for interim or annual periods ending after June 15, 2009, and is applied prospectively. The Partnership’s adoption of FAS No. 165 as of June 30, 2009 did not have a material effect on the Partnership’s financial statements, related disclosures and management discussion and analysis.
In February 2010, the FASB issued ASU No. 2010-09, Subsequent Events (Topic 855): Amendments to Certain Recognition and Disclosure Requirements which eliminates the requirement that an SEC filer disclose the date through which subsequent events have been evaluated for initially issued, or revised, financial statements. This amendment was effective upon issuance. The Partnership’s adoption did not have a material impact on the Partnership’s financial statements.
Generally Accepted Accounting Principles
In June 2009, the FASB issued FAS No. 168, The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles. This standard replaces FAS No. 162, The Hierarchy of Generally Accepted Accounting Principles, and establishes only two levels of U.S. GAAP, authoritative and non-authoritative. The FASB Accounting Standards Codification (the “Codification”) will become the source of authoritative, nongovernmental U.S. generally accepted accounting principles (“GAAP”), except for rules and interpretive releases of the SEC, which are sources of authoritative GAAP for SEC registrants. All other non-grandfathered, non-SEC accounting literature not included in the Codification will become non-authoritative. This standard is effective for financial statements issued for fiscal years and interim periods ending after September 15, 2009. As the Codification was not intended to change or alter existing GAAP, the Partnership’s adoption did not have a material impact on the Partnership’s financial statements.
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Notes to Financial Statements
Internal Control over Financial Reporting in Exchange Act Periodic Reports
On July 21, 2010, the enactment of the Dodd-Frank Wall Street Reform and Consumer Protection Act made permanent the SEC’s non-accelerated filer’s exemption, previously set to expire after December 15, 2010, from compliance with Section 404(b) of the Sarbanes-Oxley Act of 2002, or SOX. Therefore, as a non-accelerated filer, the Partnership is exempted from the SOX requirement that SEC registrants provide an attestation report on the effectiveness of internal controls over financial reporting by the registrant’s external auditor.
Recently Adopted Accounting Standards
Accounting Changes and Error Correction
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 APB 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 in addition to changes required by an accounting pronouncement in the unusual instance that the pronouncement does not include specific transition provisions. SFAS No. 154 became effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005. The January 1, 2006 adoption of SFAS No. 154 did not have a material impact on the Partnership's financial statements.
Revenue Recognition: Taxes Received from Customers
In June 2006, the FASB issued Emerging Issues Task Force, or EITF, No. 06-3, How Taxes Collected from Customers and Remitted to Governmental Authorities Should be Presented in the Income Statement (That Is, Gross versus Net Presentation). EITF 06-3 addresses the income statement presentation of any tax collected from customers and remitted to a government authority and concludes that the presentation of taxes on either a gross basis or a net basis is an accounting policy decision that should be disclosed pursuant to Accounting Principles Board, or APB, No. 22, Disclosures of Accounting Policies. For taxes that are reported on a gross basis (included in revenues and costs), EITF 06-3 requires disclosure of the amounts of those taxes in interim and annual financial statements, if those amounts are significant. EITF 06-3 became effective for interim and annual reporting periods beginning after December 15, 2006. The adoption of EITF 06-03, effective January 1, 2007, had no impact on the accompanying financial statements. The Partnership's existing accounting policy, which was not changed upon the adoption of EITF 06-3, is to present taxes within the scope of EITF 06-3 on a net basis.
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Notes to Financial Statements
Note 3 - Transactions with Managing General Partner and Affiliates
The Managing General Partner transacts business on behalf of the Partnership under the authority of the Drilling and Operating Agreement (D&O Agreement). Revenues and other cash inflows received on behalf of the Partnership are distributed to the Partners net of (after deducting) corresponding operating costs and other cash outflows incurred on behalf of the Partnership. Undistributed natural gas and oil revenues collected by the Managing General Partner from the Partnership’s customers of $158,593, $120,843 and $290,093 as of December 31, 2007, 2006 and 2005, respectively, are included in the balance sheet caption “Due from Managing General Partner - other, net.” The fair value of the Partnership’s portion of unexpired derivative instruments is recorded on the balance sheet under the caption “Due from the Managing General Partner - derivatives” in the case of net unrealized gains or “Due to Managing General Partner - derivatives” in the case of net unrealized losses. All other unsettled transactions between the Partnership and the Managing General Partner are recorded net on the balance sheet under the caption “Due to or from Managing General Partner - other, net.”
The following table presents transactions with the Managing General Partner and its affiliates for the years ended December 31, 2007, 2006 and 2005. “Well operations and maintenance” and “Gathering, compression and processing fees” are included in “Production and operating costs” on the Statements of Operations.
(1) Under the D&O Agreement, the Managing General Partner, as operator of the wells, receives payments for well charges and lease operating supplies and maintenance expenses from the Partnership when the wells begin producing.
Well charges. The Managing General Partner receives reimbursement at actual cost for all direct expenses incurred on behalf of the Partnership, monthly well operating charges for operating and maintaining the wells during producing operations at a competitive rate, and monthly administration charge for Partnership activities.
During the production phase of operations, the Managing General Partner as the operator receives a monthly fee for each producing well based upon competitive industry rates for operations and field supervision and $75 for Partnership-related general and administrative expenses that include accounting, engineering and management. The Managing General Partner as operator bills non-routine operations and administration costs to the Partnership at its cost. The Managing General Partner may not benefit by inter-positioning itself between the Partnership and the actual provider of operator services. In no event is any consideration received for operator services duplicative of any consideration or reimbursement received under the Agreement.
The well operating charges cover all normal and regularly recurring operating expenses for the production, delivery and sale of natural gas and oil, such as:
·
well tending, routine maintenance and adjustment;
·
reading meters, recording production, pumping, maintaining appropriate books and records; and
·
preparing production related reports to the Partnership and government agencies.
The well supervision fees do not include costs and expenses related to:
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Notes to Financial Statements
·
the purchase or repairs of equipment, materials or third-party services;
·
the cost of compression and third-party gathering services, or gathering costs;
·
brine disposal; and
·
rebuilding of access roads.
These costs are charged at the invoice cost of the materials purchased or the third-party services performed.
Lease Operating Supplies and Maintenance Expense. The Managing General Partner and its affiliates may enter into other transactions with the Partnership for services, supplies and equipment during the production phase of the Partnership, and is entitled to compensation at competitive prices and terms as determined by reference to charges of unaffiliated companies providing similar services, supplies and equipment. Management believes these transactions were on terms no less favorable than could have been obtained from non-affiliated third parties.
(2) Under the Agreement, the Managing General Partner is responsible for gathering, compression, processing and transporting the gas produced by the Partnership to interstate pipeline systems, local distribution companies, and/or end-users in the area from the point the natural gas from the well is commingled with natural gas from other wells. In such a case, the Managing General Partner uses gathering systems already owned by PDC or PDC constructs the necessary facilities if no such line exists. In such a case, the Partnership pays a gathering, compression and processing fee directly to the Managing General Partner at competitive rates. If a third-party gathering system is used, the Partnership pays the gathering fee charged by the third-party gathering the gas.
(3) The Managing General Partner is reimbursed by the Partnership for all direct costs expended by them on the Partnership’s behalf for administrative and professional fees, such as legal expenses and audit fees.
(4) The Agreement provides for the allocation of cash distributions 80% to the Investors Partners and 20% to the Managing General Partner. The cash distributions during 2007, 2006 and 2005 include $5,816, $1,868 and $137, respectively, for Investor Partner units repurchased by PDC. For additional disclosure regarding the allocation of cash distributions, refer to Note 5, Partners’ Equity and Cash Distributions.
In accordance with the D&O Agreement, the Partnership paid its proportionate share of the cost of drilling and completing each well as follows:
a)
The cost of the prospect; and
b)
The intangible well costs for each well completed and placed in production, an amount equal to the depth of the well in feet at its deepest penetration as recorded by the drilling contractor multiplied by the “intangible drilling and completion cost” in the D&O Agreement, plus the actual extra completion cost of zones completed in excess of the cost of the first zone and actual additional costs incurred in the event that an intermediate or third string of surface casing is run, rig mobilization and trucking costs, the additional cost for directional drilling and drill stem testing, sidetracking, fishing of drilling tools; and
c)
The tangible costs of drilling and completing the partnership wells and of gathering pipelines necessary to connect the well to the nearest appropriate sales point or delivery point.
Additionally, refer to Note 4, Derivative Financial Instruments for derivative transactions between the Partnership and the Managing General Partner.
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Notes to Financial Statements
The Partnership holds record title in its name to the working interest in each well. PDC provides an assignment of working interest to the Partnership for the well bore prior to spudding the well and effective the date of the spudding of the well, in accordance with the D&O Agreement. Upon completion of the drilling of all of the Partnership wells, these assignments are recorded in the applicable county. Investor Partners rely on PDC to use its best judgment to obtain appropriate title to these working interests. Provisions of the Agreement relieve PDC from any error in judgment with respect to the waiver of title defects. PDC takes those steps it deems necessary to assure that title to the leases is acceptable for purposes of the Partnership.
Note 4 - Derivative Financial Instruments
The Partnership accounts for derivative financial instruments in accordance with SFAS No. 133, Accounting for Derivative Instruments and Certain Hedging Activities, as amended. Since the Managing General Partner does not designate any of the Partnership’s derivative as hedges, the Partnership’s derivative financial instruments did not qualify under the terms of Statement of Financial Accounting Standards (“SFAS”) No. 133, Accounting for Derivative Instruments and Certain Hedging Activities for the years ended December 31, 2007, 2006 and 2005. Accordingly, the Partnership recognizes all derivative instruments as either assets or liabilities on the Partnership’s balance sheets at fair value. Changes in the derivatives' fair values are recorded on a net basis in the Partnership’s statements of operations in “Commodity price risk management gain (loss), net.”
The Partnership is exposed to the effect of market fluctuations in the prices of natural gas and oil as they relate to natural gas and oil sales. Price risk represents the potential risk of loss from adverse changes in the market price of natural gas and oil commodities. The Managing General Partner employs established policies and procedures to manage the risks associated with these market fluctuations using commodity derivatives. Partnership policy prohibits the use of natural gas and oil derivative instruments for speculative purposes.
Concentration of Credit Risk. A significant component of the Partnership’s future liquidity is concentrated in derivative instruments that enables the Partnership to manage a portion of its exposure to price volatility from producing natural gas and oil. These arrangements expose the Partnership to credit risk. These contracts consist of collars, swaps and basis protection swaps. Credit risk represents the loss that the Partnership would incur if a counterparty fails to perform under its contractual obligations. 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 from counterparties. The Managing General Partner attempts to reduce credit risk by diversifying its counterparty exposure and entering into transactions with high-quality counterparties. When exposed to credit risk, the Managing General Partner analyzes the counterparties’ financial condition prior to entering into an agreement, establishes credit limits and monitors the appropriateness of those limits on an ongoing basis. Although the 2008 disruption in the credit market has had a significant impact on a number of financial institutions, through the date of filing, the Managing General Partner, PDC, has had no counterparty default losses. The Managing General Partner evaluates the credit risk of the Partnership’s assets from counterparties using relevant credit market default rates, giving consideration to amounts outstanding for each counterparty and the duration of each outstanding derivative position. Based on the Managing General Partner’s historical experience having no counterparty defaults during the years ended December 31, 2007, 2006 and 2005, the Partnership determined that the impact of the nonperformance of counterparties on the fair value of the Partnership’s derivative instruments was insignificant. At December 31, 2007, 2006 and 2005 no valuation allowance was recorded by the Partnership.
Risk Management Strategies. The Partnership’s results of operations and operating cash flows are affected by changes in market prices for natural gas and oil. To mitigate a portion of the exposure to adverse market changes, the Managing General Partner has entered into various derivative contracts. As of December 31, 2007, the Partnership's natural gas and oil derivative instruments were comprised of “collars” and “swaps.” These instruments generally consist of CIG-based contracts for Colorado gas production and NYMEX-based contracts for Colorado oil production. In addition to the collars, swaps and basis protection swaps currently allocated to the Partnership, the Managing General Partner previously utilized “floor” contracts to protect against natural gas and oil price declines in subsequent periods. Through October 31, 2007, the Partnership’s natural gas derivative instruments were comprised of natural gas floors and collars while its oil derivative instruments were comprised of oil floors.
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Notes to Financial Statements
·
“Collars” contain a fixed floor price (put) and ceiling price (call). If the index price falls below the fixed put strike price, PDC, as Managing General Partner, receives the market price from the purchaser and receives the difference between the put strike price and index price from the counterparty. If the index price exceeds the fixed call strike price, PDC, as Managing General Partner, receives the market price from the purchaser and pays the difference between the call strike price and index price to the counterparty. If the index price is between the call and put strike price, no payments are due to or from the counterparty.
·
“Swaps” are arrangements that guarantee a fixed price. If the index price is below the fixed contract price, PDC, as Managing General Partner, receives the market price from the purchaser and receives the difference between the index price and the fixed contract price from the counterparty. If the index price is above the fixed contract price, PDC, as Managing General Partner, receives the market price from the purchaser and pays the difference between the index price and the fixed contract price to the counterparty. If the index price and contract price are the same, no payment is due to or from the counterparty.
·
“Basis protection swaps” are arrangements that guarantee a price differential for natural gas from a specified delivery point. For CIG basis protection swaps, which traditionally have negative differentials to NYMEX, PDC, as Managing General Partner, receives a payment from the counterparty if the price differential is greater than the stated terms of the contract and pays the counterparty if the price differential is less than the stated terms of the contract. If the index price and contract price are the same, no payment is due to or from the counterparty.
·
“Floors” contain a floor price (put) whereby PDC, as Managing General Partner, receives the market price from the purchaser and the difference between the index price and floor strike price from the counterparty if the index price falls below the floor strike price, but receives no payment when the index price exceeds the floor strike price.
The Managing General Partner enters into derivative instruments for Partnership production to reduce the impact of price declines in future periods. While these derivatives are structured to reduce the 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 in the physical market. The Partnership believes the derivative instruments in place continue to be effective in achieving the risk management objectives for which they were intended although at December 31, 2007, they were below market due to high energy prices.
The table below summarizes the fair value of the Partnership’s open derivative positions as of December 31, as follows:
At December 31, 2007, 2006 and 2005, the maximum term for the derivative positions listed above is 12 months, 15 months and 15 months, respectively.
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PDC 2002-C LIMITED PARTNERSHIP
Notes to Financial Statements
The following table identifies the changes in the fair value of commodity based derivatives as reflected in the statements of operations:
Pursuant to SFAS No. 133, the Partnership’s derivatives do not qualify for designation as cash flow hedges. Changes in the fair value of these non-qualifying derivatives that occur prior to their maturity (i.e. temporary fluctuations in value) are reported currently in the Partnership’s statements of operations as unrealized gain (loss). “Commodity price risk management gain (loss), net,” includes realized and unrealized gains and losses on commodity based derivatives related to our natural gas and oil sales.
In addition to the “collar” and “swap” derivative instruments, the Managing General Partner previously utilized “floor” contracts to protect against natural gas and oil price declines in subsequent periods.
This table identifies the Partnership’s derivative positions related to gas sales activities in effect as of December 31, 2005, on the Partnership’s production.
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PDC 2002-C LIMITED PARTNERSHIP
Notes to Financial Statements
This table identifies the Partnership’s derivative positions related to natural gas and oil sales activities in effect as of December 31, 2006, on the Partnership’s production.
This table identifies the Partnership’s derivative positions related to natural gas and oil sales activities in effect as of December 31, 2007, on the Partnership’s production.
Note 5 - Partners’ Equity and Cash Distributions
Partners’ Equity
A Limited Partnership unit represents the individual interest of an individual investor partner in the Partnership. No public market exists or will develop for the units. While units of the Partnership are transferable, assignability of the units is limited, requiring the consent of the Managing General Partner. Further, individual investor partners may request that the Managing General Partner repurchase units pursuant to the Unit Repurchase Program.
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PDC 2002-C LIMITED PARTNERSHIP
Notes to Financial Statements
Allocation of Partners’ Interest
The table below summarizes the participation of the Investor Partners and the Managing General Partner in the revenues and costs of the Partnership.
(a)
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.
(b)
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.
(c)
These allocations are for tax reporting purposes and do not impact cash distributions or Partners’ equity.
(d)
Represents a one-time fee paid to the Managing General Partner on the day the Partnership was funded equal to 1-1/2% of total investor subscriptions.
(e)
Represents operating costs incurred after the completion of productive wells, including monthly per-well charges paid to the Managing General Partner.
(f)
The Managing General Partner receives monthly reimbursement from the Partnership for direct costs - general and administrative incurred by the Managing General Partner on behalf of the Partnership.
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PDC 2002-C LIMITED PARTNERSHIP
Notes to Financial Statements
The following table presents the allocation of net income to the Investor Partners and the Managing General Partner for each of the periods presented.
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 of operations beginning six 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 up to 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 the cash distributions made to the Investor Partners as a percentage of the investment, divided by the number of years since the closing of the Partnership less six months. For the years ended December 31, 2007, 2006 and 2005, no obligation of the Managing General Partner arose under this provision.
Unit Repurchase Provisions
Investor Partners may request that the Managing General Partner repurchase units at any time beginning with the third anniversary of the first cash distribution of the Partnership. The repurchase price is set at a minimum of four times the most recent twelve months of cash distributions from production. The Managing General Partner is conditionally obligated to purchase, in any calendar year, Investor Partner units aggregating to 10% of the initial subscriptions if requested by an individual investor partner, subject to its financial ability to do so and upon receipt of opinions of counsel that the repurchase will not cause the Partnership to be treated as a “publically traded partnership” or result in the termination of the Partnership for federal income tax purposes. Repurchase requests are fulfilled by the Managing General Partner on a first-come, first-serve basis.
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PDC 2002-C LIMITED PARTNERSHIP
Notes to Financial Statements
The following table presents information about the Managing General Partner’s limited partner unit repurchases under the unit repurchase program during the periods described below:
In addition to the above repurchase program, individual investor partners periodically offer and PDC repurchases units on a negotiated basis before the third anniversary of the date of the first cash distribution. The following table presents information about the Managing General Partner’s negotiated-basis limited partner unit repurchases during the periods described below:
Cash Distributions
The Agreement requires the Managing General Partner to distribute cash available for distribution not less frequently than quarterly. The Managing General Partner will determine and distribute, if funds are available for distribution, cash on a monthly basis. The Managing General Partner will make cash distributions of 80% to the Investor Partners and 20% to the Managing General Partner throughout the term of the Partnership. The Partnership has paid cash distributions each month since June 2003. Distributions for the years ended December 31, 2007, 2006, and 2005 were $757,720, $1,675,928, and $1,318,317, respectively.
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PDC 2002-C LIMITED PARTNERSHIP
Notes to Financial Statements
Note 6 - Natural Gas and Oil Properties
The Partnership is engaged solely in natural gas and oil activities, all of which are located in the continental United States. Drilling operations began upon funding in December 2002 with advances made to the Managing General Partner for all planned drilling and completion costs for the Partnership by December 31, 2002. Costs capitalized for these activities at December 31, 2007, 2006 and 2005 are as follows:
Included in “Development costs” are the estimated costs associated with the Partnership’s asset retirement obligations discussed in Note 7, Asset Retirement Obligations.
Note 7 - Asset Retirement Obligations
Changes in the carrying amount of asset retirement obligations associated with the Partnership’s working interest in natural gas and oil properties are as follows:
If the fair value of the estimated asset retirement obligation changes, an adjustment is recorded to both the asset retirement obligation and the asset retirement costs. New liabilities incurred during 2006 resulted from a change in estimates for plugging cost.
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PDC 2002-C LIMITED PARTNERSHIP
Notes to Financial Statements
Note 8 - Commitments and Contingencies
Colorado Royalty Settlement. On May 29, 2007, Glen Droegemueller, individually and as representative plaintiff on behalf of all others similarly situated, filed a class action complaint against the Managing General Partner in the District Court, Weld County, Colorado alleging that the Managing General Partner underpaid royalties on natural gas produced from wells operated by the Managing General Partner in parts of the State of Colorado (the “Droegemueller Action”). The plaintiff sought declaratory relief and to recover an unspecified amount of compensation for underpayment of royalties paid by the Managing General Partner pursuant to leases. The Managing General Partner moved the case to Federal Court on June 28, 2007. On October 10, 2008, the court preliminarily approved a settlement agreement between the plaintiffs and the Managing General Partner, on behalf of itself and the Partnership. Although the Partnership was not named as a party in the suit, the lawsuit states that this action relates to all wells operated by the Managing General Partner, which includes a majority of the Partnership’s 12 wells in the Wattenberg field. The portion of the settlement relating to the Partnership’s wells for all periods through December 31, 2007 that has been expensed by the Partnership is approximately $68,000. The entire settlement of $75,000 was deposited by the Managing General Partner into an escrow account on November 3, 2008. Notice of the settlement was mailed to members of the class action suit in the fourth quarter of 2008. The final settlement was approved by the court on April 7, 2009. Settlement distribution checks were mailed in July 2009. During September 2009, all settlement costs were paid to the Partners and any required judicial action from the settlement of the suit was implemented in this distribution.
Stormwater Permit. On December 8, 2008, the Managing General Partner received a Notice of Violation /Cease and Desist Order (the “Notice”) from the Colorado Department of Public Health and Environment (the “CDPHE”), related to the stormwater permit for the Garden Gulch Road. The Managing General Partner manages this private road for Garden Gulch LLC. The Managing General Partner is one of eight users of this road, all of which are natural gas and oil companies operating in the Piceance Basin of Colorado. Operating expenses, including amounts arising from this notice, if any, are allocated among the users of the road based upon their respective usage. The Partnership has 2 wells in this region. The Notice alleges a deficient and/or incomplete stormwater management plan, failure to implement best management practices and failure to conduct required permit inspections. The Notice requires corrective action and states that the recipient shall cease and desist such alleged violations. The Notice states that a violation could result in civil penalties up to $10,000 per day. The Managing General Partner’s responses were submitted on February 6, 2009, and April 8, 2009. Commencing in December 2009, the Managing General Partner entered negotiations with the CDPHE regarding this notice and continues to work to bring this matter to closure. Given the inherent uncertainty in administrative actions of this nature, the Managing General Partner is unable to predict the ultimate outcome of this administrative action at this time and therefore no amounts have been recorded on the Partnership’s financial records.
Derivative Contracts. The Partnership is exposed to the effect of market fluctuations in the prices of natural gas and oil. The Managing General Partner employs established policies and procedures to manage the risks associated with these market fluctuations by utilizing derivative instruments. Should the counterparties to the Managing General Partner’s derivative instruments not perform, the Partnership’s exposure to market fluctuations in commodity prices would increase significantly. Through the date of this filing, the Managing General Partner and the Partnership have had no counterparty defaults.
Note 9 - Restatement
PDC 2002-C Limited Partnership, which was funded and commenced operations on November 12, 2002, filed Annual Reports on Form 10-K for the period from November 12, 2002 (date of inception) to December 31, 2002 and for the twelve month periods ended December 31, 2003 and December 31, 2004 on April 4, 2003, March 29, 2004 and April 15, 2005, respectively. In addition, the Partnership filed Quarterly Reports on Form 10-Q for the quarters ended March 31, 2005 and June 30, 2005 on May 16, 2005 and July 22, 2005, respectively. Petroleum Development Corporation (hereafter the “Managing General Partner” or “PDC”), which conducts business under the name PDC Energy, is the Managing General Partner of the Partnership.
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PDC 2002-C LIMITED PARTNERSHIP
Notes to Financial Statements
In connection with preparation of the Partnership’s financial statements for the quarter ended September 30, 2005, the Managing General Partner undertook a review of its accounting for derivatives, asset retirement obligations and certain aspects of its accounting for natural gas and oil properties. As a result of PDC’s review, on November 11, 2005, the Managing General Partner and the Managing General Partner’s Audit Committee concluded, that because of errors identified in those financial statements, all of the Partnership’s previously issued financial statements should be restated and therefore should no longer be relied on. Additionally, in the course of preparing its financial statements for the year ended December 31, 2006, PDC identified additional accounting errors in its previously issued financial statements. As a result, PDC undertook an evaluation to determine whether previously issued financial statements for various limited partnerships, including the Partnership, which are subject to Securities and Exchange Commission (“SEC”) periodic reporting requirements, also contained material errors that required restatement. Until the evaluation was completed, the Partnership suspended periodic filings. Upon completion of the evaluation, the Managing General Partner and the Managing General Partner’s Audit Committee confirmed that the Partnership’s previously issued financial statements required restatement since the identified errors were deemed material to those financial statements.
This comprehensive annual report on Form 10-K includes financial statements for the years ended December 31, 2007, 2006 and 2005 and is the first periodic report the Partnership has filed with the SEC since identification of the accounting errors. The financial information presented in this Annual Report on Form 10-K includes audited financial statements for each of the years ended December 31, 2007, 2006 and 2005, as well as unaudited interim condensed financial information for each quarter in 2007, 2006 and 2005.
Since the unrecorded errors were deemed to be material to the previously issued financial statements for the period from November 12, 2002 (date of inception) to December 31, 2004 and these financial statements have not been presented herein, the Partnership effected the restatement by recording a cumulative effect adjustment to Partners’ equity at January 1, 2005 to correct prior period errors in the accounting for the following items:
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PDC 2002-C LIMITED PARTNERSHIP
Notes to Financial Statements
(1)
The accounts receivable error of $109,921 related to an adjustment to record actual for previously estimated natural gas and oil sales revenue of $133,795 offset by the reclassification of unrealized derivative gains of $23,874 to Due to Managing General Partner - derivatives at December 31, 2004.
(2)
The Due to Managing General Partner - other, net error of $2,097 related to the correction of over withheld production taxes of $100,979 recorded to natural gas and oil production costs together with $1,836 of accrued interest income thereon offset by the accrual of natural gas and oil production costs of $100,718 at December 31, 2004.
(3)
The oil and natural gas properties error of $2,287,393 related to the recognition of $1,774,861 recorded as a loss on impairment of oil and gas properties, a $563,360 reduction to accumulated DD&A in conjunction with recording the impairment and an increase of $50,828 related to the understatement of asset retirement obligations described in (7) below. The impairment expense resulted from the Partnership’s properties being divided into two separate fields for the purposes of assessment for impairment from the previously inappropriate one field approach. The impairment assessment for the Partnership’s Grand Valley Field in the Piceance Basin could not support the current carrying value of its wells based on undiscounted cash flows and thus an impairment occurred. The impairment resulted from the Partnership reducing the carrying value of this field to an amount equal to the future discounted cash flows.
(4)
The accumulated depreciation, depletion and amortization (DD&A) error related to a decrease in accumulated DD&A of $563,360 resulting from the impairment described in (3) above offset by a net $876,789 increase in accumulated DD&A resulting from an increase in DD&A expense related to the Partnership’s wells being erroneously assigned to one combined field instead of two separate fields offset by a decrease in DD&A expense, resulting from the impairment, which occurred in the first quarter of 2004.
(5)
The accounts payable and accrued expenses error of $55,216 is related to the reclassification of unrealized losses from accounts payable and accrued expenses to Due to Managing General Partner - Derivatives at December 31, 2004.
(6)
The Due to Managing General Partner - derivatives, error of $65,016 is related to a reclassification of $23,874 from accounts receivable and $55,215 from accounts payable to Due from Managing General Partner - derivatives, and recording realized derivative losses of $33,675 at December 31, 2004.
(7)
The asset retirement obligations error of $57,818 related to the Partnership’s use of an incorrect starting date for accretion resulting in an understatement of accretion asset retirement obligations of $6,990 and by the understatement of the cost of natural gas and oil properties of $50,828 at December 31, 2004.
(8)
The accumulated other comprehensive income error of $31,342 at December 31, 2004 related to the Partnership’s erroneous recording of unrealized losses on derivatives in accordance with hedge accounting as a component of Accumulated Other Comprehensive Income (AOCI). The Partnership determined that its derivatives did not qualify for hedge accounting and unrealized gains or losses should be recognized in the Statement of Operations at December 31, 2004. Upon restatement of the balance sheet at December 31, 2004, AOCI is eliminated and changes in fair value of open derivative positions are recorded in retained earnings.
There was no impact on total net cash provided by operating activities related to the cumulative effect adjustment to Partners’ equity at January 1, 2005 to correct prior period errors.
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PDC 2002-C LIMITED PARTNERSHIP
Supplemental Natural Gas and Oil Information - Unaudited
Costs Incurred in Natural Gas and Oil Property Development Activities
Natural gas and oil development costs include costs incurred to gain access to and prepare development well locations for drilling, to drill and equip developmental wells, recompletions and to provide facilities to extract, treat, gather and store natural gas and oil. The Partnership’s 14 productive developmental wells were drilled, completed and connected-to-line as of August 2003. There were no additional costs incurred with respect to natural gas and oil property development activities during 2007. There was an increase in development costs due to an asset retirement obligation increase of approximately $20,000 in 2006.
Net Proved Natural Gas and Oil Reserves
The Managing General Partner’s Reserve Engineering Department petroleum engineers performed the Partnership’s reserve evaluation for the years 2007, 2006 and 2005. These reserve estimates have been prepared in compliance with professional standards and the reserves definitions prescribed by the SEC that were in effect during the years 2007, 2006 and 2005, since the SEC’s Modernization of Oil and Gas Reporting final rule prohibits retroactive application of the new natural gas and oil industry disclosure standards. These new SEC natural gas and oil industry disclosure rules will be implemented by the Partnership in its Annual Report on Form 10-K as of December 31, 2009. For more information regarding the SEC’s Modernization of Oil and Gas Reporting and the major provisions likely to impact the both the determination of and disclosures for the Partnership’s natural gas and oil reserves when adopted as of December 31, 2009, see Note 2. Summary of Significant Accounting Policies−Recently Issued Accounting Standards to the Partnership’s financial statements accompanying this Annual Report.
Proved reserves are the estimated quantities of natural gas and oil that geologic and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Estimates of proved reserves may change, either positively or negatively, as additional information becomes available and as contractual, economic and political conditions change. The Partnership’s net proved reserve estimates have been adjusted as necessary to reflect all contractual agreements, royalty obligations and interests owned by others at the time of the estimate.
Proved developed reserves are the quantities of natural gas and oil expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped reserves are those reserves expected to be recovered from existing wells where a relatively major expenditure is required for completion. The Partnership’s proved undeveloped reserves relate to future well recompletions in the Codell formation of the Wattenberg Field. These recompletions, which are expected to start in 2011 or later, as part of the well development plan, generally occur five to 10 years after initial well drilling. Funding for these recompletions are expected to be provided by withholding distributions from investors beginning in October 2010. Currently, the Partnership expects recompletion activities to be completed through approximately 2014. The time frame of recompletion activity is impacted by individual well decline curves as well as the objective to maximize the financial impact of the recompletion.
The following Partnership reserve estimates present the estimate of the proved gas and oil reserves and net cash flows of the Partnership’s properties all of which are located in the United States. The Managing General Partner’s management emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries are more imprecise than those of producing gas and oil properties. Accordingly, the estimates are expected to change as future information becomes available.
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PDC 2002-C LIMITED PARTNERSHIP
Supplemental Natural Gas and Oil Information - Unaudited
Below are the net quantities of net proved reserves of the Partnership’s Properties as of December 31, 2007, 2006 and 2005.
Definitions used throughout Supplemental Natural Gas and Oil Information - Unaudited:
·
Bbl - One barrel or 42 U.S. gallons liquid volume
·
MBbl - One thousand barrels
·
Mcf - One thousand cubic feet
·
Mcfe - One thousand cubic feet of gas equivalents, based on a ratio of 6 Mcf for each barrel of oil, which reflects the relative energy content
·
MMcf - One million cubic feet
·
MMcfe - One million cubic feet of gas equivalents
At December 31, 2007, the Partnership recorded an upward revision to its previous estimate of proved reserves of approximately 105 MMcf of natural gas and an upward revision to its previous estimate of proved reserves of approximately 6 MBbl of oil. The revision due to positive commodity price changes resulted in an increase to natural gas proved reserves of approximately 89 MMcf. The revision due to changes in increased well performance resulted in an increase to natural gas proved reserves of approximately 16 MMcf and an increase to oil proved reserves of approximately 6 MBbl.
At December 31, 2006, the Partnership recorded a downward revision to its previous estimate of proved reserves of approximately 91 MMcf of natural gas and approximately 10 MBbl of oil. The revision was primarily due to negative commodity price changes resulting in a decrease of 94 MMcf of gas combined with a decrease of 10 MBbl of oil due to deteriorated well performance offset by an increase of 3 MMcf of gas due to increased well performance, and its related revision to the wells’ decline curves.
At December 31, 2005, the Partnership recorded a downward revision to its previous estimate of proved reserves of approximately 208 MMcf of gas and approximately 4 MBbl of oil. The revision was primarily due to decreases of 250 MMcf of gas and 4 MBbl of oil due to deteriorated well performance and its related downward revision to the wells’ decline curves and an increase of 42 MMcf of gas due to positive commodity price changes.
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PDC 2002-C LIMITED PARTNERSHIP
Supplemental Natural Gas and Oil Information - Unaudited
Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Natural Gas and Oil Reserves
Summarized in the following table is information with respect to the standardized measure of discounted future net cash flows relating to proved natural gas and oil reserves. Future cash inflows are computed by applying year-end prices of natural gas and oil, consistent with professional standards and the SEC natural gas and oil industry rules and regulations, in effect during the years 2007, 2006 and 2005, 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, including production - related taxes, primarily severance and property, assuming continuation of existing economic conditions. Future development costs include the development costs related to recompletions of Wattenberg Field wells drilled in the Codell formation, as described in Item 1, Business-Plan of Operations. Since Partnership taxable income is reported in the separate tax returns of individual investor partners, no future estimated income taxes are computed and presented herein. The SEC’s Modernization of Oil and Gas Reporting will be implemented by the Partnership in its Annual Report on Form 10-K as of December 31, 2009, since retroactive application is prohibited. For more information regarding this new industry rulemaking and the major provisions likely to impact disclosures for the Partnership’s natural gas and oil reserves, including the standardized measure of discounted future net cash flows, when adopted as of December 31, 2009 see Note 2. Summary of Significant Accounting Policies−Recently Issued Accounting Standards to the Partnership’s financial statements accompanying this Annual Report.
The following table summarizes the principal sources of change in the standardized measure of discounted future estimated net cash flows for the years ended December 31, 2007, 2006 and 2005:
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 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.
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PDC 2002-C LIMITED PARTNERSHIP
Supplemental Natural Gas and Oil Information - Unaudited
The estimated present value of future cash flows relating to proved reserves is extremely sensitive to prices used at any measurement period. The average December 31 price used for each commodity, consistent with professional standards and SEC rules and regulations, at December 31, 2007, 2006 and 2005 is presented below.
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PDC 2002-C LIMITED PARTNERSHIP
Condensed Quarterly Balance Sheets
(Unaudited)
*Derived from audited December 31, 2007 balance sheet contained in the Partnership’s accompanying financial statements for the year ended December 31, 2007, included in this report.
See accompanying notes to unaudited condensed quarterly financial statements.
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PDC 2002-C LIMITED PARTNERSHIP
Condensed Quarterly Balance Sheets
(Unaudited)
* Derived from audited December 31, 2006 balance sheet contained in the Partnership’s accompanying financial statements for the year ended December 31, 2006, included in this report.
See accompanying notes to unaudited condensed quarterly financial statements.
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PDC 2002-C LIMITED PARTNERSHIP
Condensed Quarterly Balance Sheets
(Unaudited)
*Derived from audited December 31, 2005 balance sheet contained in the Partnership’s accompanying financial statements for the year ended December 31, 2005, included in this report.
See accompanying notes to unaudited condensed quarterly financial statements.
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PDC 2002-C LIMITED PARTNERSHIP
Condensed Quarterly Statements of Operations
(Unaudited)
See accompanying notes to unaudited condensed quarterly financial statements.
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PDC 2002-C LIMITED PARTNERSHIP
Condensed Quarterly Statements of Operations
(Unaudited)
See accompanying notes to unaudited condensed quarterly financial statements.
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PDC 2002-C LIMITED PARTNERSHIP
Condensed Quarterly Statements of Operations
(Unaudited)
See accompanying notes to unaudited condensed quarterly financial statements.
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PDC 2002-C LIMITED PARTNERSHIP
Condensed Interim Statements of Cash Flows
(Unaudited)
See accompanying notes to unaudited condensed quarterly financial statements.
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PDC 2002-C LIMITED PARTNERSHIP
Condensed Interim Statements of Cash Flows
(Unaudited)
See accompanying notes to unaudited condensed quarterly financial statements.
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PDC 2002-C LIMITED PARTNERSHIP
Condensed Interim Statements of Cash Flows
(Unaudited)
See accompanying notes to unaudited condensed quarterly financial statements.
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PDC 2002-C LIMITED PARTNERSHIP
Notes to Unaudited Condensed Quarterly Financial Statements
Note 1 - Basis of Presentation
The PDC 2002-C Limited Partnership (the “Partnership” or the “Registrant”) was organized as a limited partnership on June 3, 2002, in accordance with the laws of the State of West Virginia for the purpose of engaging in the exploration and development of natural gas and oil properties and commenced business operations with its funding on November 12, 2002, upon completion of its sale of Partnership units. Petroleum Development Corporation (hereafter the “Managing General Partner” or “PDC”), which conducts business under the name PDC Energy, is the Managing General Partner of the Partnership.
The accompanying interim financial statements have been prepared without audit in accordance with accounting principles generally accepted in the United States of America for interim financial information and the instructions to Form 10-Q and Regulation S-X, Rule 8-03(a) and (b) of the Securities and Exchange Commission (“SEC”). Accordingly, pursuant to certain rules and regulations, certain notes and other financial information included in the accompanying audited financial statements have been condensed or omitted. In the Partnership’s opinion, the accompanying interim financial statements contain all adjustments (consisting of only normal recurring adjustments) necessary to fairly state the Partnership's financial position and results of operations for the periods presented.
Note 2 - Transactions with Managing General Partner and Affiliates
The Managing General Partner transacts business on behalf of the Partnership. Revenues and other cash inflows received on behalf of the Partnership are distributed to the Partners net of (after deducting) corresponding operating costs and other cash outflows incurred on behalf of the Partnership. The fair value of the Partnership’s portion of unexpired derivative instruments is recorded on the balance sheet under the captions “Due from Managing General Partner-derivatives” in the case of net unrealized gains or “Due to Managing General Partner-derivatives” in the case of net unrealized losses. Realized gains or losses from derivative transactions that have not yet been distributed to the Partnership are included in the balance sheet caption “Due from Managing General Partner-other, net” or “Due to Managing General Partner-other, net,” respectively.
The following table presents undistributed natural gas and oil revenues, included in the balance sheet caption “Due from Managing General Partner - other, net,” that were collected by the Managing General Partner from the Partnership’s customers, as of end of the periods described below:
All other unsettled transactions between the Partnership and the Managing General Partner are also recorded net on the balance sheet under the caption “Due from (to) Managing General Partner - other, net.”
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PDC 2002-C LIMITED PARTNERSHIP
Notes to Unaudited Condensed Quarterly Financial Statements
The following table presents transactions with the Managing General Partner and its affiliates during the quarters ended March 31, June 30, September 30 and December 31, for the years 2007, 2006 and 2005. “Well operations and maintenance” and “Gathering, compression and processing fees” are included in “Production and operating costs” on the Statements of Operations.
*Cash distributions started in July 2003. Cash distributions presented above include equity cash distributions on Investor Partner units repurchased by PDC. The following table presents these equity cash distributions associated to limited partnership units repurchased by PDC, for the periods described:
Note 3 - Derivative Financial Instruments
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 natural gas and oil sales. These instruments consisted of Colorado Interstate Gas Index, or CIG, based contracts for Colorado natural gas production and New York Mercantile Exchange, or NYMEX, based floors for the Partnership’s Colorado oil 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 receives for the volume of natural gas and oil to which the derivative relates.
In addition to the collars, swaps and basis protection swaps currently allocated to the Partnership, the Managing General Partner previously utilized “floor” contracts to protect against natural gas and oil price declines in subsequent periods. Through October 31, 2007, the Partnership’s natural gas derivative instruments were comprised of natural gas floors and collars while its oil derivative instruments were comprised of oil floors.
·
“Floors” contain a floor price (put) whereby PDC, as Managing General Partner, receives the market price from the purchaser and the difference between the index price and floor strike price from the counterparty if the index price falls below the floor strike price, but receives no payment when the index price exceeds the floor strike price.
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PDC 2002-C LIMITED PARTNERSHIP
Notes to Unaudited Condensed Quarterly Financial Statements
·
“Collars” contain a fixed floor price (put) and ceiling price (call). If the index price falls below the fixed put strike price, PDC, as Managing General Partner, receives the market price from the purchaser and receives the difference between the put strike price and index price from the counterparty. If the index price exceeds the fixed call strike price, PDC, as Managing General Partner, receives the market price from the purchaser and pays the difference between the call strike price and index price to the counterparty. If the index price is between the call and put strike price, no payments are due to or from the counterparty.
Upon the expiration of the NYMEX-based oil “floor” contract in October 31, 2007, PDC entered into a NYMEX-based oil “swap” contract in which the Managing General Partner received a fixed price for the hedged commodity and paid a floating market price to the counterparty. The fixed-price payment and the floating-price payment were netted, which resulted in a net amount due to or from the counterparty.
The following table summarizes the Partnership’s open derivative positions as of March 31, June 30 and September 30, as follows:
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PDC 2002-C LIMITED PARTNERSHIP
Notes to Unaudited Condensed Quarterly Financial Statements
The following table identifies the changes in the fair value of commodity based derivatives as reflected in the Partnership’s statements of operations for the three-months ended March 31, June 30, September 30 and December 31 for the years indicated:
Note 4 - Capitalized Costs Relating to Natural Gas and Oil Activities
The Partnership is engaged solely in natural gas and oil activities, all of which are located in the continental United States. Drilling operations began upon funding in November 2002 with advances made to the Managing General Partner for all planned drilling and completion costs for the Partnership made in November 2002. Costs capitalized for these activities are as follows:
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PDC 2002-C LIMITED PARTNERSHIP
Notes to Unaudited Condensed Quarterly Financial Statements
Note 5 - Commitments and Contingencies
Colorado Royalty Settlement. On May 29, 2007, Glen Droegemueller, individually and as representative plaintiff on behalf of all others similarly situated, filed a class action complaint against the Managing General Partner in the District Court, Weld County, Colorado alleging that the Managing General Partner underpaid royalties on natural gas produced from wells operated by the Managing General Partner in parts of the State of Colorado (the “Droegemueller Action”). The plaintiff sought declaratory relief and to recover an unspecified amount of compensation for underpayment of royalties paid by the Managing General Partner pursuant to leases. The Managing General Partner moved the case to Federal Court on June 28, 2007. On October 10, 2008, the court preliminarily approved a settlement agreement between the plaintiffs and the Managing General Partner, on behalf of itself and the Partnership. Although the Partnership was not named as a party in the suit, the lawsuit states that this action relates to all wells operated by the Managing General Partner, which includes a majority of the Partnership’s 12 wells in the Wattenberg field. The portion of the settlement relating to the Partnership’s wells for all periods through December 31, 2007 that has been expensed by the Partnership in is approximately $68,000. This entire settlement of $75,000 was deposited by the Managing General Partner into an escrow account on November 3, 2008. Notice of the settlement was mailed to members of the class action suit in the fourth quarter of 2008. The final settlement was approved by the court on April 7, 2009. Settlement distribution checks were mailed in July 2009. During September 2009, all settlement costs were paid to the Partners and any required judicial action from the settlement of the suit was implemented in this distribution.
Stormwater Permit. On December 8, 2008, the Managing General Partner received a Notice of Violation /Cease and Desist Order (the “Notice”) from the Colorado Department of Public Health and Environment (the “CDPHE”), related to the stormwater permit for the Garden Gulch Road. The Managing General Partner manages this private road for Garden Gulch LLC. The Managing General Partner is one of eight users of this road, all of which are natural gas and oil companies operating in the Piceance Basin of Colorado. Operating expenses, including amounts arising from this notice, if any, are allocated among the users of the road based upon their respective usage. The Partnership has 2 wells in this region. The Notice alleges a deficient and/or incomplete stormwater management plan, failure to implement best management practices and failure to conduct required permit inspections. The Notice requires corrective action and states that the recipient shall cease and desist such alleged violations. The Notice states that a violation could result in civil penalties up to $10,000 per day. The Managing General Partner’s responses were submitted on February 6, 2009, and April 8, 2009. Commencing in December 2009, the Managing General Partner entered negotiations with the CDPHE regarding this notice and continues to work to bring this matter to closure. Given the inherent uncertainty in administrative actions of this nature, the Managing General Partner is unable to predict the ultimate outcome of this administrative action at this time and therefore no amounts have been recorded on the Partnership’s financial records.
Derivative Contracts. The Partnership is exposed to the effect of market fluctuations in the prices of natural gas and oil. The Managing General Partner employs established policies and procedures to manage the risks associated with these market fluctuations by utilizing derivative instruments. Should the counterparties to the Managing General Partner’s derivative instruments not perform, the Partnership’s exposure to market fluctuations in commodity prices would increase significantly. Through the date of this filing, the Managing General Partner and the Partnership have had no counterparty defaults.
Note 6 - Restatement
PDC 2002-C Limited Partnership (the "Partnership" or the "Registrant"), which was funded on and commenced operations on November 12, 2002, filed Annual Reports on Form 10-K for the period from November 12, 2002 (date of inception) and for the twelve month periods ended December 31, 2003 and December 31, 2004 on April 4, 2003, March 29, 2004 and April 15, 2005, respectively. In addition, the Partnership filed Quarterly Reports on Form 10-Q for the quarters ended March 31, 2005 and June 30, 2005 on May 16, 2005 and July 22, 2005, respectively.
In connection with preparation of the Partnership’s financial statements for the quarter ended September 30, 2005, the Managing General Partner undertook a review of its accounting for derivatives, asset retirement obligations and certain aspects of its accounting for natural gas and oil properties. As a result of PDC’s review, on November 11, 2005, the Managing General Partner and the Managing General Partner’s Audit Committee concluded that because of errors identified in those financial statements all of the Partnership’s previously issued financial statements should be restated and therefore should no longer be relied on. Additionally, in the course of preparing its financial statements for the year ended December 31, 2006, PDC identified additional accounting errors in its previously issued financial statements. As a result, PDC undertook an evaluation to determine whether previously issued financial statements for various limited partnerships, including the Partnership, which are subject to Securities and Exchange Commission, or SEC, periodic reporting requirements, also contained material errors that required restatement. Until the evaluation was completed, the Partnership suspended periodic filings. Upon completion of the evaluation, the Managing General Partner and the Managing General Partner’s Audit Committee confirmed that the Partnership’s previously issued financial statements required restatement since the identified errors were deemed material to those financial statements.
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PDC 2002-C LIMITED PARTNERSHIP
Notes to Unaudited Condensed Quarterly Financial Statements
This comprehensive annual report on Form 10-K includes financial statements for the years ended December 31, 2005, 2006 and 2007 and is the first periodic report the Partnership has filed with the SEC since identification of the accounting errors. The financial information presented in this Annual Report on Form 10-K includes audited financial statements for each of the years ended December 31, 2005, 2006 and 2007, as well as unaudited interim condensed financial information for each quarter in 2005, 2006 and 2007.
Since the unrecorded errors were deemed to be material to the previously issued financial statements for the period from November 12, 2002 (date of inception) to December 31, 2004 and these financial statements have not been presented herein, the Partnership effected the restatement by recording a cumulative effect adjustment to Partners’ equity at January 1, 2005, to correct prior period errors in the accounting for the following items:
See Note 9, Restatement, to the Partnership’s accompanying annual financial statements included in this report for additional information related to these errors.
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PDC 2002-C LIMITED PARTNERSHIP
Notes to Unaudited Condensed Quarterly Financial Statements
Restatement of Unaudited Interim Condensed Financial Statements for the Three Months Ended March 31, 2005
Additionally, this comprehensive Annual Report includes the restatement of the Partnership's unaudited interim condensed financial statements for the three month period ended March 31, 2005, which have been restated to properly reflect the understatement of natural gas and oil sales, the over-withholding of production taxes from revenue distributions made to the limited partners of the Partnership, the correction of DD&A, the correction of accretion of asset retirement obligations, the correction of accounts payable and accounting for the Partnership's derivatives.
The following table reflects the effects of the restatements on the Condensed Balance Sheet as of March 31, 2005 and the Condensed Statements of Operations for the three month period ended March 31, 2005:
(1)
The Partnership determined that there was an error in the Partnership’s accounting for derivatives for improperly using hedge accounting and for using an incorrect derivative valuation methodology. Correction of this error required recognition in the statement of operations of a realized and an unrealized derivative loss of $47,632, and reclassification of a realized loss of $41,623 previously included in natural gas and oil sales during the first quarter of 2005. The correction also resulted in changes to balance sheet captions as follows: an increase in “Accounts receivable” of $31,139; an increase in “Due from Managing General Partner - derivatives” (short term) of $10,596; a decrease in “Due from Managing General Partner - other, net” of $7,950; an increase in “Due from Managing General Partner - derivatives” (long term) of $938; an increase in “Accounts payable and accrued expenses” of $31,186; an increase in “Due to Managing General Partner - derivatives” (short term) of $17,224; an increase in “Due to Managing General Partner - derivatives” (long term) of $319; and an increase in the “Accumulated other comprehensive loss” of $7,997.
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PDC 2002-C LIMITED PARTNERSHIP
Notes to Unaudited Condensed Quarterly Financial Statements
(2)
The Partnership determined that natural gas and oil revenues had been overstated for the three month period ended March 31, 2005 by $59,205 and production and operating costs were overstated by $15,687. The reversal of the previously recorded incorrect natural gas and oil revenues accrual and the recording of the correct accrual resulted in changes to the Balance Sheet captions as follows: a decrease in “Accounts receivable” of $66,964; an increase in “Due from Managing General Partner - other, net” of $60,567; and an increase in “Accounts payable and accrued expenses” of $37,121.
(3)
PDC determined that it had also over-withheld production taxes from distributions to the limited partners of the Partnership during 2005. The total error for the production tax over-withholding was $20,895, including $1,546 in forgone interest income, during the three month period ended March 31, 2005. Properly recording these costs resulted in an increase in “Due from Managing General Partner - other, net” of $20,895.
(4)
The “Depreciation, depletion and amortization” error related to Partnership’s wells being assigned to one combined field instead of two separate fields. This resulted in the recognition of impairment expense at December 31, 2004, which is included in the restatement adjustment to Partners’ equity at January 1, 2005. The revised calculation of DD&A using two fields resulted in additional DD&A expense of $8,835 during the first quarter of 2005 with a corresponding decrease in “Natural gas and oil properties, net” at March 31, 2005 of $8,835.
(5)
The Partnership also used an incorrect starting date for accretion of the asset retirement obligation resulting in an understatement of “Accretion of asset retirement obligations” of $931 offset by a reduction in “Direct costs - general and administration” of $104. Recording the additional accretion resulted in an increase to the Balance Sheet caption “Asset retirement obligations” of $827.
(6)
Represents the reclassification of $233,288 of “Accounts receivable” for undistributed natural gas and oil revenues collected by the Managing General Partner from the Partnership’s customers from “Accounts receivable” to “Due from Managing General Partner - other, net” offset by the reclassification of $33,723 of “Accounts payable and accrued expenses” for natural gas and oil production costs to “Due from Managing General Partner - other, net” to conform to the 2007 current year presentation.
Although net income for the quarter ended March 31, 2005 decreased by $20,623 due to the restatement, net cash provided by operating activities remained unchanged for the quarter.
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PDC 2002-C LIMITED PARTNERSHIP
Notes to Unaudited Condensed Quarterly Financial Statements
Restatement of Unaudited Interim Condensed Financial Statements for the Three Months Ended June 30, 2005
This comprehensive Annual Report also includes the restatement of the Partnership's unaudited interim condensed financial statements for the three month period ended June 30, 2005, which have been restated to properly reflect the understatement of natural gas and oil sales, the over-withholding of production taxes from revenue distributions made to the limited partners of the Partnership, the correction of DD&A, the correction of accretion of asset retirement obligations, the correction of accounts payable and accounting for the Partnership's derivatives.
The following table reflects the effects of the restatements on the Condensed Balance Sheet as of June 30, 2005 and the Condensed Statements of Operations for the three month period ended June 30, 2005:
(1)
The Partnership determined that there was an error in the Partnership’s accounting for derivatives for improperly using hedge accounting and for using an incorrect derivative valuation methodology. Correction of this error required recognition in the statement of operations of a realized and an unrealized derivative gain of $12,515, and reclassification of a realized loss of $14,854 previously included in natural gas and oil sales during the second quarter of 2005. The correction also resulted in changes to balance sheet captions as follows: an increase in “Accounts receivable” of $6,571; an increase in “Due from Managing General Partner - derivatives” (short term) of $7,807; a decrease in “Due from Managing General Partner - other, net” of $14,854; a decrease in “Due from Managing General Partner - derivatives” (long term) of $573; a decrease in “Accounts payable and accrued expenses” of $20,642; a decrease in “Due to Managing General Partner - derivatives” (short term) of $30,153; an increase in “Due to Managing General Partner - derivatives” (long term) of $2,068; and a decrease in the “Accumulated other comprehensive loss” of $20,309.
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(2)
The Partnership determined that natural gas and oil revenues had been understated for the three month period ended June 30, 2005 by $14,201 and production and operating costs were understated by $1,766. The reversal of the previously recorded incorrect natural gas and oil revenues accrual and the recording of the correct accrual resulted in changes to the Balance Sheet captions as follows: an increase in “Accounts receivable” of $20,805; an increase in “Due from Managing General Partner - other, net” of $328; and an increase in “Accounts payable and accrued expenses” of $8,698.
(3)
PDC determined that it had over-withheld production taxes from distributions to the limited partners of the Partnership during 2005. The total error for the production tax over-withholding was $22,646, including $1,675 in forgone interest income, during the three month period ended June 30, 2005. Properly recording these costs resulted in an increase in “Due from Managing General Partner - other, net” of $22,646.
(4)
The “Depreciation, depletion and amortization” error related to Partnership’s wells being assigned to one combined field instead of two separate fields. The revised calculation of DD&A using two fields resulted in an increase to DD&A expense of $10,121 during the second quarter of 2005 with a corresponding decrease in “Natural gas and oil properties, net” at June 30, 2005 of $10,121.
(5)
The Partnership also used an incorrect starting date for accretion of the asset retirement obligation resulting in an understatement of “Accretion of asset retirement obligations” of $945 offset by a decrease in “Direct costs - general and administration” $104. Recording the additional accretion resulted in an increase to the Balance Sheet caption “Asset retirement obligations” of $841.
(6)
Represents the reclassification of $308,558 of “Accounts receivable” for undistributed natural gas and oil revenues collected by the Managing General Partner from the Partnership’s customers from “Accounts receivable” to “Due from Managing General Partner - other, net” accompanied by the reclassification of $34,318 from “Accounts payable and accrued expenses” for production and operating costs to “Due from Managing General Partner - other, net” to conform to the 2007 presentation.
Although net income for the quarter ended June 30, 2005 increased by $51,488 due to the restatement, net cash provided by operating activities remained unchanged for the quarter.