UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, DC
FORM 10/A
(Amendment No. 1)
GENERAL FORM FOR REGISTRATION OF SECURITIES
PURSUANT TO SECTION 12(b) OR 12(g) OF
THE SECURITIES EXCHANGE ACT OF 1934
Rockies Region 2006 Limited Partnership
(Exact Name of Registrant as Specified in Its Charter)
| West Virginia | | 20-5149573 |
| (State or Other Jurisdiction of Incorporation or Organization) | | (IRS Employer Identification No.) |
| | 120 Genesis Boulevard, Bridgeport, West Virginia | 26330 | |
| | (Address of Principal Executive Offices) | (Zip Code) | |
Registrant's telephone number, including area code: 304-842-6256
Securities to be registered pursuant to Section 12(b) of the Act:
| Title of Each Class to be so Registered | | Name of Each Exchange on Which Each Class is to be Registered |
Securities to be registered pursuant to Section 12(g) of the Act:
Limited Partnership Interests
(Title of Class)
General Partnership Interests
(Title of Class)
Form 10/A
Rockies Regional 2006 Limited Partnership
| | | Page |
| Item 1 | | 1 |
| Item 1A | | 9 |
| Item 2 | | |
| | | 16 |
| | | 17 |
| | | 25 |
| Item 3 | | 26 |
| Item 4 | | 27 |
| Item 5 | | 29 |
| Item 6 | | 33 |
| Item 7 | | 33 |
| Item 8 | | 36 |
| Item 9 | | 36 |
| Item 10 | | 41 |
| Item 11 | | 41 |
| Item 12 | | 45 |
| Item 13 | | 46 |
| Item 14 | | 46 |
| Item 15 | | 46 |
| 47 |
| F-1 |
INFORMATION REQUIRED IN REGISTRATION STATEMENT
Rockies Region 2006 Limited Partnership (the "Partnership" or the "Registrant") was organized as a limited partnership on July 20, 2006 under the West Virginia Uniform Limited Partnership Act. Upon completion of a private placement of its securities on September 7, 2006, the Partnership was funded and commenced its business operations. The Partnership was funded with initial contributions of $89,940,527 from 2,022 limited and general partners, excluding the managing general partner (collectively, the “Investor Partners”) and a cash contribution of $38,912,342 from Petroleum Development Corporation (“PDC”), the Managing General Partner. After payment of syndication costs of $9,084,039 and a one-time management fee to the Managing General Partner of $1,349,108, the Partnership had available cash of $118,419,722 to commence Partnership activities. The Partnership has drilled, owns and operates natural gas and oil wells located in Colorado and North Dakota and will produce and sell natural gas and oil from these wells. As of September 30, 2007, the Partnership has conducted the following drilling activities:
| | Colorado | | North Dakota |
| Development wells: (a) | | | |
| Drilled, completed and producing | 86 | | 4 |
| Dry holes | 1 | | - |
| Exploratory wells: (b) | | | |
| Drilled , completed and producing | - | | 1 |
| Dry holes | 3 | | 2 |
| Total Wells Drilled | 90 | | 7 |
| a. | A development well is a well that is drilled close to and into the same formation as wells which have already produced and sold oil or natural gas. |
| b. | An exploratory well is one which is drilled in an area where there has been no oil or natural gas production, or a well which is drilled to a previously untested or non-producing zone in an area where there are wells producing from other formations. |
The ninety-seven wells in the table above are the only wells to be drilled by the Partnership since all of the funds raised in the Partnership offering have been utilized.
Since all of the Partnership’s wells have been drilled as of September 30, 2007 and are producing oil and/or natural gas, the Partnership’s business plan for the remainder of this year and for next year will be to produce and sell the oil and natural gas from the Partnership’s wells, and to make distributions to the partners as outlined in the Partnership’s cash distribution policy in “Item 9, Market Price of and Dividends on the Registrant's Common Equity and Related Stockholder Matters.”
The address and telephone number of the Partnership and Petroleum Development Corporation ("PDC"), the Managing General Partner of the Partnership, are 120 Genesis Boulevard, Bridgeport, West Virginia 26330 and (304) 842-6256.
Drilling Activities
The Partnership has invested in the drilling of ninety-seven prospects on which it has drilled an equal number of wells. The Partnership’s working interests in these wells is generally 99.9%, except for a few wells in which the Partnership’s working interest ranges from 63.49% to 100.00%. As indicated by the table above, ninety-one wells are completed and producing.
The Partnership drilled sixty-four of its Colorado wells to target the Codell formation, or deeper, in the Wattenberg Field, Colorado, of which one well was determined to be a developmental dry hole and sixty-three wells have been successfully completed and are in production. PDC plans to recomplete most of the wells producing from the Codell formation in the Wattenberg Field wells after they have been in production for five years or more, although the exact timing may be delayed or accelerated due to changing commodity prices. A recompletion consists of a second fracture treatment of the formation similar to the fracture treatment used when the well is first completed. PDC and other producers have found that the recompletions typically increase the production rate and recoverable reserves of the wells significantly. The cost of recompleting a well producing from the Codell formation is about one third of the cost of a new well (currently about $200,000 for the recompletion). PDC will charge the Partnership for the direct costs of recompletions, and will pay its proportionate share of costs based on the operating costs sharing ratios of the Partnership. The Partnership may borrow the funds necessary to pay for the recompletions, and payment for those borrowings will be made from the Partnership production proceeds. Any such borrowings will be non-recourse to the Investor Partners in the Partnership.
PDC's experience to date with Codell recompletions has generally been very good, although not all recompletions have been successful. If the Partnership participates in unsuccessful recompletions, it may have additional costs without having sufficient incremental revenue to pay those costs, which would reduce the funds available for distribution to the Investor Partners and PDC.
Title to Properties
The Partnership holds record title in its name to leases. PDC has assigned its interest in the leases to the Partnership. Partnership investors rely on PDC to use its best judgment to obtain appropriate title to leases. Provisions of the limited partnership 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. The leases, having been assigned to the Partnership, are not subject to claims by creditors of PDC. For additional information, see “Item 3, Properties – Title to Properties,” below.
Partnership Prospects
The Partnership has eighty-seven development wells and three exploratory wells in Colorado and four development wells and three exploratory well in North Dakota. Of the wells in Colorado, sixty-four of the developmental wells and the three exploratory wells are located in the Wattenberg Field (DJ Basin) and twenty-three are located in the Grand Valley Field (Piceance Basin). Four of the wells drilled in the Wattenberg Field were determined to be dry holes. The details of these prospect areas are further outlined below.
Colorado. 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 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 gas. Wells in the 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 in most wells will be the Codell sand which produces a combination of natural gas and oil.
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 and water. 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 gas reserves and production are divided into these numerous smaller zones.
North Dakota. The Partnership had drilled wells in the western portion of the Williston Basin, located in northwestern North Dakota. Successful wells drilled in this area are expected to product oil and natural gas, with some associated produced water. Wells drilled in this area target hydrocarbon reserves in the Nesson and/or Bakken interval. Development will encompass horizontal drilling within the target zone(s) with single or multi-lateral horizontal well bores of 4,000 feet or more. True vertical well depths may vary from 5,000 to 8,000 feet with total measured well depths, including lateral well bore(s) ranging from approximately 10,000 to 20,000 feet.
Well Operations
As operator, PDC represents the Partnership in all operations matters, including the drilling, testing, completion and equipping of wells and the sale of the Partnership’s oil and gas production from wells. PDC is the operator of all of the wells in which the partnership owns an interest.
PDC, in some cases, provides equipment and supplies, and performs salt water disposal services and other services for the Partnership. PDC sells equipment to the Partnership as needed in the drilling or completion of Partnership wells. All equipment and services are sold at the lesser of cost or competitive prices in the area of operations.
Gas Pipeline and Transmission. PDC has drilled all of the Partnership's wells in Colorado and North Dakota in the vicinity of transmission pipelines and gathering systems. PDC believes there are sufficient transmission pipelines and gathering systems for the Partnership's natural gas production, subject to some seasonal curtailment. The cost, timing and availability of gathering pipeline connections and service varies from area to area, well to well, and over time. In selecting prospects for the Partnership, PDC included in its evaluation the anticipated cost, timing and expected reliability of gathering connections and capacity. 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 gas to more distant markets. This can lead to lower natural gas prices relative to other areas as the producers compete for the available markets by reducing prices. It can also lead to curtailments of production and periods when wells are shut-in due to lack of market.
Sale of Production. The Partnership sells the oil and natural gas produced from its wells on a competitive basis at the best available terms and prices. PDC utilizes the services of its wholly-owned subsidiary Riley Natural Gas (RNG) in marketing the gas produced from Partnership wells. PDC does not make any commitment of future production that does not primarily benefit the Partnership. 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 contracts with a term of a number of years and that may require the dedication of the gas from a well for a period ranging up to the life of the well.
The Partnership sells natural gas discovered by it at negotiated prices based upon a number of factors, including the quality of the gas, well pressure, estimated reserves, prevailing supply conditions and any applicable price regulations promulgated by the Federal Energy Regulatory Commission (FERC). The Partnership sells oil produced by it 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.
Price Hedging. Natural gas and oil spot market prices have been extremely volatile in the past, and the volatility may continue in the future. In order to provide a more predictable cash flow stream from Partnership wells, PDC may use financial hedges, put options, call options, and other derivative instruments to offset variations in prices. These hedges may result in more predictable cash flow than would otherwise have been received and at times result in higher cash flow, but at other times in lower cash flow.
Drilling and Operating Agreement. The Partnership has entered into a drilling and operating agreement with PDC. The drilling and operating agreement provides that the operator conducts and directs drilling operations and has full control of all operations on the Partnership's wells. The operator has no liability to the Partnership for losses sustained or liabilities incurred, except as may result from the operator's negligence or misconduct. Under the terms of the drilling and operating agreement, PDC may subcontract responsibilities 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 a proportionate share of total lease, development, and operating costs, and receives a proportionate share of production subject only to royalties and overriding royalties. The Partnership is responsible only for its obligations and is liable only for its proportionate working interest share of the costs of developing and operating the wells.
The operator provides all necessary labor, vehicles, supervision, management, accounting, and overhead services for normal production operations, and deducts from Partnership revenues a 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 monthly administrative charge is $100 per well for Partnership accounting, engineering, management, and general and administrative expenses. Charges for areas with current operations are shown below.
| Initial Per Well Operating Charges |
| Well Location | Monthly Per Well Partnership Administration Fee | Monthly Per Well Tending Fee | Total Operating Charges |
| Wattenberg Field | $100 | $400 | $500 |
| Piceance Basin | $100 | $700 | $800 |
| Williston Basin | $100 | $950 | $1,050 |
The well tending fees and administration fees may be adjusted annually to an amount equal to the rates initially established by the drilling and operating agreement, multiplied by the average of the then current 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.
The Partnership has the right to take in kind and separately dispose of its share of all oil and gas produced from its wells, excluding its proportionate share of production required for lease operations and production unavoidably lost. Initially, the Partnership designated the operator as its agent to market its production and authorize the operator 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 gas. If pipelines owned by PDC are used in the delivery of natural gas to market, PDC may charge a gathering fee not to exceed that which would be charged by a non-affiliated third party for a similar service.
The drilling and operating agreement continues in force as long as any well or wells produce, or are capable of 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 Agreement.
Production Phase of Operations
General. When Partnership wells are "complete" (i.e., drilled, fractured or stimulated, and all surface production equipment and pipeline facilities necessary to produce the well are installed), production operations commence on each well.
The Partnership sells the produced natural gas to industrial users, gas marketers, including affiliated marketers, commercial end users, interstate or intrastate pipelines or local utilities, primarily under market sensitive contracts in which the price of gas sold varies as a result of market forces. Some leases, and thus the natural gas derived from wells drilled on those leases, may be dedicated to particular markets at the time the Partnership acquired those leases, or subsequent to, as part of the gas marketing arrangements.
PDC, on behalf of the Partnership, may enter into fixed price contracts, or utilize derivatives, including hedges, swaps or options in order to offset some or all of the price variability for particular periods of time, generally for less than two years. The use of derivatives may entail fees, including the time value of money for margin requirements, which are charged to the Partnership.
PDC utilizes its subsidiary RNG to market the Partnership's produced natural gas, enter into hedges or swaps, collars or purchase options on behalf of the Partnership. RNG is entitled to charge reasonable fees for its services, including out-of-pocket costs. These fees are equal to or less than fees charged to non-affiliated producers for similar services.
Seasonal factors, such as effects of weather on prices received and costs incurred may impact the Partnership's results. In addition, both sales volumes and prices tend to be affected by demand factors with a significant seasonal component.
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.
The above items of expenditure involve amounts payable solely out of, and expenses incurred solely by reason of, production operations. Although the Partnership is permitted to borrow funds for its operations, it is PDC's practice to deduct operating expenses from the production revenue for the corresponding period, and to defer the collection of operating expenses to future periods when revenues are insufficient to render full payment.
Interests of Parties in Production Revenues
PDC, the Investor Partners, and unaffiliated third parties (including landowners) share revenues from production of natural gas and oil from wells in which the Partnership has an interest. The following chart illustrates the interest of gross revenues derived from the wells. For the purpose of this chart, "gross revenue" is defined as the "wellhead gas and oil revenue" paid by the purchasers. Landowner and other royalties payable to unaffiliated third parties may vary, generally between 12.5% to 25% or more; however, the average of the royalty interests for all prospects or wells of the Partnership may not exceed 25%.
Illustration of Partnership Revenue Sharing |
| Entity or Interest Owners | Partnership Interests | Gross Revenue Interests (Partnership Revenues and Third Party Royalties) |
| | | If 12½% Royalty: | If 25% Royalty: |
| PDC, the Managing General Partner | 37% | 32.375% | 27.75% |
| Investor Partners | 63% | 55.125% | 47.25% |
| Landowners and Over- riding Royalty Owners | N/A | 12.50% | 25.00% |
| Totals | 100% | 100.00% | 100.00% |
Insurance
PDC, in its capacity as operator, carries well pollution, public liability and worker’s compensation insurance, but that insurance may not be sufficient to cover all liabilities. Each unit held by the additional general partners represents an open-ended security for unforeseen events such as blowouts, lost circulation, and stuck drill pipe, which may result in unanticipated additional liability materially in excess of the per unit subscription amount.
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 beneficiary under each policy and pays the premiums for each policy, except the Managing General Partner and the Partnership are co-insured and co-beneficiaries with respect to the insurance coverage referred to in #2 and #5 below. Additionally, PDC as operator of the Partnership's wells, requires all of PDC's subcontractors to carry liability insurance coverage with respect to their activities. In the event of a loss, the insurance policies of the particular subcontractor at risk would 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, currently, West Virginia, Michigan, Pennsylvania and Colorado; this insurance will be obtained for any other jurisdictions in which the operator hires employees; |
| 2. | Operator's bodily injury liability and property damage liability insurance, each with a limit of $1,000,000; |
| 3. | Employer's liability insurance with a limit of not less than $1,000,000; |
| 4. | Automobile public liability insurance with a limit of not less than $1,000,000 per occurrence, covering all automobile equipment; and |
| 5. | Operator's umbrella liability insurance with a limit of $50,000,000 for each well location and in the aggregate. |
PDC 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 drilling. 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 operations.
Competition and Markets
Competition is high among persons and companies involved in the exploration for and production of oil and natural gas. The Partnership competes with entities having financial resources and staffs substantially larger than those available to the Partnership. There are thousands of oil and natural gas companies in the United States. The national supply of natural gas is widely diversified. As a result of this competition and FERC and Congressional deregulation of natural gas and oil prices, prices are generally determined by competitive forces.
The marketing of any oil and natural gas produced by the Partnership is affected by a number of factors 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 crude oil and natural gas in world markets has 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 pipelines to separate their storage, sales and transportation functions and establishing an industry-wide structure for "open-access" transportation service. 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 gas transportation, maximize shippers' supply alternatives, and encourage domestic natural gas production in order to meet projected increases in natural 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 affected demand for natural gas.
The combined impact of FERC Order 636 and 637 has been to increase the competition among gas suppliers from different regions.
In 1995, the North American Free Trade Agreement ("NAFTA") eliminated trade and investment barriers in the United States, Canada, and Mexico, increasing foreign competition for natural gas production. Legislation that Congress may consider with respect to oil and natural gas 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 (OPEC) establish prices and production quotas for petroleum products from time to time, with the intent of reducing the current global oversupply and maintaining or increasing price levels. PDC is unable to predict what effect, if any, future OPEC actions will have on the quantity of, or prices received for, oil and natural gas produced and sold from the Partnership's wells.
Various parts of the fields the Partnership’s wells are in are crossed by pipelines belonging to Colorado Interstate Gas, Encana, Duke, 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.
The Partnership sells natural gas from its wells to Duke Energy, Encana and Williams on the spot market via open access transportation arrangements through Colorado Interstate Gas, Williams or other pipelines. As a result of FERC regulations that require interstate gas pipelines to separate their merchant activities from their transportation activities and require them to release available capacity on both a short and a long-term basis, local distribution companies must take an increasingly active role in acquiring their own gas supplies. Consequently, pipelines and local distribution companies 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. Activity by state regulatory commissions to review local distribution company procurement practices more carefully and to unbundle retail sales from transportation has caused gas purchasers to minimize their risks in acquiring and attaching gas supply and has added to competition in the natural gas marketplace.
In FERC Order No. 587 and other initiatives, pipelines were required to develop electronic communications in order to ensure that the gas industry is more competitive. Pipelines must provide standardized access via the Internet to information concerning capacity and prices, and standardized procedures are now available for nominating and scheduling deliveries. The industry has also developed methods to access and integrate all gas supply and transportation information on a nationwide basis, via the Internet, so as to create a national market. Furthermore, parallel developments toward an electronic marketplace for electric power, mandated by the FERC in Order Nos. 888 and 2000, are serving to create multi-national markets for energy products generally. These systems will allow rapid consummation of natural gas transactions.
Natural Gas and Crude Oil Pricing
PDC sells the natural gas and oil from Partnership wells in Colorado and North Dakota subject to market sensitive contracts, the price of which increases or decreases with market forces beyond control of the Partnership. Currently, PDC sells Partnership natural gas in the Piceance Basin primarily to Williams Production RMT, which has an extensive gathering and transportation system in the field. In the Wattenberg Field, the natural gas is sold primarily to Duke Energy Field Services, which gathers and processes the gas and liquefiable hydrocarbons produced. Gas produced in Colorado is subject to changes in market prices on a national level, as well as changes in the market within the Rocky Mountain Region. Sales may be affected for short periods of time by capacity interruptions on pipelines transporting gas out of the region.
Sales of natural gas by the Partnership are subject to regulation by governmental regulatory agencies. Generally, the regulatory agency in the state where a producing gas well is located supervises production activities and the transportation of gas sold into intrastate markets. FERC regulates the rates for interstate transportation of natural gas but, under the Wellhead Decontrol Act of 1989, FERC may not regulate the price of natural gas. Deregulated natural gas production may be sold at market prices determined by supply, demand, Btu content, pressure, location of wells, and other factors.
Currently, PDC sells crude oil primarily to Teppco Crude Oil, L.P. Generally, 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 New York Mercantile Exchange (“Nymex”), but also due to changes in the supply and demand at the various refineries. Additionally, the cost of trucking or transporting the oil to market affects the price the Partnership ultimately receives for the oil.
Governmental Regulation
Federal and state regulations affect production of Partnership oil and natural gas. In most areas of operations, the production of oil is regulated by conservation laws and regulations, which control the conduct of oil and gas operations.
The Partnership's drilling and production operations are also subject to environmental protection regulations established by federal, state, and local agencies, which in turn may necessitate significant capital outlays which would materially affect the financial position and business operations of the Partnership.
Some states control production through regulations establishing the spacing of wells, limiting the number of days in a given month during which a well can produce and otherwise limiting the rate of allowable production. Through regulations enacted to conserve natural resources and prevent pollution, local, state and federal environmental controls also affects Partnership operations. These regulations could necessitate spending funds on environmental protection measures, rather than on drilling operations. If any penalties or prohibitions were imposed on the Partnership for violating those regulations, the Partnership's operations could be adversely affected.
Proposed Regulation
Various legislative proposals in Congress and in state legislatures could, if enacted, affect the petroleum and natural gas industries. 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 (such as prohibiting drilling activities on federal and state lands in roadless wilderness areas), landowners' "rights" legislation, alternative fuel use requirements and/or tax incentives and other measures. At the present time, it is impossible to predict what proposals, if any, will actually be enacted by Congress or the various state legislatures and what effect, if any, the proposals will have on the Partnership's operations.
In the course of its normal business, the Partnership is subject to a number of risks that could adversely impact its business, operating results, financial condition, and cash distributions. The following is a discussion of the material risks involved in an investment in the Partnership.
Risks Pertaining to Natural Gas and Oil Investments
Drilling natural gas and oil wells is speculative and may be unprofitable and result in the total loss of investment. The drilling and completion operations undertaken by the Partnership for the development of natural gas and oil reserves are inherently speculative and involve a high degree of risk and the possibility of a total loss of investment. Drilling activities may result in unprofitable well operations, not only from non-productive wells, but also from wells that do not produce natural gas or oil in sufficient quantities or quality to return a profit on the amounts expended. Partnership wells may not produce sufficient natural gas and oil for investors to receive a profit or even to recover their initial investment. Only three of the prior Partnerships sponsored by PDC have, to date, generated cash distributions in excess of investor subscriptions without giving effect to tax savings.
The Partnership may retain Partnership revenues or borrow funds if needed for Partnership operations to fully develop the Partnership's wells; if full development of the Partnership's wells proves commercially unsuccessful, an investor might anticipate a reduction in cash distributions. The Partnership intends to utilize substantially all available capital raised in the offering for the drilling and completion of wells and will have only nominal funds available for Partnership purposes prior to the time as there is production from Partnership well operations. Upon completion of the Partnership’s drilling activities, the Partnership will have utilized substantially all of its available capital. If the Partnership requires additional capital in the future, it will have to either retain Partnership revenues or borrow the funds necessary for these purposes. Retaining Partnership revenues and/or the repayment of borrowed funds will result in a reduction of cash distributions to the investors. Additionally, in the future, PDC may wish to rework or recomplete Partnership wells; however, PDC has not held money from the initial investment for that future work. 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 the investors to cover revenues retained or to repay financial obligations of the Partnership for borrowed funds plus interest. If future development of the Partnership's wells is not commercially successful, whether using funds retained from production revenues or borrowed funds, these operations could result in a reduction of cash distributions to the Investor Partners of the Partnership.
Increases in prices of oil and natural gas have increased the cost of drilling and development and may affect the performance and profitability of the Partnership in both the short and long term. In the current high price environment, most oil and gas companies have increased their expenditures for drilling new wells. This has resulted in increased demand and higher cost for leases, oilfield services and well equipment. Because of these higher costs, the risk to the Partnership of decreased profitability from future decreases in oil and natural gas prices is increased.
Reductions in prices of oil and natural gas reduce the profitability of the Partnership's production operations and could result in reduced cash distributions to the investors. Global economic conditions, political conditions, and energy conservation have created unstable prices. Revenues of the Partnership are directly related to natural gas and oil prices. The prices for domestic natural gas and oil production have varied substantially over time and by location and are likely to remain extremely unstable. Revenue from the sale of oil and natural gas increases when prices for these commodities increase and declines when prices decrease. These price changes can occur rapidly and are not predictable and are not within the control of the Partnership. A decline in natural gas and/or oil prices would result in lower revenues for the Partnership and a reduction of cash distributions to the partners of the Partnership. In the third and fourth quarter of 2007, the price of natural gas in the Rocky Mountains region has declined over the same periods in 2006.
The high level of drilling activity could result in an oversupply of natural gas on a regional or national level, resulting in much lower commodity prices, reduced profitability of the Partnership and reduced cash distributions to the investors. Recently, the natural gas market has been characterized by excess demand compared to the supplies available, leading in general to higher prices for natural gas. The high level of drilling, combined with a reduction in demand resulting from higher prices, could result in an oversupply of natural gas. In the Rocky Mountain region, rapid growth of production and increasing supplies may result in lower prices and production curtailment due to limitations on available pipeline facilities or markets not developed to utilize or transport the new supplies. In both cases, the result would probably be lower prices for the natural gas the Partnership produces, reduced profitability for the Partnership and reduced cash distributions to the Investor Partners. In the third and fourth quarter of 2007, the price of natural gas in the Rocky Mountains region has declined over the same periods in 2006.
Sufficient insurance coverage may not be available for the Partnership, thereby increasing the risk of loss for the Investor Partners. It is possible that some or all of the insurance coverage which the Partnership has available may become unavailable or prohibitively expensive. In that case, PDC might elect to change the insurance coverage. The additional general partners could be exposed to additional financial risk due to the reduced insurance coverage and due to the fact that additional general partners would continue to be individually liable for obligations and liabilities of the Partnership. Investor Partners could be subject to greater risk of loss of their investment because less insurance would be available to protect the Partnership from casualty losses. Moreover, should the Partnership's cost of insurance become more expensive the amount of cash distributions to the investors will be reduced.
Through their involvement in Partnership and other non-partnership activities, the Managing General Partner and its affiliates have interests which conflict with those of the Investor Partners; actions taken by the Managing General Partner in furtherance of its own interests could result in the Partnership's being less profitable and a reduction in cash distributions to the investors. PDC's continued active participation in oil and natural gas activities for its own account and on behalf of other partnerships organized or to be organized by PDC and the manner in which Partnership revenues are allocated create conflicts of interest with the Partnership. PDC has interests which inherently conflict with the interests of the Investor Partners. In operating the Partnership, the Managing General Partner and its affiliates could take actions which benefit themselves and which do not benefit the Partnership. These actions could result in the Partnership's being less profitable. In that event, an Investor Partner could anticipate a reduction of cash distributions.
The Partnership and other partnerships sponsored by the Managing General Partner may compete with each other for prospects, equipment, contractors, and personnel; as a result, the Partnership may find it more difficult to operate effectively and profitably. During and after 2007, PDC plans to offer interests in other partnerships to be formed for substantially the same purposes as those of the Partnership. Therefore, a number of partnerships with unexpended capital funds, including those partnerships formed before and after the Partnership, may exist at the same time. The Partnership may compete for equipment, contractors, and PDC personnel (when the Partnership is also needful of equipment, contractors and PDC personnel), which may make it more difficult and more costly to obtain services for the Partnership. In that event, it is possible that the Partnership would be less profitable. Additionally, because PDC must divide its attention in the management of its own affairs as well as the affairs of the thirty-three (33) limited partnerships PDC has organized in previous programs, the Partnership will not receive PDC's full attention and efforts at all times.
The Partnership's derivative activities could result in reduced revenue compared to the level the Partnership might experience if no derivative instruments were in place and reduced cash distributions to the investors. The Partnership expects to use derivative instruments to reduce the impact of price movements on revenue. While these derivative instruments protect the Partnership against the impact of declining prices, they also may limit the positive impact of price increases. As a result, the Partnership may have lower revenues when prices are increasing than might otherwise be the case, and may also reduce the Partnership's cash flows and cash distributions to the Investor Partners.
Hedging transactions have in the past and may in the future impact our cash flow from operations. Our commodity hedging may prevent us from benefiting fully from price increases and may expose us to other risks. PDC will enter into hedging arrangements to reduce the Partnership’s exposure to fluctuations in natural gas and crude oil prices and to achieve more predictable cash flow. Although the Partnership’s hedging activities may limit the Partnership’s exposure to declines in natural gas and crude oil prices, these activities may also limit and have in the past limited, additional revenues from increases in natural gas and crude oil prices. To the extent that the Partnership engages in hedging activities to protect itself from commodity price volatility, the Partnership may be prevented from realizing the benefits of price increases above the levels of the hedges.
Additionally, the hedging transactions PDC has entered into, or will enter into, may not adequately protect the Partnership from financial loss due to circumstances such as:
| · | Highly volatile natural gas and crude oil prices; |
| · | Production being less than expected; or |
| · | A counterparty defaults on its contractual obligations. |
Fluctuating market conditions and government regulations may cause a decline in the profitability of the Partnership and a reduction of cash distributions to the investors. The sale of any natural gas and oil produced by the Partnership will be affected by fluctuating market conditions and governmental regulations, including environmental standards, set by state and federal agencies. From time-to-time, a surplus of natural gas or oil may occur in areas of the United States. The effect of a surplus may be to reduce the price the Partnership receives for the natural gas or oil production, or to reduce the amount of natural gas or oil that the Partnership may produce and sell. As a result, the Partnership may not be profitable. Lower prices and/or lower production and sales will result in lower revenues for the Partnership and a reduction in cash distributions to the partners of the Partnership.
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 oil and natural gas 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 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 we may produce and sell. A major risk inherent in our drilling plans is the need to obtain drilling permits from state and local authorities. Delays in obtaining regulatory approvals or drilling permits, 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 our ability to develop our 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 our ability to pay distributions to our unitholders. We further reference sections “Government Regulation” and “Proposed Regulation” in “Item 1, Business”, for a detailed discussion of the laws and regulations that affect the Partnership’s activities.
Environmental hazards involved in drilling natural 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 investors. There are numerous natural hazards involved in the drilling of wells, including unexpected or unusual formations, pressures, blowouts involving possible damages to property and third parties, surface damages, personal injury or loss of life, damage to and loss of equipment, reservoir damage and loss of reserves. Uninsured liabilities would reduce the funds available to the Partnership, may result in the loss of Partnership properties and may create liability for additional general partners. The Partnership may become subject to liability for pollution, abuses of the environment and other similar damages, and 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 partners of the Partnership.
Delay in partnership natural gas or oil production could reduce the Partnership's profitability and a reduction in cash distributions to the investors. Drilling wells in areas remote from marketing facilities may delay production from those wells until sufficient reserves are established to justify construction of necessary pipelines and production facilities. The Partnership’s inability to complete wells in a timely fashion may also 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 partners of the Partnership would decline.
A significant variance from the Partnership’s estimated reserves and future net revenues estimates could adversely affect the Partnership’s cash flows, results of operations and the availability of capital resources and the Partnership’s earnings. The accuracy of proved reserves estimates and estimated future net revenues from such reserves is a function of the quality of available geological, geophysical, engineering and economic data and is subject to various assumptions, including assumptions required by the SEC relating to oil and gas prices, drilling and operating expenses, and other matters. Although the estimated proved reserves represent reserves the Partnership reasonably believes it is certain to recover, actual future production, oil and gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and gas reserves will most likely vary from the assumptions and estimates used to determine proved reserves. Any significant variance could materially affect the estimated quantities and value of the Partnership’s oil and gas reserves, which in turn could adversely affect cash flows, results of operations and the availability of capital resources. In addition, estimates of proved reserves may be adjusted to reflect production history, results of exploration and development, prevailing oil and gas prices and other factors, many of which are beyond the Partnership’s control. Downward adjustments to the estimated proved reserves could require a write down to the carrying value of the Partnership’s oil and gas properties, which would reduce earnings and partners’ equity.
The present value of proved reserves will not necessarily equal the current fair market value of the estimated oil and gas reserves. In accordance with the reserve reporting requirements of the SEC, the estimated discounted future net cash flows from proved reserves are 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 oil and gas properties will affect the timing of future net cash flows from proved reserves and their present value.
Seasonal weather conditions may adversely affect the Partnership’s ability to conduct drilling, completion and production activities in some of the areas of operation. Oil and natural gas operations in the Rocky Mountains are adversely affected by seasonal weather conditions. In certain areas, drilling and other oil and natural gas activities are restricted or prevented by weather conditions for up to 6 months out of the year. This limits operations in those areas and can intensify competition during those months for drilling rigs, oil field equipment, services, supplies and qualified personnel, which may lead to periodic shortages. These constraints and the resulting shortages or high costs could delay operations and materially increase operating and capital costs and therefore adversely affect profitability, and could result in a reduction of cash distributions to the investors.
Two Colorado lawsuits against PDC, the Managing General Partner of the Partnership, for underpayment of royalties, could financially harm PDC and the Partnership. A judgment by the Federal Court against PDC could result in higher production costs for the Partnership, reduced profitability and reduced cash distributions to the investors. On May 29, 2007, a complaint was filed against PDC in Weld County, Colorado. The complaint represents a class action against PDC seeking compensation for alleged underpayment of royalties on leases in Colorado, resulting from the alleged miscalculation of costs to produce marketable natural gas. A second similar Colorado class action suit was filed against PDC on December 3, 2007. Many of the subject properties include working interests owned by partnerships of which PDC is the managing general partner, including the working interests of the Partnership. Although at this time the Partnership has not been named as a party in these suits, the Managing General Partner believes that the Partnership’s 64 wells in the Wattenberg field will be subject to the lawsuits. The lawsuits seek unspecified damages. PDC has retained Colorado counsel to defend the interest of PDC and its sponsored partnerships in this matter. PDC disputes the plaintiff's claims and intends to defend the lawsuits vigorously. While PDC presently believes that the ultimate outcome of these proceedings will not materially harm PDC's and the various partnerships' respective financial position, cash flows, or overall results of operations, litigation is subject to inherent uncertainties, and unfavorable rulings could occur. An unfavorable ruling could include money damages. Were an unfavorable ruling to occur, the court could determine that the royalty owners have a right to a greater share of the revenues from PDC's and the Partnership's respective wells than they have been receiving, including past revenues. The court could rule that PDC and the Partnership owe the royalty owners revenues for previous production plus interest and could require both PDC and the Partnership to pay royalty owners unreduced royalties on future production, the result of which could reduce PDC's and the Partnership's future revenues.
Were such a ruling to be rendered, the Partnership might be liable for additional royalties not paid to the owners from the time that the Partnership first produced natural gas from its wells until final judgment by the court. Moreover, the Partnership might be required to pay additional royalties to the owners for natural gas production in the future following the court's final judgment, and incur legal fees. Therefore, under these circumstances, it is likely that the profitability of the Partnership would be reduced and that future cash distributions to the investors in the Partnership likewise would be reduced.
Special Risks of an Investment in the Partnership
The partnership units are not registered, there will be no public market for the units, and as a result an Investor Partner may not be able to sell his or her units. There is and will be no public market for the units nor will a public market develop for the units. Investor Partners may not be able to sell their Partnership interests or may be able to sell them only for less than fair market value. The offer and sale of units have not been, and will not in the future be, registered under the Securities Act or under any state securities laws. Each purchaser of units has been required to represent that such investor has purchased the units for his or her own account for investment and not with a view to resale or distribution. No transfer of a unit may be made unless the transferee is an "accredited investor" and such transfer is registered under the Securities Act and applicable state securities laws, or an exemption therefrom is available. The Partnership may require that the transferor provide an opinion of legal counsel stating that the transfer complies with all applicable securities laws. A sale or transfer of units by an investor requires PDC's prior written consent. For these and other reasons, an investor must anticipate that he or she will have to hold his or her Partnership interests indefinitely and will not be able to liquidate his or her investment in the Partnership. Consequently, an investor must be able to bear the economic risk of investing in the Partnership for an indefinite period of time.
Dry hole costs and impairment charges associated with the Partnership's drilling have resulted in reduced distributions to the investors. To date, the Partnership has drilled a total of 97 wells. Of these wells, six have been determined to be commercially unproductive and therefore declared to be dry holes. As dry holes result in no production of oil and natural gas, the occurrence of dry holes causes the revenues and distributions to be less than if the wells drilled had been commercially productive. As of September 30, 2007, the Partnership recorded $8,122,577 in dry hole costs.
Quarterly, the Partnership assesses impairment of capitalized costs of proved oil and gas properties by comparing net capitalized costs to estimated undiscounted future net cash flows on a field-by-field basis using estimated production based upon prices at which management reasonably estimates such production to be sold. From inception through September 30, 2007, the Partnership's impairment charges totaled $9,575,300. Unlike dry holes, impaired properties may still produce oil and natural gas which can be sold, however the impaired properties may not generate enough production for the Partnership to recoup the amounts invested in the properties.
The additional general partners will be individually liable for Partnership obligations and liabilities that arose prior to conversion to limited partners (which can occur only after the drilling completion operations are finished) that are beyond the amount of their subscriptions, Partnership assets, and the assets of the Managing General Partner. Under West Virginia law, the state in which the Partnership has organized, general partners of a limited partnership have unlimited liability with respect to the Partnership. Therefore, the additional general partners of the Partnership will be liable individually and as a group for all obligations and liabilities of creditors and claimants, whether arising out of contract or tort, in the conduct of the Partnership's operations until such time as the additional general partners are converted to limited partners. Under the Partnership Agreement, this conversion is not scheduled to occur until the drilling and completion operations are finished. Irrespective of conversion, the additional general partners will remain fully liable for obligations and liabilities that arose prior to conversion. Investors as additional general partners may be liable for amounts in excess of their subscriptions, the assets of the Partnership, including insurance coverage, and the assets of the Managing General Partner.
The Managing General Partner may not have sufficient funds to repurchase limited partnership units. As a result of the Managing General Partner being a general partner in several partnerships, the Partnership’s net worth is at risk of reduction if PDC suffers a significant financial loss. Because the investors may request the Managing General Partner to repurchase the units in the Partnership, subject to certain conditions and restrictions, a significant adverse financial reversal could result in the Managing General Partner’s inability to pay for Partnership obligations or the repurchase of investor units. As a result, an investor 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. Because PDC is primarily responsible for the conduct of the Partnership's affairs, as well as the affairs of other partnerships for which PDC serves as managing general partner, a significant adverse financial reversal for PDC could result in PDC's inability to pay for Partnership liabilities and obligations. The additional general partners of the Partnership might be personally liable for payments of the Partnership's liabilities and obligations. Therefore, the Managing General Partner's financial incapacity could increase the risk of personal liability as an additional general partner because PDC would be unable to indemnify the additional general partners for any personal losses they suffered arising from Partnership operations.
The Managing General Partner and various limited partnership sponsored by the Managing General Partner have been delinquent in filing their periodic reports with the SEC. Consequently, investors are unable to review current financial statements of other Partnerships sponsored by the Managing General Partner as a source of information in evaluating their investment in the Partnership. PDC and various other limited partnerships which PDC has sponsored and for which PDC serves as the Managing General Partner are subject to reporting requirements of the Securities Exchange Act of 1934. As a result, PDC and these limited partnerships are obligated to file annual and quarterly reports with the SEC in accordance with the rules of the SEC. In the course of preparing its consolidated financial statements for the quarter ended June 30, 2005, PDC identified accounting errors in prior period financial statements. As a result, on October 17, 2005, PDC’s Board of Directors, Audit Committee and management concluded that previously issued financial statements could not be relied upon and would be restated. PDC made similar determinations regarding the financial statements of various limited partnerships which are subject to the Exchange Act obligations and for which PDC serves as the Managing General Partner. Since then, PDC has become compliant with its Exchange Act filing and reporting obligations. The various limited partnerships have not filed their amended annual reports for the years ended prior to and including December 31, 2004 or their amended reports for the quarter ended March 31, 2005, and have not yet filed their quarterly reports for the quarters ended June 30 and September 30, 2005 and March 31, June 30, and September 30, 2006, their annual reports for the years ended December 31, 2005 and December 31, 2006, and their quarterly reports for the quarters ended March 31, June 30 and September 30, 2007. These limited partnerships are in the process of correcting their erroneous reports and preparing the quarterly and annual reports that they have not yet filed. Until these Partnerships file their requisite 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.
As of December 31, 2006, the Managing General Partner identified material weaknesses in its internal control over financial reporting, and because we rely on the Managing General Partner for our financial reporting, if certain of these material weaknesses are not remediated on or before December 31, 2007, we may determine that our internal controls over financial reporting are not effective and result in a reasonable possibility that a material misstatement in our annual or interim financial statements will not be prevented or detected on a timely basis. While, we are not required to report on the effectiveness of our internal control over financial reporting until December 31, 2007, our Managing General Partner is required to assess the effectiveness of its ICFR. As discussed in the Manager General Partner's Annual Report on Form 10-K for the year ended for December 31, 2006, filed with the Securities and Exchange Commission on May 23, 2007, and directly applicable to our internal control over financial reporting, the Managing General Partner did not maintain effective controls as of December 31, 2006, over:
| · | the timely reconciliation, review and adjustment of significant balance sheet accounts, specifically distribution liability, and |
| · | the proper identification of all derivative contracts related to oil and gas sales to ensure the fair value determination of certain derivatives. |
If the Managing General Partner does not remediate these identified material weaknesses on or before December 31, 2007, we may also conclude that our internal control over financial reporting is not effective with regard to these same controls and that there is a reasonable possibility that a material misstatement in our annual or interim financial statements will not be prevented or detected on a timely basis.
As reported in its Quarterly Report on Form 10-Q for the quarter ended September 30, 2007, the Managing General Partner has made the following changes during 2007 in its internal control over financial reporting that it believes have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting:
| · | reinforced reconciliation procedures to ensure the timely reconciliation, review and adjustments to significant balance sheet and income statement accounts, |
| · | developed and approved extensive policies and procedures concerning the controls over financial reporting for derivatives, and |
| · | provided additional training regarding derivatives for key personnel. |
The Managing General Partner continues to evaluate the ongoing effectiveness and sustainability of these changes 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.
For additional information regarding the material weaknesses of the Managing General Partner, please refer to its Annual Report on Form 10-K for the year ended December 31, 2006. You can access this report and all of the other reports the Managing General Partner has filed with the SEC on its website at www.petd.com.
Item 2. Financial Information.
(a) SELECTED FINANCIAL DATA.
The selected financial data for the period from September 7, 2006 (date of inception) to December 31, 2006 and as of and for the nine months ended September 30, 2007 presented below has been derived from audited financial statements of the Partnership appearing elsewhere herein. This information is only a summary and should be read in conjunction with “Management Discussion and Analysis of Financial Condition and Results of Operations” and the financial statements and related notes thereto contained in this report.
| | | Nine Months Ended September 30, 2007 | | | Period from September 7, 2006 (date of inception) to December 31, 2006 | |
| | | | | | (restated) | |
| | | | | | | |
| Oil and gas sales | | $ | 23,580,164 | | | $ | 1,228,684 | |
| Oil and gas price risk management gain(loss), net | | | 543,740 | | | | (408 | ) |
| Costs and expenses | | | 15,936,055 | | | | 2,721,058 | |
| Loss on impairment of oil and gas properties | | | 2,445,617 | | | | 7,129,683 | |
| Exploratory dry hole costs | | | 8,122,577 | | | | - | |
| Net loss | | | (2,291,166 | ) | | | (7,456,539 | ) |
| Allocation of net loss | | | | | | | | |
| Managing general partner | | | (847,731 | ) | | | (2,259,749 | ) |
| Investor partners | | | (1,443,435 | ) | | | (5,196,790 | ) |
| Investor partners per unit | | | (321 | ) | | | (1,156 | ) |
| Total assets (as of end of period) | | | 99,995,128 | | | | 113,026,550 | |
(b) MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
Disclosure Regarding Forward Looking Statements
Safe Harbor Statement Under the Private Securities Litigation Reform Act of 1995
Statements, other than historical facts, contained in this Form 10/A, including statements of estimated oil and gas production and reserves, future cash flows and the Partnership’s strategies, plans and objectives, are “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). Although the Partnership believes that its forward looking statements are based on reasonable assumptions, it cautions that such statements are subject to a wide range of risks, trends and uncertainties, incidental to the production and marketing of oil and gas, that could cause actual results to differ materially from those projected. Among those risks, trends and uncertainties are important factors that could cause actual results to differ materially from the forward looking statements, including, but not limited to, changes in production volumes, worldwide demand and commodity prices for petroleum natural resources; risks incidental to the operation of oil and gas wells; future production and development costs; the effect of existing and future laws, governmental regulations and the political and economic climate of the United States; the effect of derivative activities; and conditions in the capital markets. In particular, careful consideration should be given to cautionary statements made in this Form 10/A in the Risk Factors section. The Partnership undertakes no duty to update or revise these forward-looking statements.
When used in this Form 10/A, the words, “expect,” “anticipate,” “intend,” “plan,” “believe,” “seek,” “estimate” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain these identifying words. Because these forward-looking statements involve risks and uncertainties, actual results could differ materially from those expressed or implied by these forward-looking statements for a number of important reasons, including those discussed under “Item 1A., Risk Factors” and elsewhere in this Form 10/A.
Restatement of Historical Financial Statements
The Partnership’s financial statements for the period from September 7, 2007 (date of inception) to December 31, 2006 and for the quarter ended March 31, 2007 included in this Form 10/A have been restated from the amounts originally filed on Form 10. These financial statements have been restated to correct errors in the Partnership’s accounting for oil and gas properties and wells in progress.
A summary of adjustments included in the restatement and their impact on the net loss and partners’ equity, as well as detailed information as to the effects of the restatements on the Partnership’s previously reported financial statements is included in “Note 13 – Restatement of Historical Financial Statements” in the Notes to the Financial Statements.
Overview
The Partnership was funded on September 7, 2006 with initial contributions of $89,940,527 from the Investor Partners and a cash contribution of $38,912,342 from the Managing General Partner. After payment of syndication costs of $9,084,039 and a one-time management fee to PDC of $1,349,108, the Partnership had available cash of $118,419,722 to commence Partnership oil and gas well drilling activities.
The Partnership began exploration and development activities immediately after funding. The Partnership was billed by PDC for exploration and development activities from the inception of the Partnership through December 31, 2006. At December 31, amounts remaining from the funding of the Partnership were paid to PDC as a prepayment for drilling of oil and natural gas wells on behalf of the Partnership under the drilling and operating agreement. On September 7, 2006 PDC commenced drilling wells on prospects designated by PDC. By September 30, 2007, a total of ninety-seven wells had been drilled, predominantly in Colorado, of which ninety-one were producing and six were dry holes. These ninety-seven wells are the only wells the Partnership will drill, 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 fourth quarter of 2006 as wells were connected to pipelines. Production and sales increased as additional wells were completed and connected to pipelines. Once producing, the Partnership’s wells will produce until they are depleted or until they are uneconomical to produce; however, it is the plan of the Partnership and the Managing General Partner to recomplete the Codell formation in certain wells in the Wattenberg Field after five or more years of production because these wells will have experienced a significant decline in production in that time period. These Codell recompletions typically increase the production rates and recoverable reserves. Although PDC’s prior experience with Codell recompletions has seen significant production increases, not all recompletions have been successful.
Results of Operations
The following table presents significant operational information of the Partnership for nine months ended September 30, 2007 and the period from September 7, 2006 (date of inception) to December 31, 2006.
| | | Period from September 7, 2006 (date of inception) to December 31, 2006 | | | Nine Months Ended September 30, 2007 | |
| | | (restated) | | | | |
| | | | | | | |
| Oil and gas sales | | $ | 1,228,684 | | | $ | 23,580,164 | |
| Gas sales - Mcf | | | 52,706 | | | | 2,279,359 | |
| Average selling price/Mcf | | $ | 5.92 | | | $ | 4.53 | |
| Oil sales - Bbl | | | 16,728 | | | | 238,675 | |
| Average selling price/Bbl | | $ | 54.79 | | | $ | 55.55 | |
| | | | | | | | | |
| Production and operating costs | | $ | 189,069 | | | $ | 4,084,097 | |
| Production and operating costs/Mcfe | | $ | 1.24 | | | $ | 1.10 | |
| Depreciation, depletion and amortization | | $ | 1,003,120 | | | $ | 11,653,405 | |
| Loss on impairment of oil and gas properties | | $ | 7,129,683 | | | $ | 2,445,617 | |
| Exploratory dry hole costs | | $ | - | | | $ | 8,122,577 | |
| | | | | | | | | |
| Net loss | | $ | (7,456,539 | ) | | $ | (2,291,166 | ) |
| Partnership cash distributions | | $ | - | | | $ | (13,132,064 | ) |
| | | | | | | | | |
| Oil and gas price risk management gain (loss), net | | | | | | | | |
| Realized gain | | $ | - | | | $ | 50,655 | |
| Unrealized (loss) gain | | $ | (408 | ) | | $ | 493,085 | |
| | | | | | | | | |
| Working capital | | $ | 2,026,810 | | | $ | 8,802,215 | |
Definitions
| · | Bbl – One barrel or 42 U.S. gallons liquid volume |
| · | Mcf – One thousand cubic feet |
| · | Mcfe – One thousand cubic feet of natural gas equivalents, based on a ratio of 6 Mcf for each barrel of oil, which reflects the relative energy content. |
As reflected in the table above, oil and gas sales and production increased dramatically in the nine months ended September 30, 2007, as the number of producing wells for the partnership increased from twenty-five at December 31, 2006 to ninety-one at September 30, 2007. The increase in production was substantial enough to offset the effect of declining average natural gas selling prices, which decreased to $4.53 in 2007 from $5.92 in 2006, a decline of 23.5%. Natural gas selling prices for 2007 have consistently been lower than prices for the same period in 2006. The average selling price for oil increased 1.3% for the nine months ended September 30, 2007 as compared to the average selling price for 2006. Production and operating costs and depreciation, depletion and amortization also increased substantially as production increased. Production costs per Mcfe dropped from $1.24 in 2006 to $1.10 in 2007, as production costs were spread out over the increased production levels.
The Partnership recorded impairment losses of $2,445,617 for the nine months ended September 30, 2007 and $7,129,683 for the period from September 7, 2006 (date of inception) to December 31, 2006. These impairments resulted from production activities in the Bakken and Nesson fields in North Dakota and are discussed in more detail below. The Partnership recorded exploratory dry hole expenses of $8,122,577 for the nine months ended September 30, 2007. The Partnership recorded a net loss of $2,291,166 for the nine months ended September 30, 2007 and a net loss of $7,456,539 for the period from September 7, 2006 (date of inception) to December 31, 2006. The substantial loss in 2006 resulted primarily from the impairment referred to above.
The Partnership manages oil and gas price risks through the use of derivative instruments to provide protection on declining oil and natural gas prices. In periods of rising oil and natural gas prices, the Partnership may record losses in its derivative transactions as fair values exceed contract prices related to the Partnership’s oil and gas sales. In periods of declining prices, the Partnership would record gains in its derivative transactions. Transactions in derivative instruments resulted in an overall net gain for 2007 and an overall net loss for 2006. For 2007, there was an unrealized gain on derivatives of $493,085 compared to an unrealized loss on derivatives of $408 for 2006. Total net realized and unrealized gains for the first nine months of 2007 were greater than the net loss in 2006 due to increased hedging activity by the Partnership as production increased. The total net realized and unrealized gain for the nine months ended September 30, 2007 were $543,740, as compared to a net unrealized loss of $408 for the period from September 7, 2006 (date of inception) to December 31, 2006. The net gains/losses are comprised of the change in fair value of derivatives positions related to the Partnership’s oil and gas production for derivative contracts entered into by the Managing General Partner on behalf of the Partnership. The Partnership records gains or losses from its derivative positions on the statement of operations as oil and gas price risk management gain (loss), net.
Production
Production commenced during the fourth quarter of 2006, as wells were drilled, completed and connected to a pipeline. Production for the quarter ended December 31, 2006 was 52,706 Mcf of natural gas and 16,728 Bbls of oil. The total production for the nine months ended September 30, 2007 was 2,279,359 Mcf of natural gas and 238,675 Bbls of oil. Production increased significantly during 2007 as more wells were brought in line.
The Partnership's future revenues from oil and natural gas sales are affected by changes in prices. As a result of changes in market conditions, oil and natural gas prices are highly dependent on the balance between supply and demand. The Partnership's sales prices for natural gas and oil are subject to increases and decreases based on various market sensitive indices.
Liquidity and Capital Resources
The Partnership had working capital of $8,802,215 and $2,026,810 at September 30, 2007 and December 31, 2006, respectively, which generally represents the receivables from oil and gas sales for the preceding three months offset by accounts payable from oil and gas activity.
As the Partnership has completed its drilling activities as of September 30, 2007, the Partnership’s operations are expected to be conducted with available funds and revenues generated from oil and gas production activities. No additional funds will be used at this time for drilling activities. As such, the Partnership’s liquidity may be impacted by fluctuating oil and natural gas prices, as noted in “Item 1A, Risk Factors.”
No bank borrowings are anticipated until such time as recompletions of the Codell formation in the Wattenberg Field wells are undertaken by the Partnership, which is expected to occur in 2011 or later.
Oil and Gas Reserves
Information related to the oil and gas reserves of the Partnership’s wells is discussed in detail in “Note 8 – Supplemental Reserve Information (Unaudited)” in the Notes to the Financial Statements.
Periodic and Quarterly Analysis
The table below reflects the Partnership’s sales of production from the wells and the average prices received for the period ended December 31, 2006 and each of the quarters in 2007.
| | | No. of | | | Gas | | | Oil | | | | |
| | | Producing | | | | | | Average | | | | | | Average | | | Oil and Gas | |
| | | Wells | | | Mcf | | | Price | | | Bbls | | | Price | | | Sales | |
| Total 2006 | | | 25 | | | | 52,706 | | | $ | 5.92 | | | | 16,728 | | | $ | 54.79 | | | $ | 1,228,684 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Quarter 1 | | | 32 | | | | 273,331 | | | $ | 5.60 | | | | 59,138 | | | $ | 45.22 | | | $ | 4,204,666 | |
| Quarter 2 | | | 64 | | | | 848,953 | | | | 5.03 | | | | 104,673 | | | | 53.86 | | | | 9,904,797 | |
| Quarter 3 | | | 91 | | | | 1,157,075 | | | | 3.91 | | | | 74,864 | | | | 66.08 | | | | 9,470,701 | |
| Total 2007 | | | | | | | 2,279,359 | | | $ | 4.53 | | | | 238,675 | | | $ | 55.55 | | | $ | 23,580,164 | |
The following table sets forth the periodic and quarterly operating results for the period from September 7, 2006 (date of inception) to December 31, 2006 and for each of the quarters in 2007. Additional quarterly information for 2007 is presented in “Note 12 – Quarterly Financial Data (unaudited)” in the Notes to the Financial Statements.
| STATEMENTS OF OPERATIONS | | Period From | | | | | | | | | | |
| | | September 7, 2006 | | | For the Quarter Ended | |
| | | (date of | | | March 31, | | | June 30, | | | September 30, | |
| | | inception) to | | | 2007 | | | 2007 | | | 2007 | |
| | | December 31, 2006 | | | (unaudited) | | | (unaudited) | | | | |
| | | (restated) | | | (restated) | | | | | | | |
| Revenues: | | | | | | | | | | | | |
| Oil and gas sales | | $ | 1,228,684 | | | $ | 4,204,666 | | | $ | 9,904,797 | | | $ | 9,470,701 | |
| Oil and gas price risk management (loss) gain, net | | | (408 | ) | | | (60,931 | ) | | | 80,000 | | | | 524,671 | |
| Total revenues | | | 1,228,276 | | | | 4,143,735 | | | | 9,984,797 | | | | 9,995,372 | |
| | | | | | | | | | | | | | | | | |
| Costs and Expenses: | | | | | | | | | | | | | | | | |
| Production and operating costs | | | 189,069 | | | | 740,263 | | | | 1,544,329 | | | | 1,799,505 | |
| Management fee | | | 1,349,108 | | | | - | | | | - | | | | - | |
| Direct costs | | | 176,613 | | | | 21,421 | | | | 19,536 | | | | 129,973 | |
| Depreciation, depletion and amortization | | | 1,003,120 | | | | 2,021,542 | | | | 4,778,643 | | | | 4,853,220 | |
| Accretion of asset retirement obligation | | | 3,148 | | | | 8,451 | | | | 9,847 | | | | 9,325 | |
| Loss on impairment of oil and gas properties | | | 7,129,683 | | | | 1,135,208 | | | | 1,310,409 | | | | - | |
| Exploratory dry hole costs | | | - | | | | 3,395,210 | | | | 3,150,266 | | | | 1,577,101 | |
| Total costs and expenses | | | 9,850,741 | | | | 7,322,095 | | | | 10,813,030 | | | | 8,369,124 | |
| | | | | | | | | | | | | | | | | |
| (Loss) income from operations | | | (8,622,465 | ) | | | (3,178,360 | ) | | | (828,233 | ) | | | 1,626,248 | |
| | | | | | | | | | | | | | | | | |
| Interest expense | | | 15 | | | | 1,200 | | | | 1,927 | | | | 2,058 | |
| Interest income | | | (1,165,941 | ) | | | (8,545 | ) | | | (49,639 | ) | | | (36,180 | ) |
| | | | | | | | | | | | | | | | | |
| Net (loss) income | | $ | (7,456,539 | ) | | $ | (3,171,015 | ) | | $ | (780,521 | ) | | $ | 1,660,370 | |
| | | | | | | | | | | | | | | | | |
| Net (loss) income per Investor Partner unit | | $ | (1,156 | ) | | $ | (444 | ) | | $ | (109 | ) | | $ | 233 | |
| | | | | | | | | | | | | | | | | |
| Investor Partner units oustanding | | | 4,497 | | | | 4,497 | | | | 4,497 | | | | 4,497 | |
For the Period from September 7, 2006 (date of inception) to December 31, 2006
The Partnership had twenty-five completed and producing wells at December 31, 2006, resulting in oil and gas sales of $1,228,684 for the fourth quarter of 2006. Natural gas sales were $312,151 at an average selling price of $5.92 per Mcf, while oil sales were $916,533 at an average selling price of $54.79. Production costs for the period were $1.24 per Mcfe.
The Partnership recorded an impairment of oil and gas properties in the Bakken and Nesson fields, both in North Dakota, of $7,129,683 in the fourth quarter of 2006. The original cost of the oil and gas properties in the Bakken field was $8,279,715, which was reduced by $464,765 in depreciation and depletion recorded in 2006, resulting in a net book value of $7,814,950 at December 31, 2006. Expected discounted future cash flows for the Bakken field were $1,558,752 at December 31, 2006, resulting in an impairment charge of $6,256,198 as the fair value of the Bakken oil and gas properties exceeded the expected future cash flows. The original cost of oil and gas properties in the Nesson Field was $2,630,805, which was reduced by $21,240 in depletion and depreciation recorded in 2006, resulting in a net book value of $2,609,565 at December 31, 2006. Expected discounted future cash flows for the Nesson Field were $1,736,080 at December 31, 2006, resulting in an impairment charge of $873,485 as the fair value of the Nesson oil and gas properties exceeded the expected future cash flows. These impairment charges largely contributed to the Partnership’s December 31, 2006 net loss of $7,456,539.
In accordance with the Partnership Agreement, a one-time management fee equal to 1½% of investors’ subscriptions was charged to the Partnership in the amount of $1,349,108 by the Managing General Partner. This fee was paid by the Partnership to the Managing General Partner upon funding the Partnership.
For the three Months Ended March 31, 2007
The Partnership had thirty-three completed and producing wells at March 31, 2007, resulting in oil and gas sales of $4,204,666 for the three months ended March 31, 2007. Natural gas sales were $1,530,308 at an average selling price of $5.60 per Mcf, while oil sales were $2,674,358 at an average selling price of $45.22. Production costs for the period were $1.18 per Mcfe.
The Partnership recorded an impairment of oil and gas properties of $1,135,208 in the first quarter of 2007. Oil and gas properties located in the Nesson field in North Dakota were impaired. The original cost of the oil and gas properties was $2,663,714 which was reduced by $173,821 in accumulated depreciation and depletion and $873,485 in previous impairment charges, resulting in a net book value of $1,616,408 at March 31, 2007. Expected discounted future cash flows associated with the oil and gas properties in the Nesson field were $481,200 at March 31, 2007, resulting in an impairment change of $1,135,208, as the fair value of the oil and gas properties exceeded the expected future cash flows. This impairment charge largely contributed to the Partnership’s March 31, 2007 net loss of $3,171,015. The Partnership also recorded exploratory dry hole costs of $3,395,210 related to two exploratory wells, one in North Dakota and one in Colorado which were determined to be dry holes.
For the three Months Ended June 30, 2007
The Partnership had sixty-five completed and producing wells at June 30, 2007, resulting in oil and gas sales of $9,904,797 for the three months ended June 30, 2007. Natural gas sales were $4,267,619 at an average selling price of $5.03 per Mcf, while oil sales were $5,637,178 at an average selling price of $53.86. Production costs for the period were $1.05 per Mcfe.
The Partnership recorded an impairment of oil and gas properties of $1,310,409 in the second quarter of 2007. Oil and gas properties located in the Nesson field in North Dakota were impaired. The original cost of the oil and gas properties was $4,632,193 which was reduced by $302,091 in accumulated depreciation and depletion and $2,008,693 in previous impairment charges, resulting in a net book value of $2,321,409 at June 30, 2007. Expected future cash flows associated with the oil and gas properties in the Nesson field was $1,011,000 at June 30, 2007, resulting in an impairment change of $1,310,409 as the fair value of the oil and gas properties exceeded the expected future cash flows. The Partnership also recorded exploratory dry hole costs of $3,150,266 related to an exploratory well in North Dakota which was determined to be a dry hole.
For the three Months Ended September 30, 2007
The Partnership had ninety-one completed and producing wells at September 30, 2007, resulting in oil and gas sales of $9,470,701 for the three months ended September 30, 2007. Natural gas sales were $4,523,900 at an average selling price of $3.91 per Mcf, while oil sales were $4,946,801 at an average selling price of $66.08. Production costs for the period were $1.12 per Mcfe. The third quarter was the first profitable quarter for the partnership, with net income of $1,660,370 for the quarter.
The Partnership did not incur any impairment of oil and gas properties during the three months ended September 30, 2007. The Partnership recorded exploratory dry hole costs of $1,577,101 related to two exploratory wells in the Wattenberg Field in Colorado which were determined to be economic dry holes, as the cost of extending the pipeline to the wells to bring the gas to market was deemed economically infeasible based on current market prices and existing reserves.
Critical Accounting Policies and Estimates
We have identified the following policies as critical to the understanding of results of operations. This 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. 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 Notes to the Financial Statements. The Partnership's critical accounting policies and estimates are as follows:
Use of Estimates in Testing for Impairment of Long-Lived Assets
Impairment testing for long-lived assets and intangible assets with definite lives is required when circumstances indicate those assets may be impaired. In performing the impairment test, the Partnership would estimate the future cash flows associated with individual assets or groups of assets. Impairment must be recognized when the undiscounted estimated future cash flows are less than the related asset’s carrying amount. In those circumstances, the asset must be written down to its fair value, which, in the absence of market price information, may be estimated as the present value of its expected future net cash flows, using an appropriate discount rate. 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.
Oil and Gas Property Accounting
The Partnership accounts for its oil and gas properties under the successful efforts method of accounting. Costs of proved developed producing properties, successful exploratory wells and development dry hole costs are depreciated or depleted by the unit-of-production method based on estimated proved developed producing oil and gas reserves. Property acquisition costs are depreciated or depleted on the unit-of-production method based on estimated proved oil and gas reserves. The Partnership obtains new reserve reports from independent petroleum engineers annually as of December 31st of each year. The Partnership adjusts for any major acquisitions, new drilling and divestures during the year as needed.
Exploratory well drilling costs are initially capitalized but charged to expense if the well is determined to be nonproductive. The status of each in-progress well is reviewed quarterly to determine the proper accounting treatment under the successful efforts method of accounting. Cumulative costs on in-progress exploratory wells “Suspended Well Costs” remain capitalized until their productive status becomes known. If an in-progress exploratory well is found to be unsuccessful (referred to as a dry hole) prior to the issuance of financial statements, the costs are expensed to exploratory dry hole costs. If a final determination about the productive status of a well cannot be made prior to issuance of the financial statements, the well is classified as “Suspended Well Costs” until there is sufficient time to conduct additional completion or testing operations to evaluate the pertinent geological and engineering data obtained. When a final determination of a well’s productive status is made, the well is removed from the suspended well status and the proper accounting treatment is recorded. The determination of an exploratory well's ability to produce is made within one year from the completion of drilling activities.
Upon sale or retirement of significant portions of or complete fields of depreciable or depletable property, the book value thereof, less proceeds, is credited or charged to income. Upon sale of a partial unit of property, the proceeds are credited to property costs.
The Partnership assesses impairment of capitalized costs of proved oil and gas properties by comparing net capitalized costs to estimated undiscounted future net cash flows on a field-by-field basis using estimated production based upon prices at which management reasonably estimates such products will be sold. These estimates of future product prices may differ from current market prices of oil and gas. Any downward revisions to the Partnership's estimates of future production or product prices could result in an impairment of the Partnership's oil and gas properties in subsequent periods. If net capitalized costs exceed undiscounted future net cash flows, the measurement of impairment is based on estimated fair value which would consider future discounted cash flows.
Revenue Recognition
Sales of natural gas are recognized when natural gas has been delivered to a custody transfer point, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser, collection of revenue from the sale is reasonably assured, and the sales price is fixed or determinable. Natural gas is sold by the Managing General Partner under contracts with terms ranging from one month up to the life of the well. Virtually all of the Managing General Partner’s contracts’ pricing provisions are tied to a market index with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality of natural gas and prevailing supply and demand conditions, so that the price of the natural gas fluctuates to remain competitive with other available natural gas supplies. As a result, the Partnership’s revenues from the sale of natural gas will suffer if market prices decline and benefit if they increase. However, the Managing General Partner may from time to time enter into derivative agreements, usually with a term of two years or less which may either fix or collar a price in order to reduce the impact of market price fluctuations. The Partnership believes that the pricing provisions of its natural gas contracts are customary in the industry.
The Managing General Partner currently uses the “Net-Back” method of accounting for transportation arrangements of natural gas sales. The Managing General Partner sells gas at the wellhead, collects a price, and recognizes revenues based on the wellhead sales price since transportation costs downstream of the wellhead are incurred by the Managing General Partner’s customers and reflected in the wellhead price.
Sales of oil are recognized when persuasive evidence of a sales arrangement exists, the oil is verified as produced and is delivered from storage tanks at well locations to a purchaser, collection of revenue from the sale is reasonably assured, and the sales price is determinable. The Partnership does not refine any of its oil production. The Partnership’s crude oil production is sold to purchasers at or near the Partnership’s wells under short-term purchase contracts at prices and in accordance with arrangements that are customary in the oil industry.
(c) QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Market-Sensitive Instruments and Risk Management
The Partnership's primary market risk exposure is commodity price risk. This exposure is discussed in detail below:
Commodity Price Risk
The Managing General Partner utilizes commodity-based derivative instruments to manage a portion of the Partnership's exposure to price risk from its oil and natural gas production. These derivatives are held in the name of the Managing General Partner for the benefit of the Partnership. These arrangements have the effect of locking in for specified periods (at predetermined prices or ranges of prices) the prices the Partnership receives for the volume to which the derivative contracts relate. As a result, while these arrangements 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 associated with the derivative commodity. The Managing General Partner’s policy of prohibiting the use of natural gas futures and option contracts for speculative purposes is also applied to the Partnership.
As of September 30, 2007, the Partnership recorded a gain of $543,740 related to oil and gas price risk management and had outstanding short-term derivative receivable of $540,465 and a long-term derivative receivable of $47,582. The following table summarizes the Partnership’s share of open derivative positions as of September 30, 2007:
| Open Derivative Contracts | |
| Commodity | Type | | Quantity Gas | | | Weighted Average Price | | | Fair Market Value | |
| | | | (a) | | | | | | | |
| Partnership's share of positions as of September 30, 2007 | | | | | | | | | |
| Natural Gas | Floors | | | 1,021,893 | | | $ | 5.38 | | | $ | 695,279 | |
| Natural Gas | Ceilings | | | 841,528 | | | $ | 10.21 | | | $ | (107,232 | ) |
| Due From Managing General Partner - Derivatives, Total | | | | | | | | | | $ | 588,047 | |
| | | | | | | | | | | | | | |
| Partership's share of positions maturing within 12 months following September 30, 2007 | | | | | | | | | |
| Natural Gas | Floors | | | 932,272 | | | $ | 5.37 | | | $ | 623,173 | |
| Natural Gas | Ceilings | | | 752,008 | | | $ | 10.19 | | | $ | (82,708 | ) |
| Due From Managing General Partner - Derivatives, Short-term | | | | | | | | | | $ | 540,465 | |
(a) MMBtu - one million British thermal units. One British thermal unit is the heat required to raise the temperature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit.
At September 30, 2007, the maximum term for the derivative positions listed above is 13 months.
Derivative arrangements are entered into by the Managing General Partner on behalf of the Partnership and are reported on the Partnership’s balance sheet at fair value as a net short-term or long-term receivable or payable due from or payable to the Managing General Partner. Changes in the fair value of the Partnership’s share of derivatives are recorded in the statement of operations. As of December 31, 2006, the Partnership recorded an unrealized loss of $408 on oil and gas price risk management and had outstanding short-term derivative and long-term derivative receivables of $1,549 and $1,472, respectively. The following table summarizes the Partnership’s share of open derivative positions as of December 31, 2006:
| Open Derivative Contracts | |
| Commodity | Type | | Quantity Gas | | | Weighted Average Price | | | Fair Market Value | |
| | | | (a) | | | | | | | |
| Partnership's share of positions as of December 31, 2006: | | | | | | | | | |
| Natural Gas | Cash Settled Option Sales | | | 6,291 | | | $ | 5.25 | | | $ | 3,021 | |
| Due From Managing General Partner - Derivatives, Total | | | | | | | | | | $ | 3,021 | |
| | | | | | | | | | | | | | |
| Partership's share of positions maturing within 12 months following December 31, 2006: | | | | | | | | | |
| Natural Gas | Cash Settled Option Sales | | | 2,517 | | | $ | 5.25 | | | $ | 1,549 | |
| Due From Managing General Partner - Derivatives, Short-term | | | | | | | | | | $ | 1,549 | |
(a) MMBtu - one million British thermal units. One British thermal unit is the heat required to raise the temperature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit.
At December 31, 2006, the maximum term for the derivative positions listed above is 15 months.
Disclosure of Limitations
The Partnership's ultimate realized gain or loss with respect to commodity price fluctuations depends on the future exposures that arise during the period, the Partnership's hedging strategies at the time and commodity prices at the time.
The Partnership’s properties consist of working interests in natural gas wells and the ownership in leasehold acreage in the spacing units for the ninety-seven 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 sections titled “Drilling Prospects” and “Partnership Prospects” in “Item 1, Business” for additional information on the fields, location and development of the Partnership’s properties. In addition, see “Note 8 – Supplemental Reserve Information (Unaudited)” in the Note to the Financial Statements for additional information regarding the Partnership’s reserves related to its properties.
The Partnership commenced drilling activities immediately following funding on September 7, 2006, and as of December 31, 2006, sixty-nine wells were in progress. As of September 30, 2007 a total of ninety-seven gross wells had been drilled and the status as of that date is reflected in the table below. The Partnership���s ninety-one development wells were drilled in Colorado and North Dakota. Of the Partnership’s six exploratory wells, three exploratory wells were drilled in Colorado, and three in North Dakota.
| | Gross Wells | | Net Wells |
| Development wells: | | | |
| Drilled, completed and producing | 90 | | 89.77 |
| Dry holes | 1 | | 1.00 |
| Exploratory wells: | | | |
| Drilled, completed and producing | 1 | | .64 |
| Dry holes | 5 | | 5.00 |
| Total Wells Drilled | 97 | | 96.41 |
The ninety-seven wells in the table above are the only wells to be drilled by the Partnership since the all of the funds raised in the Partnership offering have been utilized.
As of September 30, 2007, the Partnership owned ninety-one productive wells, as follows:
| | Gross Wells | | Net Wells |
| Development wells: | | | |
| Drilled, completed and producing | 90 | | 89.77 |
| Exploratory wells: | | | |
| Drilled, completed and producing | 1 | | .64 |
| Total Productive Wells | 91 | | 90.41 |
Productive wells consist of producing wells and wells capable of producing oil and gas in commercial quantities, including gas wells awaiting pipeline connections to commence deliveries. Gross wells refers to the number of wells in which the Partnership has an interest. Net wells refers to gross wells multiplied by the percentage working interest owned by the Partnership.
Production
Production commended during the fourth quarter of 2006. For the quarter ended December 31, 2006, total production net to the Partnership’s interest was 52,706 thousand cubic feet (Mcf) of gas and 16,728 barrels (Bbls) of oil. For the nine months ended September 30, 2007, total production net to the Partnership’s interest was 2,279,359 Mcf of gas and 238,675 Bbls of oil.
Oil and Gas Reserves
Proved oil and gas reserves of the Partnership were estimated as of December 31, 2006 by an independent petroleum engineer, Ryder Scott Company, L.P., as provided for under the partnership agreement. The Partnership obtains new reserve reports from independent petroleum engineers annually as of December 31 of each year. The Partnership adjusts for any major acquisitions, new drilling and divestures during the year as needed. See “Note 8 – Supplemental Reserve Information (Unaudited)” to the financial statements for additional information regarding the Partnership’s reserves.
Title to Properties
The Partnership's interests in producing acreage are in the form of assigned direct interests in leases. Such properties are subject to customary royalty interests generally contracted for in connection with the acquisition of properties and could be subject to liens incident to operating agreements, liens for current taxes and other burdens. The Partnership believes that none of these burdens materially interfere with the use of such properties in the operation of the Partnership's business. As is customary in the oil and gas industry, little or no investigation of title is made at the time of acquisition of undeveloped properties (other than a preliminary review of local mineral records). Investigations are generally made, including in most cases receiving a title opinion of legal counsel, before commencement of drilling operations. A thorough examination of title has been made with respect to all of the Partnership's spacing units on which wells are drilled and the Partnership believes that it has generally satisfactory title to such properties.
Item 4. Security Ownership of Certain Beneficial Owners and Management.
PDC owns a 37% working interest in the Partnership.
Certain Shareholders of Petroleum Development Corporation
The following table sets forth information as of October 31, 2007, with respect to the common stock of PDC owned by each person who owns beneficially 5% or more of the outstanding voting common stock, by all directors and executive officers individually, and by all directors and officers as a group. Total shares of PDC common stock outstanding at October 31, 2007 was 14,902,762.
| Name and Address of Beneficial Owner | | Number of Shares Beneficially Owned | | Percent of Shares Beneficially Owned |
FMR Corporation 82 Devonshire Street Boston, MA 02109 | | 2,420,360 (1) | | 16.2% |
| | | | | |
Steinberg Asset Management 12 East 49th Street New York, NY 10017 | | 2,085,868 (2) | | 14.0% |
| | | | | |
Kayne Anderson Rudnick Investment Management, LLC 1800 Avenue of the Stars Los Angeles, CA 90067 | | 1,078,093 (3) | | 7.2% |
| | | | | |
Barclay’s Global Investors, NA 45 Fremont Street San Francisco, Ca 94105 | | 1,029,403 (4) | | 6.9% |
| | | | | |
Steven R. Williams 120 Genesis Boulevard Bridgeport, WV 26330 | | 326,981 (5) | | 2.2% |
| | | | | |
Thomas E. Riley 120 Genesis Boulevard Bridgeport, WV 26330 | | 107,289 (6) | | * |
| | | | | |
Eric R. Stearns 120 Genesis Boulevard Bridgeport, WV 26330 | | 63,800 (7) | | * |
| | | | | |
Richard W. McCullough 120 Genesis Boulevard Bridgeport, WV 26330 | | 2,162 (8) | | * |
| | | | | |
Darwin L. Stump 120 Genesis Boulevard Bridgeport, WV 26330 | | 33,494 (9) | | * |
| | | | | |
| Daniel W. Amidon | | - (10) | | * |
| | | | | |
| Vincent F. D'Annunzio | | 21,779 (11) | | * |
| | | | | |
| Jeffrey C. Swoveland | | 10,158 (12) | | * |
| | | | | |
| Kimberly Luff Wakim | | 3,099 (13) | | * |
| | | | | |
| David C. Parke | | 1,371 (14) | | * |
| | | | | |
| Anthony J. Crisafio | | - (15) | | * |
| | | | | |
| Joseph E. Casabona | | - (16) | | * |
| | | | | |
| Larry F. Mazza | | - (16) | | * |
| | | | | |
| All directors and executive officers as a group (13 persons) | | 570,132 (17) | | 3.8% |
| | | | | |
| Shares Outstanding at October 31, 2007 | | 14,902,762 | | 100.0% |
| (1) | According to the Schedule 13G filed by FMR Management with the Securities and Exchange Commission on February 14, 2007. |
| (2) | According to the Schedule 13G filed by Steinberg Asset Management with the Securities and Exchange Commission on February 9, 2007. |
| (3) | According to the Schedule 13G filed by Anderson Rudnick Investment Management with the Securities and Exchange Commission on February 5, 2007. |
| (4) | According to the Schedule 13G filed by Barclays Global Investors, NA Management with the Securities and Exchange Commission on January 23, 2007. |
| (5) | Includes 6,281 shares subject to options exercisable and 2,032 shares of restricted stock vesting within 60 days of October 31, 2007, excludes 17,528 restricted shares subject to vesting greater than 60 days. |
| (6) | Includes 4,151 shares subject to options exercisable and 1,347 share of restricted stock vesting within 60 days of October 31 2007, excludes 12623 restricted shares subject to vesting greater than 60 days. |
| (7) | Includes 3,845 shares subject to options exercisable and 1,270 share of restricted stock vesting within 60 days of October 31, 2007, excludes 11,327 restricted shares subject to vesting greater than 60 days. |
| (8) | Includes 833 shares subject to options exercisable and 1,064 shares of restricted stock vesting within 60 days of October 31, 2007; excludes 3,192 restricted shares subject to vesting greater than 60 days. |
| (9) | Includes 3,467 shares subject to options exercisable and 1,195 share of restricted stock vesting within 60 days of October 31, 2007, excludes 8,121 restricted shares subject to vesting greater than 60 days. |
| (10) | Excludes 4,300 restricted shares subject to vesting greater than 60 days. |
| (11) | Excludes 2,000 restricted shares subject to vesting greater than 60 days. |
| (12) | Excludes 4,758 restricted shares subject to vesting greater than 60 days. |
| (13) | Excludes 3,379 restricted shares subject to vesting greater than 60 days. |
| (14) | Excludes 4,758 restricted shares subject to vesting greater than 60 days. |
| (15) | Excludes 3,035 restricted shares subject to vesting greater than 60 days. |
| (16) | Excludes 1,355 restricted share subject to vesting greater than 60 days which were granted to each of Mr. Casabona and Mr. Mazza on November 9, 2007. |
| (17) | Includes 18,577 shares subject to options exercisable within 60 days of October 31, 2007, excludes 75,021 restricted shares subject to vesting. |
Item 5. Directors and Executive Officers
General Management
The Managing General Partner of the Partnership is Petroleum Development Corporation ("PDC"), a publicly-owned Nevada corporation organized in 1955. The common stock of PDC is traded on the Nasdaq Global Select Market under the symbol "PETD." Since 1969, PDC has been engaged in the business of exploring for, developing and producing oil and natural gas primarily in West Virginia, Tennessee, Pennsylvania, Ohio, Michigan and the Rocky Mountains. As of November 30, 2007, PDC had approximately 260 employees. PDC will make available to Investor Partners, upon request, audited financial statements of PDC for the most recent fiscal year and unaudited financial statements for interim periods. PDC's Internet address is www.petd.com. PDC posts on its Internet Web site its periodic and current reports and other information, including its audited financial statements, that it files with the Securities and Exchange Commission, as well as various charters and other corporate governance information.
As the managing general partner, PDC actively manages and conducts the business of the Partnership. PDC has the full and complete power to do any and all things necessary and incident to the management and conduct of the Partnership's business. PDC is responsible for maintaining Partnership bank accounts, collecting Partnership revenues, making distributions to the partners, delivering reports to the partners, and supervising the drilling, completion, and operation of the Partnership's natural gas and oil wells.
In addition to managing the affairs of the Partnership, the management and technical staff of PDC also manage the corporate affairs of PDC, the affairs of thirty-three (33) limited partnerships formed in the current and previous programs, and other joint ventures formed over the years. PDC owns an interest in all of the older limited partnerships and wells. Because PDC must divide its attention and efforts among many unrelated parties, the Partnership does not receive its full attention or efforts at all times, however, PDC believes that it devotes sufficient time, attention and expertise to the Partnership to appropriately manage the affairs of the Partnership.
Experience and Capabilities as Driller/Operator
PDC is contracted to serve as operator for the Partnership wells. Since 1969, PDC has drilled over 3,100 wells in Colorado, West Virginia, Tennessee, Ohio, Michigan, North Dakota, Utah, Wyoming, and Pennsylvania. PDC currently operates approximately 3,400 wells.
PDC employs geologists who develop prospects for drilling by PDC and who help oversee the drilling process. In addition, PDC has an engineering staff that is responsible for well completions, pipelines, and production operations. PDC retains drilling subcontractors, completion subcontractors, and a variety of other subcontractors in the performance of the work of drilling contract wells. In addition to technical management, PDC may provide services, at competitive rates, from PDC-owned service rigs, a water truck, steel tanks used temporarily on the well location during the drilling and completion of a well, roustabouts, and other assorted small equipment and services. A roustabout is an oil and gas field employee who provides skilled general labor for assembling well components and other similar tasks. PDC may lay short gathering lines, or may subcontract all or part of the work where it is more cost effective for the Partnership. PDC employs full-time well tenders and supervisors to operate its wells. In addition, the engineering staff evaluates reserves of all wells at least annually and reviews well performance against expectations. All services provided by PDC are provided at rates less than or equal to prevailing rates for similar services provided by unaffiliated persons in the area.
Petroleum Development Corporation
The executive officers and directors of PDC, their principal occupations for the past five years and additional information are set forth below:
The executive officers named below are full-time employees of PDC. As such, they devote the entirety of their daily time to the business and operations of PDC. One of the major business segments of PDC includes the operation of the business of PDC's sponsored limited partnerships, including the Partnership. An element of their job responsibilities requires that they devote such time and attention to the business and affairs of the Partnership as is reasonably required. This time commitment varies for each individual and varies over the life of the Partnership.
| Name | | Age | | Positions and Offices Held | | Director Since | | Directorship Term Expires |
| | | | | | | | | |
| Steven R. Williams | | 56 | | Chairman, Chief Executive Officer and Director | | 1983 | | 2009 |
| | | | | | | | | |
| Thomas E. Riley | | 55 | | President and Director | | 2004 | | 2010 |
| | | | | | | | | |
| Eric R. Stearns | | 49 | | Executive Vice President – Exploration and Production | | - | | - |
| | | | | | | | | |
| Richard W McCullough | | 56 | | Chief Financial Officer | | - | | - |
| | | | | | | | | |
| Darwin L. Stump | | 52 | | Chief Accounting Officer | | - | | - |
| | | | | | | | | |
| Daniel W. Amidon | | 47 | | General Counsel, Secretary | | - | | - |
| | | | | | | | | |
| Vincent F. D'Annunzio | | 55 | | Director | | 1989 | | 2010 |
| | | | | | | | | |
| Jeffrey C. Swoveland | | 52 | | Director | | 1991 | | 2008 |
| | | | | | | | | |
| Kimberly Luff Wakim | | 49 | | Director | | 2003 | | 2009 |
| | | | | | | | | |
| David C. Parke | | 40 | | Director | | 2003 | | 2008 |
| | | | | | | | | |
| Anthony J. Crisafio | | 54 | | Director | | 2006 | | 2009 |
| | | | | | | | | |
| Joseph E. Casabona | | 64 | | Director | | 2007 | | 2008 |
| | | | | | | | | |
| Larry F. Mazza | | 47 | | Director | | 2007 | | 2008 |
Steven R. Williams was elected Chairman and Chief Executive Officer in January 2004. Mr. Williams served as President from March 1983 until December 2004 and has been a Director of PDC since 1983.
Thomas E. Riley was elected Director in January 2004 by the Board of Directors and assumed the position of President in December 2004. Previously, Mr. Riley was appointed Executive Vice President of Production, Natural Gas Marketing and Business Development in November 2003. Prior thereto, Mr. Riley served as Vice President Gas Marketing and Acquisitions of PDC since April 1996. Prior to joining us, Mr. Riley was president of Riley Natural Gas Company, a natural gas marketing company which PDC acquired in April 1996.
Richard W. McCullough was appointed Chief Financial Officer in November 2006 and also served as PDC’s Treasurer from November 2006 until October 2007. Prior to joining us, Mr. McCullough served as president and chief executive officer of Gasource, LLC, Dallas, Texas, a marketer of long-term, natural gas supplies. From 2001 to 2003, Mr. McCullough served as an investment banker with J.P. Morgan Securities, Atlanta, Georgia, and served 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. Mr. McCullough, a CPA, was a practicing certified public accountant for 8 years.
Darwin L. Stump was appointed Chief Accounting Officer in November 2006. Mr. Stump has been an officer of PDC since April 1995 and held the position of Chief Financial Officer and Treasurer from November 2003 until November 2006. Previously, Mr. Stump served as Corporate Controller from 1980 until November 2003. Mr. Stump, a CPA, was a senior accountant with Main Hurdman, Certified Public Accountants prior to joining PDC.
Eric R. Stearns was appointed Executive Vice President of Exploration and Production in December 2004. Prior to his current position, Mr. Stearns was Executive Vice President of Exploration and Development since November 2003, having previously served as Vice President of Exploration and Development since April 1995. Mr. Stearns joined PDC as a geologist in 1985 after working at Hywell, Incorporated and for Petroleum Consultants.
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.
Vincent F. D'Annunzio has served as president of Beverage Distributors, Inc., located in Clarksburg, West Virginia since 1985. Mr. D’Annuzio has served as a Director since 1989.
Jeffrey C. Swoveland is the Chief Operating Officer of Coventina Healthcare Enterprises, a medical device company specializing in therapeutic warming and multi-modal treatment systems used in the treatment, rehabilitation and management of pain since May 2007. Previously, 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, from September 2000 to May 2007. 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 1997 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 has served as a Director since 1991.
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. Ms. Wakim has practiced law with Thorp, Reed & Armstrong LLP since 1990. Ms. Wakim has served as a Director since 2003.
David C. Parke is a Managing Director in the investment banking group of Boenning & Scattergood, Inc., West Conshohocken, PA, 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 as a member of the board of directors of Zunicom Inc., a public company providing business communication services to the hospitality industry. Mr. Parke has served as a Director since 2003.
Anthony J. Crisafio was elected to the Board in October 2006. Mr. Crisafio, a Certified Public Accountant, serves as an independent business consultant, providing financial and operational advice to businesses and has done so since 1995. He owned two small businesses during the period 1991 to 2002. Additionally, Mr. Crisafio has served as the Chief Operating Officer of Cinema World, Inc. from 1989 until 1993 and was a partner with Ernst & Young from 1986 until 1989.
Joseph E. Casabona was elected to the Board in October 2007 by the Board of Directors. Mr. Casabona served as Executive Vice President and member of the Board of Directors of Denver based Energy Corporation of America, or ECA, from 1985 to his retirement earlier this year. ECA combines Appalachian Basin natural gas development, deep exploration, marketing, and pipeline gathering and transportation to industrial end users, utility purchasers and other customers with higher risk, higher reward exploratory drilling in Texas and internationally.
Larry F. Mazza was elected to the Board in October 2007 by the Board of Directors. Mr. Mazza has served a Chief Executive Officer of MVB Bank Harrison, Inc., in Bridgeport, West Virginia since March 2005. Prior to the formation of MVB Bank Harrison, Mr. Mazza served as Senior Vice President Retail Banking Manager for BB&T in West Virginia, where he was employed from June 1986 to March 2005.
The Audit Committee of the Board of Directors is comprised of Directors Swoveland, Crisafio, Parke, Wakim and Casabona. The Board has determined that the Audit Committee is comprised entirely of independent directors as defined by the NASDAQ rule 4200(a)(15). Jeffrey C. Swoveland chairs the Audit Committee. Mr. Swoveland and the other audit committee members, with the exception of Mr. Parke, qualify as audit committee financial experts and are independent of management.
Item 6. 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. The management fee and other amounts paid the Managing General Partner by the Partnership are not used to directly compensate or reimburse PDC’s officers or directors. These persons receive compensation solely from PDC. Information as to compensation paid by PDC to its directors and executive officers may be obtained from publicly available reports filed by PDC with the Securities and Exchange Commission under the Securities Exchange Act of 1934. This information is also available on PDC's Internet website at www.petd.com.
Compensation Committee Interlocks and Insider Participation
There are no Compensation Committee interlocks.
Item 7. Certain Relationships and Related Transactions, and Director Independence
Compensation to the Managing General Partner and Affiliates
| Recipient | Transaction | Compensation September 7, 2006 (date of inception) to December 31, 2006 | Compensation Nine Months Ended September 30, 2007 |
| Managing General Partner | Drilling compensation | $3,244,129 | $9,979,305 |
| Managing General Partner | Operator's monthly per-well charges and services | $28,102 | $333,726 |
| Managing General Partner | Purchased partnership interest | $38,912,342 | $ - |
| Managing General Partner | Sale of leases to the partnership | $630,091 | $897,464 |
| Managing General Partner | Contract drilling rates | $25,116,964 | $78,303,373 |
| Managing General Partner | Gathering, compression and processing | $14,465 | $153,224 |
| Managing General Partner and Affiliates | Gas marketing, supplies and equipment | $33,029 | $1,388,522 |
| Managing General Partner | Direct costs | $176,613 | $140,957 |
| Affiliate | Organization and offering costs | $9,084,039 | $ - |
| Managing General Partner | One-time management fee | $1,349,108 | $ - |
Drilling Costs - The Partnership entered into the drilling and operating agreement with the Managing General Partner to drill and complete the Partnership's wells at cost plus the Managing General Partner's drilling compensation of 12.6% of the total well cost. The Managing General Partner charges a drilling overhead rate of 1½% of drilling authority for expenditure (“AFE”) for each well. This overhead rate is included in the total well cost for the drilling compensation calculation. If the Managing General Partner provides other services in the drilling and completion of the wells, it charges those services at its cost, not to exceed competitive rates charged in its area of operation and these charges are included in the total well cost when determining the Managing General Partner's drilling compensation.
Cost, when used with respect to services, generally means the reasonable, necessary, and actual expense incurred in providing the services, determined in accordance with generally accepted accounting principles. The cost of the well also includes all ordinary costs of drilling, testing and completing the well.
The well costs charged to the Partnership are proportionately reduced to the extent the Partnership acquires less than 100% of the working interest in a prospect. The amount of compensation that the Managing General Partner could earn as a result of these arrangements depends on the degree to which it provides services for the wells, and the number and type of wells that are drilled. If the Managing General Partner supplies other goods and services to the Partnership, it is required to supply them at cost, and they will be included in the total well costs for determining the Managing General Partner's and the investors' contributions, the division of oil and gas revenues, and calculation of the Managing General Partner's drilling compensation
Per Well Charges - Under the drilling and operating agreement, the Managing General Partner, as operator of the wells, receives the following from the Partnership when the wells begin producing:
| · | 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 operator receives a monthly fee for each producing well based upon competitive industry rates for operations and field supervision and $100 for Partnership accounting, engineering, management, and general and administrative expenses. The operator bills non-routine operations and administration costs to the Partnership at its cost. The Managing General Partner may not benefit by interpositioning 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 partnership 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:
| · | the purchase of equipment, materials, or third-party services; |
| · | the cost of compression and third-party gathering services, or gathering costs; |
| · | rebuilding of access roads. |
These costs are charged at the invoice cost of the materials purchased or the third-party services performed.
Natural Gas and Oil Revenues - The limited partnership agreement provides for the allocation of revenues from natural gas and oil production 63% to the Investors Partners and 37% to PDC. However, the partnership sharing arrangements may be revised in the event PDC invests capital above PDC’s required minimum capital contribution to cover additional tangible drilling and lease costs, in which case PDC’s share would increase. See “Participation in Costs and Revenues” in Item 9 below. PDC has contributed capital of $38,912,342 to the Partnership as of September 30, 2007 in exchange for the 37% allocation of revenues.
Sale of Leases to the Partnership– The managing general partner sells undeveloped prospects to the Partnership to drill the Partnership’s wells. Leases are sold to the Partnership at the lower of the managing general partner’s cost to purchase the lease or the leases’ fair market value.
Direct Costs– The managing general partner is reimbursed by the Partnership for all direct costs expended by them on our behalf for administrative and professional fees, such as legal expenses, audit fees and engineering fees for reserve reports.
Organization and Offering Costs– The Partnership reimbursed the managing general partner for dealer manager commissions, discounts, and due diligence costs, marketing and support expenses and wholesaling fees, up to 10.5% of subscriptions as outlined in the partnership agreement.
Management Fee– In accordance with the Partnership Agreement, a one-time management fee equal to 1½% of investors’ subscriptions was charged to the Partnership by the Managing General Partner. This fee was paid by the Partnership to the Managing General Partner upon funding the Partnership.
Gathering, Compression and Processing Fees - Under the limited partnership agreement, the Managing General Partner is responsible for gathering, compression, processing and transporting the natural gas produced by the Partnership to interstate pipeline systems, local distribution companies, and/or end-users in the area from the point the gas from the well is commingled with 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 natural gas.
Gas Marketing, Supplies and Equipment - PDC 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. PDC intends to market some of the gas produced through its subsidiary, Riley Natural Gas. Charges for those services are at competitive rates.
Related Party Transaction Policies and Approval
The limited partnership agreement governs the related party transactions, including those described above. We have no written policies or procedures for the review, approval or ratification of transactions with related persons outside the limited partnership agreement.
Other Agreements and Arrangements
Executive officers of the Managing General Partner are eligible to invest in a Board-approved executive drilling program, as approved by the Board of Directors. The eligible executive officers under this program are Steven R. Williams, Thomas E. Riley, Richard W. McCullough, Darwin L. Stump, Daniel W. Amidon, and Eric R. Stearns.
These executive officers may profit from their participation in the executive drilling program because they invest in wells at cost and do not have to pay drilling compensation, management fees or broker commissions and therefore obtain an interest in the wells at a reduced price than that which is generally charged to the investing partners in a Partnership. Other investors participating in drilling through a Partnership are 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 on “Item 7, Compensation to the Managing General Partner and Affiliates.” As a result, the executive officers realize a benefit not generally available to other investors.
During 2006, Messrs. Williams, Riley and Stump invested approximately $40,000, $20,000 and $17,000, respectively in the executive drilling program. Through the executive drilling program, Messrs. Williams and Riley have invested in the wells owned by the Partnership. Messrs. Williams’ and Riley’s ownership in Partnership wells varies depending on when the well was drilled and the amount of funds invested in the program, but ranges from no interest up to .038. None of the other executive offices eligible for the drilling program have an ownership interest in the Partnership’s wells. The Board believes that having the executive officers invest in wells with the Company and other investors helps to create a commonality of interests much like share ownership creates a commonality of interests between the shareholders and executive officers.
The Registrant is not currently subject to any legal proceedings.
PDC, the Managing General Partner, is subject to certain legal proceedings arising from the normal course of business in its capacity as driller and well operator. As discussed in “Item 1, Properties, Title to Properties”, properties owned by the Partnership are not subject to claims of the Managing General Partner’s creditors. PDC has been named as defendant in two class action lawsuits. Although at this time the Partnership has not been named as a party, the lawsuits allege that they cover substantially all wells operated by PDC, including the wells owed by the Partnership. See “Note 10 – Commitments and Contingencies” in the Notes to the Financial Statements for additional information related to this litigation.
| Market Price of and Dividends on the Registrant's Common Equity and Related Stockholder Matters. |
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 be able to sell them only for less than fair market value. The offer and sale of the Partnership's additional general partnership interests and limited partnership interests ("units") have not been registered under the Securities Act or under any state securities laws. Each purchaser of units was required to represent that such investor was purchasing the units for his or her own account for investment and not with a view to parallel distribution. No transfer of a unit may be made unless the transferee is an "accredited investor" and such transfer is registered under the Securities Act and applicable state securities laws, or an exemption therefrom is available. The Partnership may require that the transferor provide an opinion of legal counsel stating that the transfer complies with all applicable securities laws. A sale or transfer of units by an Investor Partner requires PDC's prior written consent. For these and other reasons, an investor must anticipate that he or she will have to hold his or her partnership interests indefinitely and will not be able to liquidate his or her investment in the Partnership. Consequently, an investor must be able to bear the economic risk of investing in the Partnership for an indefinite period of time.
Cash Distribution Policy. PDC plans to make distributions of Partnership cash on a monthly basis, but makes distributions no less often than quarterly, if funds are available for distribution. PDC will make cash distributions of 63% to the Investor Partners and 37% to the Managing General Partner throughout the term of the Partnership.
PDC cannot presently predict amounts of cash distributions, if any, from the Partnership. However, PDC expressly conditions any distribution upon its having sufficient cash available for distribution. Sufficient cash available for distribution is defined to generally mean 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 debt instruments or other agreements or to provide for future distributions to unitholders. 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 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 investors in prior drilling programs sponsored by PDC, or that any level of cash distributions can be maintained.
In general, the volume of production from producing properties declines with the passage of time. The cash flow generated by the Partnership's activities and the amounts available for distribution to the Partnership's respective partners will, therefore, decline in the absence of significant increases in the prices that the Partnership receives for its oil and natural gas production, or significant increases in the production of oil and natural gas from prospects resulting from the successful additional development of these prospects. If the Partnership decides to develop its wells further, the funds necessary for that development would come from the Partnership's revenues and/or from borrowed funds. As a result, there may be a decrease in the funds available for distribution, and the distributions to the Investor Partners may decrease.
In general, PDC divides cash distributions 63% to the Investor Partners and 37% to PDC throughout the term of the Partnership. Cash is distributed to the Investor Partners and PDC as a return on capital, in the same proportion as their interest in the net income of the Partnership. However, no Investor Partner will receive distributions to the extent the distributions would create or increase a deficit in that partner's capital account.
PDC intends to develop the Partnership's interests in its prospects only with the proceeds of subscriptions and PDC's capital contributions. However, these funds may not be sufficient to fund all future well costs, and it may be necessary for the Partnership to retain Partnership revenues for the payment of these costs, or for PDC to advance the necessary funds to the Partnership or for the Partnership to borrow necessary funds. It is likely that the Partnership's Wattenberg Field, Colorado wells will benefit from recompletion services, generally in five years or longer following initial drilling of those wells. Recompletion is the process of going into an existing zone which is already producing for a refrac, or going into a new zone at a different depth, all with the objective of increasing the production of oil or natural gas. If PDC retains Partnership revenues for the payment of these recompletion or refrac costs, the amount of Partnership funds available for distribution to the partners of the Partnership will decrease correspondingly. Development work will not include the drilling of any new wells beyond the initial wells that have been drilled. PDC may retain payment for the recompletion or refrac work from Partnership proceeds in one of two methods:
| · | PDC will prepare an AFE estimate for the Partnership; PDC will complete the development work and will bill the Partnership for the work performed and will be reimbursed from future production; or |
| · | PDC will prepare an AFE estimate for the Partnership; the Partnership will retain revenues from operations until it has accumulated sufficient funds to pay for the development work, at which time PDC will commence the work, and PDC will be reimbursed as the work progresses from retained revenues. |
Should PDC decide to retain Partnership revenues for the payment of recompletion or refract costs, the determination of which option to use will be at PDC's discretion, based on the amount of the anticipated expenditure and the urgency of the necessary work.
The limited partnership agreement also permits the Partnership to borrow funds on behalf of the Partnership for Partnership activities. The Partnership may borrow needed funds, or receive advances, from the Managing General Partner or affiliates of the Managing General Partner or from unaffiliated persons. On loans or advances made available to the Partnership by the Managing General Partner or affiliates of the Managing General Partner, the Managing General Partner or affiliate may not receive interest in excess of its interest costs, nor may the Managing General Partner or affiliate receive interest in excess of the amounts which would be charged the Partnership (without reference to the Managing General Partner's financial abilities or guarantees) by unrelated banks on comparable loans for the same purpose. The Managing General Partner anticipates that borrowed funds will be utilized to finance Codell recompletion activities (see “Item 1, Business”). Because the Partnership will have to pay interest on any borrowed funds, the amount of Partnership funds available for distribution to the partners of the Partnership may be reduced accordingly.
Investors who are independent producers are entitled to claim a percentage depletion deduction against their oil and gas income. The percentage depletion rate for oil and gas properties is generally 15% of the gross income generated by the property.
PARTICIPATION IN COSTS AND REVENUES
Profits and Losses; Cash Distributions
The limited partnership agreement provides for the allocation of profits and losses during the production phase of the Partnership and for the distribution of cash available for distribution between Investor Partners and PDC, as follows:
| | Investor Partners | PDC, Managing General Partner |
| Throughout term of Partnership | 63% | 37% |
Sharing Arrangements The limited partnership agreement provides for the allocation of Partnership profits and losses, 63% to the Investor Partners and 37% to PDC, throughout the term of the Partnership. However, amounts are paid to the 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 foregoing allocation of profits and losses is an allocation of each item of income, gain, loss, and deduction which, in the aggregate, constitute a profit or a loss.
Revenues
Natural Gas and Oil Revenues. The limited partnership agreement provides for the allocation of revenues from natural gas and oil production, 63% to the Investor Partners and 37% to PDC. However, the partnership sharing arrangements may be revised in the event PDC invests capital above PDC’s required minimum capital contribution to cover additional tangible drilling and lease costs, in which case PDC’s share would increase. See “Lease Costs, Tangible Well Costs, and Gathering Line Costs” below.
Interest Income. PDC allocates and credits interest earned on the deposit of operating revenues and revenues from any other sources in the same percentages that oil and natural gas revenues are then being allocated to the Investor Partners and PDC.
Sale of Equipment. PDC allocates all revenues from sales of equipment in the same percentages as oil and natural gas revenues are then being allocated.
Sale of Productive Properties. In the event of the sale or other disposition of a productive well, a lease upon which the well is situated, or any equipment related to that lease or well, PDC will allocate and credit to the Investor Partners and PDC, the gain from the sale or disposition, in the same percentages as oil and gas revenues are then being allocated. The term "proceeds" above does not include revenues from a royalty, overriding royalty, lease interest reserved, or other promotional consideration reserved by the Partnership in connection with any sale or disposition. PDC will allocate these revenues to the Investor Partners and PDC in the same percentages as the allocation of oil and natural gas revenues.
Costs
Lease Costs, Tangible Well Costs, and Gathering Line Costs. PDC pays 100% of the costs of leases, tangible well costs and gathering line costs.
PDC contributes and/or pays for the Partnership’s share of all leases, tangible drilling and completion costs, and gathering line costs, but not less than 37% of the well costs excluding PDC’s drilling compensation. If these costs exceed PDC’s required capital contribution, PDC will increase its capital contribution. In that event, PDC’s share of all items of profit and loss during the production phase of operations and cash available for distribution would be modified to equal for PDC the percentage arrived at by dividing PDC’s capital contributions by the total well costs, excluding PDC’s drilling compensation; the Investor Partners’ allocations of these items would be changed accordingly.
Intangible Drilling Costs (IDC): Intangible drilling costs are costs required to drill a well and prepare the well for production. These costs have no salvage value. Items like the cost of drilling and completing the well, the cost of grading the surface, labor costs, and geological costs associated with selecting a well site are intangible well costs. IDC is allocated 100% to the Investor Partners.
Operating Costs: Operating costs are the costs at the well level associated with producing and maintaining productive wells, like well tending charges, painting equipment and maintaining access roads. PDC allocates and charge operating costs of Partnership wells 63% to the Investor Partners and 37% to PDC.
Direct Costs: Direct costs are Partnership level costs, primarily professional fees of the independent auditor and reserve engineer and tax return and other similar costs. PDC allocates and charges direct costs of the Partnership 63% to the Investor Partners and 37% to PDC.
The table below summarizes the participation of the Investor Partners and PDC, taking account of PDC's capital contribution, in the costs and revenues of the Partnership:
| | | Investor
Partners | | | Managing
General Partner | |
| Partnership Costs | | | | | | |
| | | | | | | |
| Broker-dealer Commissions and Expenses | | | 100 | % | | | 0 | % |
| Management Fee | | | 100 | % | | | 0 | % |
| Undeveloped Lease Costs | | | 0 | % | | | 100 | % |
| Tangible Well Costs | | | 0 | % | | | 100 | % |
| Intangible Drilling Costs (IDC) | | | 100 | % | | | 0 | % |
| Managing General Partner's Drilling Compensation | | | 100 | % | | | 0 | % |
| Direct Drilling and Compensation Costs, excluding Managing General Partner’s Drilling Compensation | | | 63 | % | | | 37 | % |
| Operating Costs | | | 63 | % | | | 37 | % |
| Direct Costs | | | 63 | % | | | 37 | % |
| Organization Costs | | | 0 | % | | | 100 | % |
| | | | | | | | | |
| Partnership Revenues | | | | | | | | |
| | | | | | | | | |
| Sale of Oil and Gas Production | | | 63 | % | | | 37 | % |
| Sale of Productive Properties | | | 63 | % | | | 37 | % |
| Sale of Equipment | | | 63 | % | | | 37 | % |
| Sale of Undeveloped Leases | | | 63 | % | | | 37 | % |
| Interest Income | | | 63 | % | | | 37 | % |
Allocations Among Investor Partners; Deficit Capital Account Balances
PDC allocates the Investor Partners' share of revenues and costs of the Partnership among them in the same proportion as each Investor Partner's capital contribution bears to the aggregate of the capital contributions of all Investor Partners in the Partnership.
To avoid the requirement of restoring a deficit capital account balance, there will be no allocations of losses to an Investor Partner to the extent those allocations would create or increase a deficit in his or her capital account (adjusted for liabilities, as provided in the limited partnership agreement).
Termination
Upon termination and final liquidation of the Partnership, PDC will distribute the assets of the Partnership to the partners based upon their capital account balances. If PDC has a deficit in its capital account, PDC must restore the deficit; however, no Investor Partner will be obligated to restore his or her deficit, if any.
Amendment of Partnership Allocation Provisions
PDC is authorized to amend the limited partnership agreement, if, in its sole discretion based on advice from its legal counsel or accountants, an amendment to revise the cost and revenue allocations is required for those allocations to be recognized for federal income tax purposes because of either the promulgation of Treasury Regulations or other developments in the tax law. Any new allocation provisions provided by an amendment must be made in a manner that would result in the most favorable aggregate consequences to the Investor Partners as nearly as possible consistent with the original allocations described in the limited partnership agreement. See Section 11.09 of the limited partnership agreement.
| Recent Sales of Unregistered Securities. |
The Registrant was funded on September 7, 2006 upon completion of the private placement of its securities. The offering was made solely to accredited investors, as that term is defined by Rule 501(a) under the Securities Act of 1933, and was effected in reliance upon §4(2) of the Securities Act and Rule 506 thereunder. The Partnership sold for cash $89,940,527 of its securities in the offering. The dealer-manager of the offering was PDC Securities Incorporated, an NASD-registered broker-dealer. PDC Securities Incorporated is an affiliate of Petroleum Development Corporation, the managing general partner of the Partnership. For additional information, see “Item 1, Business” and “Item 7, Certain Relationship and Related Transactions and Director Independence – Compensation to Managing General Partner and Affiliates.”
| Description of Registrant's Securities to be Registered. |
Units of Partnership Interest. In its offering, the Partnership sold units of general partnership interest and units of limited partnership interest in the partnership. "Unit" means the partnership interest purchased by a limited partner or an additional general partner. This interest is the right and obligation to share a proportional part of the Investor Partners' share of Partnership income, expense, assets and liabilities. The fractional interest purchased by a one unit investment in the Investor Partners' interest in the Partnership is the ratio of one unit to the total number of units sold. A general partner, excluding the managing general partner, referred to as “other general partners” will be able to apply tax deductions generated by the Partnership to reduce his/her federal adjusted gross income regardless of the source of the income, but he/she will have unlimited liability for the drilling and completion activities of the Partnership. An individual investor who invested as a limited partner will be able to use his/her deductions to reduce taxable income only from passive sources. The Internal Revenue Service defines passive income as income from partnership and rental activities. One's liability as a limited partner is restricted to his/her investment in the Partnership.
Conversion of Units by the Managing General Partner and by Other General Partners. PDC will convert all units of other general partnership interest of the Partnership into the same dollar amount of units of limited partnership interest of the Partnership subsequent to the completion of drilling operations of the Partnership. Prior to that time, other general partners may convert their units of additional general partnership interest into units of limited partnership interest if there is a material change in the amount of the Partnership's insurance coverage. PDC must notify the other general partners if there is a material reduction of the insurance coverage, and those partners will be able to require PDC to convert their interests any time during the 30 days preceding the change. Other general partners will not be able to convert their interest if the conversion would cause a termination of the Partnership for federal tax purposes. General Partners of this Partnership were converted to limited partners in September, 2007.
Unit Repurchase Provisions. Investor Partners may request that the Managing General Partner repurchase units at any time beginning with the third anniversary of the first cash distribution of the Partnership. The repurchase price is set at a minimum of four times the most recent twelve months’ of cash distributions from production. The Managing General Partner is obligated to purchase, in any calendar year, Investor Partner units aggregating to 10% of the initial subscriptions if requested by the Investor Partners, subject to its financial ability to do so and opinions of counsel. Repurchase requests are fulfilled by the Managing General Partner on a first-come, first-served basis. No partnership units can be repurchased under this provision by the Managing General Partner until thirty-six months after the date of the first distribution to the partners.
SUMMARY OF LIMITED PARTNERSHIP AGREEMENT
The limited partnership agreement in the form filed as an exhibit to this registration statement will govern all partners' rights and obligations. The following statements concerning the limited partnership agreement are merely a summary of all the material terms of the limited partnership agreement, but do not purport to be complete and in no way amend or modify the limited partnership agreement.
Responsibility of Managing General Partner
The Managing General Partner shall have the exclusive management and control of all aspects of the business of the Partnership (see sections 5.01 and 6.01 of the limited partnership agreement). No Investor Partner shall have any voice in the day-to-day business operations of the Partnership (see section 7.01 of the limited partnership agreement). The Managing General Partner is authorized to delegate and subcontract its duties under the limited partnership agreement to others, including entities related to it (See section 5.02 of the limited partnership agreement).
Liability of General Partners, Including Additional General Partners
General partners, including additional general partners, have unlimited liability for Partnership activities. The additional general partners are jointly and severally liable for all obligations and liabilities to creditors and claimants, whether arising out of contract or tort, in the conduct of Partnership operations (see section 7.12 of the limited partnership agreement).
PDC, as operator, maintains general liability insurance. In addition, PDC has agreed to indemnify each additional general partner for obligations related to casualty and business losses which exceed available insurance coverage and Partnership assets (See section 7.02 of the limited partnership agreement).
The additional general partners, by execution of the limited partnership agreement, grant to the Managing General Partner the exclusive authority to manage the Partnership business in its sole discretion and to bind the Partnership and all partners in its conduct of the Partnership business. The additional general partners may not participate in the management of the Partnership business; and the limited partnership agreement prohibits the additional general partners from acting in a manner harmful to the assets or the business of the Partnership or to do any other act which would make it impossible to carry on the ordinary business of the Partnership. If an additional general partner acts contrary to the terms of the limited partnership agreement, losses caused by his or her actions will be borne by that additional general partner alone and that additional general partner may be liable to other partners for all damages resulting from his or her breach of the limited partnership agreement. Section 7.01. Additional general partners who choose to assign their units in the future may do so only as provided in the limited partnership agreement. Liability of partners who have assigned their units may continue after the assignment unless a formal assumption and release of liability is affected (see section 7.03 of the limited partnership agreement).
Liability of Limited Partners
The West Virginia Uniform Limited Partnership Act governs the Partnership, under which law a limited partner's liability for the obligations of the Partnership is limited to his or her capital contribution, his or her share of Partnership assets and the return of any part of his or her capital contribution for a period of one year after the return (or six years in the event the return is in violation of the limited partnership agreement). A limited partner will not otherwise be liable for the obligations of the Partnership unless, in addition to the exercise of his or her rights and powers as a limited partner, the person takes part in the control of the business of the Partnership (see section 7.01of the limited partnership agreement).
Allocations and Distributions
General: Profits and losses are to be allocated and cash is to be distributed in the manner described in “Item 7, Certain Relationships and Related Transactions, and Director Independence” and “Item 9, Market Price of and Dividends on the Registrant's Common Equity and Related Stockholder Matters," above (see Article III of the limited partnership agreement).
Time of Distributions: The Managing General Partner will determine and distribute not less frequently than quarterly cash available for distribution (see section 4.01 of the limited partnership agreement). The Managing General Partner may, at its discretion, make distributions more frequently. Notwithstanding any other provision of the limited partnership agreement to the contrary, no partner will receive any distribution to the extent the distribution will create or increase a deficit in that partner's capital account (as increased by his or her share of partnership minimum gain). (see section 4.03 of the limited partnership agreement).
Liquidating Distributions: Liquidating distributions will be made in the same manner as regular distributions; however, in the event of dissolution of the Partnership, distributions will be made only after due provision has been made for, among other things, payment of all Partnership debts and liabilities. (see section 9.03 of the limited partnership agreement).
Voting Rights
Investor Partners owning 10% or more of the then outstanding units entitled to vote have the right to require the Managing General Partner to call a meeting of the partners (see section 7.07 of the limited partnership agreement).
Investor Partners may vote with respect to Partnership matters. A majority in interest of the then outstanding units entitled to vote constitutes a quorum. Each unit is entitled to one vote on all matters; each fractional unit is entitled to that fraction of one vote equal to the fractional interest in the unit. Except as otherwise provided in the limited partnership agreement, at any meeting of Investor Partners, approval of any matters considered at the meeting requires the affirmative vote of a majority of units represented, in person or by proxy, at the meeting at which a quorum is present. Approval of any of the following matters requires the affirmative vote of a majority of the then outstanding units entitled to vote, without the concurrence of the Managing General Partner:
| · | The sale of all or substantially all of the assets of the Partnership; |
| · | Removal of the Managing General Partner and election of a new managing general partner; |
| · | Dissolution of the Partnership; |
| · | Any non-ministerial amendment to the limited partnership agreement; |
| · | Cancellation of contracts for services with the Managing General Partner or affiliates; and |
| · | The appointment of a liquidating trustee in the event the Partnership is to be dissolved by reason of the retirement, dissolution, liquidation, bankruptcy, death, or adjudication of insanity or incapacity of the last remaining general partner. |
Additionally, the Partnership is not permitted to participate in a roll-up transaction unless the roll-up has been approved by at least 66 2/3% in interest of Investor Partners (see sections 5.07(m) and 7.08 of the limited partnership agreement).
The Managing General Partner if it were removed by the Investor Partners may elect to retain its interest in the Partnership as a limited partner in the successor limited partnership (assuming that the Investor Partners determined to continue the Partnership and elected a successor managing general partner), in which case the former Managing General Partner would be entitled to vote its interest as a limited partner (see section 7.06 of the limited partnership agreement).
Investor Partners may review the Partnership's books and records and list of Investor Partners at any reasonable time and may copy the list of Investor Partners at their expense. Investor Partners may submit proposals to the Managing General Partner for inclusion in the voting materials for the next meeting of Investor Partners for consideration by the Investor Partners. With respect to the merger or consolidation of the Partnership or the sale of all or substantially all of the Partnership's assets, Investor Partners may exercise dissenter's rights for fair appraisal of their units in accordance with Section 31D-13-1302 of the West Virginia Business Corporation Act (see sections 7.07, 7.08, and 8.01 of the limited partnership agreement).
Retirement and Removal of the Managing General Partner
If the Managing General Partner desires to withdraw from the Partnership for whatever reason, it may do so only upon one hundred twenty (120) days prior written notice and with the written consent of the Investor Partners owning a majority of the then outstanding units (see section 6.03 of the limited partnership agreement).
If the Investor Partners desire to remove the Managing General Partner, they may do so at any time with the consent of the Investor Partners owning a majority of the then outstanding units, and upon the selection of a successor managing general partner by the Investor Partners owning a majority of the then outstanding units (see section 7.06 of the limited partnership agreement).
Term and Dissolution
The Partnership will continue for a maximum period ending December 31, 2056 unless earlier dissolved upon the occurrence of any of the following:
| · | the written consent of the Investor Partners owning a majority of the then outstanding units; |
| · | the retirement, bankruptcy, adjudication of insanity or incapacity, withdrawal, removal, or death (or, in the case of a corporate managing general partner, the retirement, withdrawal, removal, dissolution, liquidation, or bankruptcy) of a managing general partner, unless a successor managing general partner is selected by the partners under the limited partnership agreement or the remaining managing general partner, if any, continues the Partnership's business; |
| · | the sale, forfeiture, or abandonment of all or substantially all of the Partnership's property; or |
| · | the occurrence of any event causing dissolution of the Partnership under the laws of the State of West Virginia (see section 9.01 of the limited partnership agreement). |
Reports to Partners
The Managing General Partner will furnish to the Investor Partners of the Partnership semi-annual and annual reports which will contain financial statements (including a balance sheet and statements of income, partners' equity and cash flows), which statements at fiscal year end will be audited by an independent accounting firm. Financial statements furnished in the Partnership's semi-annual reports will not be audited. Semi-annually, all Investor Partners will also receive a summary itemization of the transactions between the Managing General Partner or any affiliate and the Partnership showing all items of compensation received by the Managing General Partner and its affiliates. Annually beginning with the fiscal year ended December 31, 2006, oil and gas reserve estimates prepared by an independent petroleum engineer will also be furnished to the Investor Partners. Annual reports will be provided to the Investor Partners within 120 days after the close of the Partnership fiscal year, and semi-annual reports will be provided within 75 days after the close of the first six months of the Partnership fiscal year. In addition, the Investor Partners will receive on a monthly basis while the Partnership is participating in drilling and completion activities, reports containing a description of the Partnership's acquisition of interests in prospects, including farmins and farmouts, and the drilling, completion and abandonment of wells thereon. All Investor Partners will receive a report containing information necessary for the preparation of their federal income tax returns and any required state income tax returns by March 15 of each calendar year. Investor Partners will also receive in the monthly reports a summary of the status of wells drilled by the Partnership, the amount of oil or gas from each well and the drilling schedule for proposed wells, if known. The Managing General Partner may provide other reports and financial statements as it deems necessary or desirable (see section 8.02 of the limited partnership agreement).
Power of Attorney
Each partner has granted to the Managing General Partner a power of attorney to execute documents deemed by the Managing General Partner to be necessary or convenient to the partnership's business or required in connection with the qualification and continuance of the partnership (see section 10.01 of the limited partnership agreement).
| Indemnification of Directors and Officers. |
The Managing General Partner is entitled to reimbursement and indemnification for all expenditures made (including amounts paid in settlement of claims) or losses or judgments suffered by it in the ordinary and proper course of the Partnership's business, provided that the Managing General Partner has determined in good faith that the course of conduct which caused the loss or liability was in the best interests of the Partnership, that the Managing General Partner was acting on behalf of or performing services for the Partnership, and that the expenditures, losses or judgments were not the result of the negligence or misconduct on the part of the Managing General Partner (see section 6.04 of the limited partnership agreement). The Managing General Partner has no liability to the Partnership or to any partner for any loss suffered by the Partnership which arises out of any action or inaction of the Managing General Partner if the Managing General Partner, in good faith, determined that the course of conduct was in the best interest of the Partnership and the course of conduct did not constitute negligence or misconduct of the Managing General Partner. The Managing General Partner will be indemnified by the Partnership to the limit of the insurance proceeds and tangible net assets of the Partnership against any losses, judgments, liabilities, expenses and amounts paid in settlement of any claims sustained by it in connection with the Partnership, provided that the same were not the result of negligence or misconduct on the part of the Managing General Partner.
Notwithstanding the above, the Managing General Partner will not be indemnified for liabilities arising under federal and state securities laws unless
| · | there has been a successful adjudication on the merits of each count involving securities law violations; or |
| · | the claims have been dismissed with prejudice on their merits by a court of competent jurisdiction; or |
| · | a court of competent jurisdiction approves a settlement of the claims against a particular indemnitee and finds that indemnification of the settlement and the related costs should be made, and the court considering the request for indemnification has been advised of the position of the Securities and Exchange Commission and of the position of any state securities regulatory authority in which securities of the Partnership were offered or sold as to indemnification for violations of securities laws; |
| · | provided, however, the court need only be advised of the positions of the securities regulatory authorities of those states (a) which are specifically set forth in the Partnership's offering memorandum and (b) in which plaintiffs claim they were offered or sold Partnership units. |
In any claim for indemnification for federal or state securities laws violations, the party seeking indemnification must place before the court the position of the Securities and Exchange Commission, the Massachusetts Securities Division, and the Tennessee Securities Division or other respective state securities division with respect to the issue of indemnification for securities laws violations.
The Partnership will not incur the cost of the portion of any insurance which insures any party against any liability as to which the party is prohibited from being indemnified (see section 6.04 of the limited partnership agreement).
| Financial Statements and Supplementary Data. |
See Financial Statements starting on page F-1 attached.
| Changes in and Disagreements with Accountants on Accounting and Financial Disclosures. |
Not applicable.
| Financial Statements and Exhibits. |
| (a) | The index to Financial Statements is located on page F-2. |
| (b) | Exhibits. The following documents are filed as exhibits to this registration statement. |
| Exhibit Ref. No. | Description |
| | Limited Partnership Agreement |
| | Certificate of limited partnership which reflects the organization of the Partnership under West Virginia law |
| | Form of assignment of leases to the Partnership |
| | Drilling and operating agreement between PDC as managing general partner and the Partnership |
| | Consent of independent engineer |
Pursuant to the requirements of Section 12 of the Securities Exchange Act of 1934, the registrant has duly caused this registration statement to be signed on its behalf by the undersigned, thereunto duly authorized.
| | ROCKIES REGION 2006 LIMITED PARTNERSHIP |
| | (Registrant) |
| | | |
| | By: | Petroleum Development Corporation |
| | | Managing General Partner |
| | | |
| Date: December 21, 2007 | By: | /s/ Steven R. Williams |
| | Title: | Steven R. Williams, Chairman, Chief Executive Officer |
| | | |
| Date: December 21, 2007 | By: | /s/ Richard W. McCullough |
| | Title: | Richard W. McCullough, Chief Financial Officer |
ROCKIES REGION 2006 LIMITED PARTNERSHIP (A West Virginia Limited Partnership)
Financial Statements
For the Nine Months Ended September 30, 2007
and
Period from September 7, 2006 (Date of Inception) to December 31, 2006 (Restated)
(With Independent Registered Public Accounting Firm’s Report Thereon)
Index to Financial Statements
ROCKIES REGION 2006 LIMITED PARTNERSHIP
(A West Virginia Limited Partnership)
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Partners
Rockies Region 2006 Limited Partnership:
We have audited the accompanying balance sheets of Rockies Region 2006 Limited Partnership as of September 30, 2007 and December 31, 2006 and the related statements of operations, partners’ equity and cash flows for the nine months ended September 30, 2007 and the period from September 7, 2006 (date of inception) to December 31, 2006. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Partnership is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits 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 Rockies Region 2006 Limited Partnership as of September 30, 2007 and December 31, 2006, and the results of its operations and its cash flows for the nine months ended September 30, 2007 and the period from September 7, 2006 (date of inception) to December 31, 2006, in conformity with accounting principles generally accepted in the United States of America.
As discussed in Note 13, the financial statements as of December 31, 2006 and for the period then ended have been restated.
Pittsburgh, Pennsylvania
December 21, 2007
ROCKIES REGION 2006 LIMITED PARTNERSHIP
(A West Virginia Limited Partnership)
| |
| September 30, 2007 and December 31, 2006 (restated) | |
| | | | | | | |
| | | | | | | |
| | | September 30, | | | December 31, | |
| Assets | | 2007 | | | 2006 | |
| | | | | | (restated) | |
| | | | | | | |
| Current assets: | | | | | | |
| Cash and cash equivalents | | $ | 1,181,345 | | | $ | 1,154,594 | |
| Accounts receivable oil and gas sales | | | 9,420,049 | | | | 1,228,684 | |
| Due from Managing General Partner - derivatives, short-term | | | 540,465 | | | | 1,549 | |
| Total current assets | | | 11,141,859 | | | | 2,384,827 | |
| | | | | | | | | |
| Oil and gas properties, successful efforts method | | | 100,860,819 | | | | 21,835,420 | |
| Wells in progress | | | - | | | | 89,428,539 | |
| | | | 100,860,819 | | | | 111,263,959 | |
| Less accumulated depreciation, depletion and amortization | | | (12,059,847 | ) | | | (623,946 | ) |
| | | | 88,800,972 | | | | 110,640,013 | |
| | | | | | | | | |
| Noncurrent assets: | | | | | | | | |
| Finance charges | | | 4,715 | | | | 238 | |
| Due from Managing General Partner - derivatives, long-term | | | 47,582 | | | | 1,472 | |
| Total noncurrent assets | | | 52,297 | | | | 1,710 | |
| | | | | | | | | |
| Total Assets | | $ | 99,995,128 | | | $ | 113,026,550 | |
| | | | | | | | | |
| | | | | | | | | |
| Liabilities and Partners' Equity | | | | | | | | |
| | | | | | | | | |
| Current liabilities: | | | | | | | | |
| Accounts payable and accrued expenses | | $ | 857,087 | | | $ | 113,473 | |
| Due to Managing General Partner - other | | | 1,482,557 | | | | 244,544 | |
| Total current liabilities | | | 2,339,644 | | | | 358,017 | |
| | | | | | | | | |
| Asset retirement obligation | | | 766,423 | | | | 356,242 | |
| | | | | | | | | |
| Partners' equity | | | 96,889,061 | | | | 112,312,291 | |
| | | | | | | | | |
| Total Liabilities and Partners' Equity | | $ | 99,995,128 | | | $ | 113,026,550 | |
See accompanying notes to financial statements.
ROCKIES REGION 2006 LIMITED PARTNERSHIP
(A West Virginia Limited Partnership)
| |
| | | | | | | |
| For the Nine Months Ended September 30, 2007 and | |
| Period from September 7, 2006 (date of inception) to December 31, 2006 (restated) | |
| | | | | | | |
| | | | | | Period From | |
| | | | | | September 7, 2006 | |
| | | Nine Months Ended | | | (date of inception) to | |
| | | September 30, | | | December 31, | |
| | | 2007 | | | 2006 | |
| | | | | | (restated) | |
| | | | | | | |
| Revenues: | | | | | | |
| Oil and gas sales | | $ | 23,580,164 | | | $ | 1,228,684 | |
| Oil and gas price risk management gain (loss), net | | | 543,740 | | | | (408 | ) |
| Total revenue | | | 24,123,904 | | | | 1,228,276 | |
| | | | | | | | | |
| Costs and expenses: | | | | | | | | |
| Production and operating costs | | | 4,084,097 | | | | 189,069 | |
| Direct costs | | | 170,930 | | | | 176,613 | |
| Depreciation, depletion and amortization | | | 11,653,405 | | | | 1,003,120 | |
| Accretion of asset retirement obligations | | | 27,623 | | | | 3,148 | |
| Loss on impairment of oil and gas properties | | | 2,445,617 | | | | 7,129,683 | |
| Exploratory dry hole costs | | | 8,122,577 | | | | - | |
| Management fee | | | - | | | | 1,349,108 | |
| Total costs and expenses | | | 26,504,249 | | | | 9,850,741 | |
| | | | | | | | | |
| Loss from operations | | | (2,380,345 | ) | | | (8,622,465 | ) |
| | | | | | | | | |
| Interest expense | | | 5,185 | | | | 15 | |
| Interest income | | | (94,364 | ) | | | (1,165,941 | ) |
| | | | | | | | | |
| Net loss | | $ | (2,291,166 | ) | | $ | (7,456,539 | ) |
| | | | | | | | | |
| Net loss per Investor Partner unit | | $ | (321 | ) | | $ | (1,156 | ) |
| | | | | | | | | |
| Investor Partnerships units outstanding | | | 4,497 | | | | 4,497 | |
See accompanying notes to financial statements.
ROCKIES REGION 2006 LIMITED PARTNERSHIP
(A West Virginia Limited Partnership)
| |
| | | | | | | | | | |
| For the Nine Months Ended September 30, 2007 and | |
| Period from September 7, 2006 (date of inception) to December 31, 2006 (restated) | |
| | | | | | | | | | |
| | | | | | Managing | | | | |
| | | Investor | | | General | | | | |
| | | Partners | | | Partner | | | Total | |
| | | | | | | | | | |
| | | | | | | | | | |
| Partners' initial contributions | | $ | 89,940,527 | | | $ | 38,912,342 | | | $ | 128,852,869 | |
| | | | | | | | | | | | | |
| Syndication costs | | | (9,084,039 | ) | | | - | | | | (9,084,039 | ) |
| | | | | | | | | | | | | |
| Net loss (restated) | | | (5,196,790 | ) | | | (2,259,749 | ) | | | (7,456,539 | ) |
| | | | | | | | | | | | | |
| Balance, December 31, 2006 (restated) | | | 75,659,698 | | | | 36,652,593 | | | | 112,312,291 | |
| | | | | | | | | | | | | |
| Distributions to Partners | | | (8,273,200 | ) | | | (4,858,864 | ) | | | (13,132,064 | ) |
| | | | | | | | | | | | | |
| Net loss | | | (1,443,435 | ) | | | (847,731 | ) | | | (2,291,166 | ) |
| | | | | | | | | | | | | |
| Balance, September 30, 2007 | | $ | 65,943,063 | | | $ | 30,945,998 | | | $ | 96,889,061 | |
See accompanying notes to financial statements.
ROCKIES REGION 2006 LIMITED PARTNERSHIP
(A West Virginia Limited Partnership)
| |
| For the Nine Months Ended September 30, 2007 and | |
| Period from September 7, 2006 (date of inception) to December 31, 2006 (restated) | |
| | |
| | | September 30 | | | December 31 | |
| | | 2007 | | | 2006 | |
| Cash flows from operating activities: | | | | | (restated) | |
| | | | | | | |
| Net loss | | $ | (2,291,166 | ) | | $ | (7,456,539 | ) |
| Adjustments to reconcile net loss to net cash provided by (used in) operating activities: | | | | | | | | |
| Loss on impairment of oil and gas properties | | | 2,445,617 | | | | 7,129,683 | |
| Depreciation, depletion and amortization | | | 11,653,405 | | | | 1,003,120 | |
| Accretion of asset retirement obligation | | | 27,623 | | | | 3,148 | |
| Exploratory dry hole costs | | | 8,122,577 | | | | - | |
| Unrealized (gain)/loss on derivative transactions | | | (493,085 | ) | | | 408 | |
| Changes in operating assets and liabilities: | | | | | | | | |
| Increase in Due from Managing General Partner - derivatives | | | (91,941 | ) | | | (3,429 | ) |
| Increase in accounts receivable - oil and gas sales | | | (8,191,365 | ) | | | (1,228,684 | ) |
| Increase in financing charges | | | (4,477 | ) | | | (238 | ) |
| Increase in accounts payable and accrued expenses | | | 743,614 | | | | 113,473 | |
| Increase in due to Managing General Partner - other | | | 1,238,013 | | | | 244,544 | |
| Net cash provided by (used in) operating activities | | | 13,158,815 | | | | (194,514 | ) |
| | | | | | | | | |
| Cash flows from investing activities: | | | | | | | | |
| Expenditures for oil and gas properties | | | - | | | | (118,419,722 | ) |
| Net cash used in investing activities | | | - | | | | (118,419,722 | ) |
| | | | | | | | | |
| Cash flows from financing activities: | | | | | | | | |
| Investor Partners' contributions | | | - | | | | 89,940,527 | |
| Managing General Partner contribution | | | - | | | | 38,912,342 | |
| Syndication costs paid | | | - | | | | (9,084,039 | ) |
| Distributions to partners | | | (13,132,064 | ) | | | - | |
| Net cash (used in) provided by financing activities | | | (13,132,064 | ) | | | 119,768,830 | |
| | | | | | | | | |
| Net increase in cash and cash equivalents | | | 26,751 | | | | 1,154,594 | |
| Cash and cash equivalents at beginning of period | | | 1,154,594 | | | | - | |
| Cash and cash equivalents at end of period | | $ | 1,181,345 | | | $ | 1,154,594 | |
| | | | | | | | | |
| Supplemental disclosure of non-cash activity: | | | | | | | | |
| | | | | | | | | |
| Asset retirement obligation, with a corresponding increase to oil and gas properties | | $ | 382,558 | | | $ | 353,094 | |
See accompanying notes to financial statements.
ROCKIES REGION 2006 LIMITED PARTNERSHIP (A West Virginia Limited Partnership)
Notes to Financial Statements
The Rockies Region 2006 Limited Partnership (the “Partnership”) was organized as a limited partnership on September 7, 2006, in accordance with the laws of the State of West Virginia for the purpose of engaging in the exploration and development of oil and gas properties and commenced business operations as of the date of organization.
Purchasers of partnership units subscribed to and fully paid for 47.25 units of limited partner interests and 4449.77635 units of additional general partner interests at $20,000 per unit. Petroleum Development Corporation has been designated the Managing General Partner of the Partnership and has a 37% ownership in the Partnership. Generally, throughout the term of the Partnership, revenues, costs, and cash distributions are allocated 63% to the limited and additional general partners (collectively, the “Investor Partners”) are shared pro rata based upon the amount of their investment in the Partnership and 37% to the Managing General Partner.
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.
| (2) | Summary of Significant Accounting Policies |
Partnership Financial Statement Presentation Basis
The financial statements include only those assets, liabilities and results of operations of the partners which relate to the business of the Partnership. The statements do not include any assets, liabilities, revenues or expenses attributable to any of the partners' other activities.
Cash and Cash Equivalents
For purposes of the statement of cash flows, 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. The balance in the Partnership’s account is insured by Federal Deposit Insurance Corporation (FDIC) up to $100,000. At times, the Partnership’s account balance may exceed FDIC limits. The Partnership has not experienced losses in any such accounts and limits its exposure to credit loss by placing its cash and cash equivalents with high-quality financial institutions.
Allowance for Doubtful Accounts
As of September 30, 2007 and December 31, 2006, the Partnership did not record an allowance for doubtful accounts. The Partnership sells substantially all of its oil and natural gas to customers who purchase oil and natural gas from other Partnerships managed by the Partnership’s Managing General Partner. Historically, none 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. If an account is deemed to be uncollectible by the Managing General Partner, the remaining balance is charged to the allowance account. The Partnership did not incur any losses on accounts receivable for the nine months ended September 30, 2007 or the period from September 7, 2006 (date of inception) to December 31, 2006.
ROCKIES REGION 2006 LIMITED PARTNERSHIP
(A West Virginia Limited Partnership)
Notes to Financial Statements
Oil and Gas Properties
The Partnership accounts for its oil and gas properties under the successful efforts method of accounting. Costs of proved developed producing properties, successful exploratory wells and development dry hole costs are depreciated or depleted by the unit-of-production method based on estimated proved developed producing oil and gas reserves. Property acquisition costs are depreciated or depleted on the unit-of-production method based on estimated proved oil and gas reserves. The Partnership obtains new reserve reports from independent petroleum engineers annually as of December 31 of each year. The Partnership adjusts for any major acquisitions, new drilling and divestures during the year as needed. See “Note 8 – Supplemental Reserve Information (Unaudited)” to the financial statements for additional information regarding the Partnership’s reserve reporting. The Partnership does not maintain an inventory of undrilled leases.
Exploratory well drilling costs are initially capitalized but charged to expense if the well is determined to be nonproductive. The status of each in-progress well is reviewed quarterly to determine the proper accounting treatment under the successful efforts method of accounting. Cumulative costs on in-progress wells “Suspended Well Costs” remain capitalized until their productive status becomes known. If an in-progress exploratory well is found to be unsuccessful (referred to as a dry hole) prior to the issuance of financial statements, the costs are expensed to exploratory dry hole costs. If a final determination about the productive status of a well is unable to be made prior to issuance of the financial statements, the well is classified as “Suspended Well Costs” until there is sufficient time to conduct additional completion or testing operations to evaluate the pertinent geological and engineering data obtained. When a final determination of a well’s productive status is made, the well is removed from the suspended well status and the proper accounting treatment is recorded. The determination of an exploratory well's ability to produce is made within one year from the completion of drilling activities.
Upon sale or retirement of significant portions of or complete fields of depreciable or depletable property, the book value thereof, less proceeds, is credited or charged to income. Upon sale of a partial unit of property, the proceeds are credited to property costs.
The Partnership assesses impairment of capitalized costs of proved oil and gas properties by comparing net capitalized costs to estimated undiscounted future net cash flows on a field-by-field basis using estimated production based upon prices at which management reasonably estimates such products will be sold. These estimates of future product prices may differ from current market prices of oil and gas. Any downward revisions to the Partnership’s estimates of future production or product prices could result in an impairment of the Partnership's oil and gas properties in subsequent periods. If net capitalized costs exceed undiscounted future net cash flows, the measurement of impairment is based on estimated fair value which would consider future discounted cash flows.
Sales of natural gas are recognized when natural gas has been delivered to a custody transfer point, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser upon delivery, collection of revenue from the sale is reasonably assured, and the sales price is fixed or determinable. Natural gas is sold by the Managing General Partner under contracts with terms ranging from one month up to the life of the well. Virtually all of the Managing General Partner’s contracts pricing provisions are tied to a market index with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality of natural gas and prevailing supply and demand conditions, so that the price of the natural gas fluctuates to remain competitive with other available natural gas supplies. As a result, the Partnership’s revenues from the sale of natural gas will suffer if market prices decline and benefit if they increase. However, the Managing General Partner may from time to time enter into derivative agreements, usually with a term of two years or less which may either fix or collar a price in order to reduce market price fluctuations. The Partnership believes that the pricing provisions of its natural gas contracts are customary in the industry.
ROCKIES REGION 2006 LIMITED PARTNERSHIP
(A West Virginia Limited Partnership)
Notes to Financial Statements
The Managing General Partner currently uses the “Net-Back” method of accounting for transportation arrangements of natural gas sales. The Managing General Partner sells gas at the wellhead, collects a price, and recognizes revenues based on the wellhead sales price since transportation costs downstream of the wellhead are incurred by the Managing General Partner’s customers and reflected in the wellhead price.
Sales of oil are recognized when persuasive evidence of a sales arrangement exists, the oil is verified as produced and is delivered from storage tanks at well locations to a purchaser, collection of revenue from the sale is reasonably assured and the sales price is determinable. The Partnership is currently able to sell all the oil that it can produce under existing sales contracts with petroleum refiners and marketers. The Partnership does not refine any of its oil production. The Partnership’s crude oil production is sold to purchasers at or near the Partnership’s wells under short-term purchase contracts at prices and in accordance with arrangements that are customary in the oil industry.
The Partnership sold natural gas and oil to two customers, Teppco Crude Oil, L.P. and Williams Production RMT, which accounted for 75% and 18%, respectively, of the Partnership’s total natural gas and oil sales for the period ended December 31, 2006. These same two customers accounted for 47% and 34%, respectively, of the Partnership’s total natural gas and oil sales for the nine months ending September 30, 2007.
Asset Retirement Obligations
The Partnership applies the provisions of SFAS 143, “Accounting for Asset Retirement Obligations” and 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, which is at the time the well is completely drilled. Upon initial recognition of an asset retirement obligation, the Partnership increases the carrying amount of the long-lived asset by the same amount as the liability. Over time, the asset retirement obligations are accreted, over the estimate life of the related asset, for the change in their present value. The initial capitalized costs are depleted over the useful lives of the related assets, through charges to depreciation, depletion and amortization.
Derivative Financial Instruments
The Partnership accounts for derivative financial instruments in accordance with FAS Statement No. 133 "Accounting for Derivative Instruments and Certain Hedging Activities" as amended. Accordingly, the derivative instruments are recorded as an asset or liability on the balance sheet at fair value and the change in the fair value is recorded in oil and gas price risk management gain (loss), net. Because derivative arrangements are entered into by the Managing General Partner on behalf of the Partnership, they are reported on the balance sheet as a net short-term or long-term receivable due from or payable due to the Managing General Partner. The Partnership did not recognize any realized gains or losses on derivative contracts as of December 31, 2006, thus no amounts are due to/from the Managing General Partner on closed derivative positions at December 31, 2006. The Partnership realized a gain of $46,083 on derivative contracts as of September 30, 2007. This amount is included in the balance due to the Managing General Partner.
The measurement of fair value is based on actively quoted market prices, if available. Otherwise, the Managing General Partner seeks indicative price information from external sources including broker quotes and industry publications. If pricing information from external sources is not available, measurement involves judgment and estimates. These estimates are based on valuation methodologies considered appropriate by the Managing General Partner.
ROCKIES REGION 2006 LIMITED PARTNERSHIP
(A West Virginia Limited Partnership)
Notes to Financial Statements
By using derivative financial instruments to manage exposures to changes in commodity prices, the Partnership exposes itself to credit risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty owes the Managing General Partner, which in turn owes the Partnership thus creating repayment risk. The Managing General Partner minimizes the credit or repayment risk in derivative instruments by entering into transactions with high-quality counterparties.
Income Taxes
Since the taxable income or loss of the Partnership is reported in the separate tax returns of the partners, no provision has been made for income taxes by the Partnership.
The Partnership has made a number of estimates and assumptions relating to the reporting of assets and liabilities and revenues and expenses and the disclosure of contingent assets and liabilities to prepare these financial statements in conformity with accounting principles generally accepted in the United States of America. Actual results could differ from those estimates. Estimates which are particularly significant to the financial statements include estimates of oil and gas reserves, future cash flows from oil and gas properties which are used in assessing impairment of long-lived assets, asset retirement obligations, and valuation of derivative instruments.
Recently Issued Accounting Standards
In September 2006, the FASB issued SFAS No. 157, "Fair Value Measurements,” which replaces several existing pronouncements, defines fair value, establishes a framework for measuring fair value, and expands disclosures about fair value measurements. SFAS No. 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. Consequently, we will adopt the provisions of SFAS 157 for our fiscal year beginning January 1, 2008. The Partnership is currently evaluating the impact of the provisions of SFAS No. 157 on its financial statements.
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 is currently evaluating the impact of the provisions of SFAS No. 159 on its financial statements.
ROCKIES REGION 2006 LIMITED PARTNERSHIP
(A West Virginia Limited Partnership)
Notes to Financial Statements
Recently Implemented Accounting Standards
In June 2006, the Financial Accounting Standards Board ("FASB") issued Emerging Issues Task Force ("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 ("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, did not have a significant impact on the accompanying financial statements. The Partnerships’ 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.
In June 2006, the FASB issued Interpretation No. 48, “Accounting for Uncertainty in Income Taxes: an Interpretation of FASB Statement No. 109” (FIN 48), which clarifies the accounting for uncertainty in income taxes recognized in an entity’s financial statements in accordance with FASB Statement No. 109, “Accounting for Income Taxes.” FIN 48 prescribes a recognition threshold and measurement principles for financial statement disclosure of tax positions taken or expected to be taken on a tax return. FIN 48 is effective for fiscal years beginning after December 15, 2006. The provisions FIN 48 did not have a material impact on the Partnerships’ financial statements.
In September 2006, the Staff of the Securities and Exchange Commission issued Staff Accounting Bulletin (SAB) No. 108, “Financial Statements – Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements”. SAB 108 provides guidance on how prior year misstatements should be taken into consideration when quantifying misstatements in current year financial statements for purposes of determining whether current year’s financial statements are materially misstated. SAB 108 requires registrants to quantify misstatements using both an income statement (“rollover”) and balance sheet (“iron curtain”) approach and evaluate whether either approach results in a misstatement that, when all relevant quantitative and qualitative factors are considered, is material. If prior year errors that had been previously considered immaterial now are considered material based on either approach, no restatement is required so long as management properly applied its previous approach and all relevant facts and circumstances were considered. If prior years are not restated, the cumulative effect adjustment is recorded in opening accumulated earnings as of the beginning of the fiscal year of adoption. SAB 108 is effective for fiscal years ending on or after November 15, 2006. The provisions of SAB 108 did not have a material impact on the Partnership’s financial statements.
| (3) | Transactions with Managing General Partner and Affiliates |
The Managing General Partner and its wholly-owned subsidiary, PDC Securities Incorporated, are reimbursed for certain Partnership operating expenses and receive fees for services as provided for in the Agreement. As of September 30, 2007, and December 31, 2006, the Partnership owed the Managing General Partner $1,482,557 and $244,544, respectively. As a result of derivative transactions executed by the Managing General Partner on behalf of the Partnership, there were also short term derivative receivables of $540,465 and $1,549 and long-term derivative receivables of $47,582 and $1,472 at September, 2007 and December 31, 2006.
The following table presents reimbursements and service fees paid by the Partnership to PDC or its affiliates for the period from September 7, 2006 (date of inception) to December 31, 2006 and for the nine months ended September 30, 2007:
ROCKIES REGION 2006 LIMITED PARTNERSHIP
(A West Virginia Limited Partnership)
Notes to Financial Statements
| | | | | | Period from | |
| | | | | | September 7, 2006 | |
| | | Nine Months Ended | | | (date of inception) to | |
| | | September 30, 2007 | | | December 31, 2006 | |
| | | | | | (restated) | |
| | | | | | | |
| Payment of drilling and completion costs | | $ | - | | | $ | 118,419,722 | |
| Syndication costs* | | | - | | | | 1,816,808 | |
| Management fee | | | - | | | | 1,349,108 | |
| Well operations fees | | | 333,726 | | | | 28,102 | |
| | *Consists of organization and offering costs, including costs of organizing and selling the offering (including total underwriting and brokerage discounts and commissions), expenses for printing, mailing, salaries of employees while engaged in sales activity, charges of transfer agents, registrars, trustees, escrow holders, depositories, engineers and other experts, expenses of qualification of the sale of the securities under federal and state law, including accountants’ and attorneys’ fees and other front end fees. |
In addition, as the operator of the Partnership’s wells, the Managing General Partner receives all proceeds from the sale of oil and gas produced and pays for all costs incurred related to services, equipment and supplies from vendors for all well production and operating costs and other direct costs for the Partnership. Net revenue from oil and gas operations is distributed monthly to all partners based on their share of costs and revenues.
As described above, the Managing General Partner utilizes commodity-based derivative instruments, entered into on behalf of the Partnership, to manage a portion of the Partnership’s exposure to price risk from oil and natural gas sales. These instruments consist of CIG (Colorado Interstate Gas) index-based contracts traded by JP Morgan for Colorado natural gas production. These derivative instruments have the effect of locking in for specified periods (at predetermined prices or ranges of prices) the prices the Managing General Partner receives for the volume of oil and natural gas to which the derivative relates.
The fair value of the Partnership’s share of commodity based derivatives was $588,047 at September 30, 2007. The Partnership recognized in the statement of income realized and unrealized gains on commodity based derivatives of $543,740 for the nine months ended September 30, 2007. The following table summarizes the Partnership’s share of open derivative positions as of September 30, 2007.
ROCKIES REGION 2006 LIMITED PARTNERSHIP
(A West Virginia Limited Partnership)
Notes to Financial Statements
| Open Derivative Contracts | |
| Commodity | Type | | Quantity Gas | | | Weighted Average Price | | | Fair Market Value | |
| | | | (a) | | | | | | | |
| Partnership's share of positions as of September 30, 2007 | | | | | | | | | |
| Natural Gas | Floors | | | 1,021,893 | | | $ | 5.38 | | | $ | 695,279 | |
| Natural Gas | Ceilings | | | 841,528 | | | $ | 10.21 | | | $ | (107,232 | ) |
| Due From Managing General Partner - Derivatives, Total | | | | | | | | | | $ | 588,047 | |
| | | | | | | | | | | | | | |
| Partership's share of positions maturing within 12 months following September 30, 2007 | | | | | | | | | |
| Natural Gas | Floors | | | 932,272 | | | $ | 5.37 | | | $ | 623,173 | |
| Natural Gas | Ceilings | | | 752,008 | | | $ | 10.19 | | | $ | (82,708 | ) |
| Due From Managing General Partner - Derivatives, Short-term | | | | | | | | | | $ | 540,465 | |
(a) MMBtu - one million British thermal units. One British thermal unit is the heat required to raise the temperature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit.
At September 30, 2007, the maximum term for the derivative positions listed above is 13 months.
The fair value of the Partnership’s share of commodity based derivatives was $3,021 at December 31, 2006. The Partnership recognized in the statement of income an unrealized loss on commodity based derivatives of $408 for the period from September 7, 2006 (date of inception) to December 31, 2006. The following table summarizes the Partnership’s share of open derivative positions as of December 31, 2006.
| Open Derivative Contracts | |
| Commodity | Type | | Quantity Gas | | | Weighted Average Price | | | Fair Market Value | |
| | | | (a) | | | | | | | |
| Partnership's share of positions as of December 31, 2006: | | | | | | | | | |
| Natural Gas | Cash Settled Option Sales | | | 6,291 | | | $ | 5.25 | | | $ | 3,021 | |
| Due From Managing General Partner - Derivatives, Total | | | | | | | | | | $ | 3,021 | |
| | | | | | | | | | | | | | |
| Partership's share of positions maturing within 12 months following December 31, 2006: | | | | | | | | | |
| Natural Gas | Cash Settled Option Sales | | | 2,517 | | | $ | 5.25 | | | $ | 1,549 | |
| Due From Managing General Partner - Derivatives, Short-term | | | | | | | | | | $ | 1,549 | |
(a) MMBtu - one million British thermal units. One British thermal unit is the heat required to raise the temperature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit.
At December 31, 2006, the maximum term for the derivative positions listed above is 15 months.
ROCKIES REGION 2006 LIMITED PARTNERSHIP
(A West Virginia Limited Partnership)
Notes to Financial Statements
| (4) | Allocation of Partners’ Interests |
The table below summarizes the participation of the Managing General Partner and the Investor Partners in the costs and revenues of the Partnership, taking into account the Managing General Partner's capital contribution, which is equal to a minimum of 43.07% of the Investor Partners’ initial capital.
| | | Investor Partners | | | Managing General Partner | |
| Partnership Costs | | | | | | |
| | | | | | | |
| Organization Costs (a) | | | 0 | % | | | 100 | % |
| Broker-dealer Commissions and Expenses (a) | | | 100 | % | | | 0 | % |
| Management Fee (b) | | | 100 | % | | | 0 | % |
| Undeveloped Lease Costs | | | 0 | % | | | 100 | % |
| Tangible Well Costs | | | 0 | % | | | 100 | % |
| Intangible Drilling Costs (IDC) | | | 100 | % | | | 0 | % |
| Managing General Partner's Drilling Compensation | | | 100 | % | | | 0 | % |
| Direct Drilling and Compensation Costs, excluding Managing General Partner’s Drilling Compensation | | | 63 | % | | | 37 | % |
| Operating Costs (c) | | | 63 | % | | | 37 | % |
| Direct Costs (d) | | | 63 | % | | | 37 | % |
| | | | | | | | | |
| Partnership Revenue (e) | | | | | | | | |
| | | | | | | | | |
| Sale of Oil and Gas Production | | | 63 | % | | | 37 | % |
| Sale of Productive Properties | | | 63 | % | | | 37 | % |
| Sale of Equipment | | | 63 | % | | | 37 | % |
| Sale of Undeveloped Leases | | | 63 | % | | | 37 | % |
| Interest Income | | | 63 | % | | | 37 | % |
| (a) | The Managing General Partner paid all legal, accounting, printing, and filing fees associated with the organization of the Partnership and the offering of units and is allocated 100% of these costs. The Investor Partners paid all dealer manager commissions, discounts, and due diligence reimbursements and is allocated 100% of these costs. However, any organization and offering costs in excess of 10.5% of subscriptions will be charged and allocated to the Managing General Partner. |
| (b) | Represents a one-time fee paid to the Managing General Partner on the day the Partnership is funded equal to 1-1/2% of total investor subscriptions. |
| (c) | Represents operating costs incurred after the completion of productive wells, including monthly per-well charges paid to the Managing General Partner. |
| (d) | The Managing General Partner receives monthly reimbursement from the Partnership for direct costs incurred by the Managing General Partner on behalf of the Partnership. |
ROCKIES REGION 2006 LIMITED PARTNERSHIP
(A West Virginia Limited Partnership)
Notes to Financial Statements
| (e) | The Managing General Partner will contribute and/or pay for the Partnership’s share of all leases, tangible drilling and completion costs, and gathering line costs, totaling not less than 37% of the well costs excluding the Managing General Partner’s drilling compensation. If these costs exceed the required capital contribution, the Managing General Partner will increase its capital contribution. In that event, the Managing General Partner’s share of all items of profit and loss during the production phase of operations and cash available for distribution would be modified to equal the percentage arrived at by dividing the Managing General Partner’s capital contributions by the total well costs, excluding the Managing General Partner’s drilling compensation. The Investor Partners’ allocations of these items would be changed accordingly. The Investor Partners’ portion of capital available for investment will pay the intangible drilling costs, including the Managing General Partner’s drilling compensation of 12.6% of the total cost of the Partnership’s wells for the wells which the Managing General Partner operates. The entire capital contribution of the Investor Partners, after payment of brokerage commissions, due diligence reimbursement, and the management fee, will be utilized to pay for intangible drilling costs. If the capital contributions of the Investor Partners are insufficient to pay the intangible drilling costs, the Managing General Partner will pay the additional amount of these costs, and in these circumstances the sharing arrangements for intangible drilling costs and recapture of intangible drilling costs will be in proportion to the Investor Partners’ and the Managing General Partner’s respective payment of intangible drilling costs. |
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, which occurred in July 2007. The repurchase price is set at a minimum of four times the most recent twelve months’ of cash distributions from production. The Managing General Partner is obligated to purchase, in any calendar year, Investor Partner units aggregating to 10% of the initial subscriptions if requested by the Investor Partners, subject to its financial ability to do so and opinions of counsel. Repurchase requests are fulfilled by the Managing General Partner on a first-come, first-served basis. No partnership units can be repurchased under this provision by the Managing General Partner until thirty-six months after the date of the first distribution to the partners.
(5) Costs Relating to Oil and Gas Activities
The Partnership is engaged solely in oil and gas activities, all of which are located in the continental United States. Drilling operations began upon funding on September 7, 2006 with payments made for all planned drilling and completion costs for the Partnership made in December 2006. Costs capitalized for these activities at September 30, 2007 and December 31, 2006 are as follows:
| | | | | | Period from | |
| | | | | | September 7, 2006 | |
| | | | | | (date of inception) to | |
| | | September 30, 2007 | | | December 31, 2006 | |
| | | | | | (restated) | |
| | | | | | | |
| Leasehold costs | | $ | 811,341 | | | $ | 313,808 | |
| Development costs | | | 100,049,478 | | | | 21,521,612 | |
| Wells in progress | | | - | | | | 89,428,539 | |
| | | $ | 100,860,819 | | | $ | 111,263,959 | |
Wells in progress represents prepayments to the Managing General Partner for the exploration and development of oil and gas properties.
ROCKIES REGION 2006 LIMITED PARTNERSHIP
(A West Virginia Limited Partnership)
Notes to Financial Statements
(6) Exploratory Dry Hole Costs
The Jepson 11-19h exploratory well in the Bakken field in North Dakota was determined to be an economic dry hole in the first quarter of 2007. Although the well does produce oil, the amount of production was deemed to be insignificant and thus the well was determined to be an a dry hole. The Brnak 22-11 exploratory well in Colorado was also determined to be a dry hole. At March 31, 2007, the Partnership expensed $3,395,210 of exploratory dry hole costs related to these two wells.
During the second quarter of 2007, the Anderson 11-24h exploratory well in Nesson field in North Dakota was determined to be a dry hole. The Partnership expensed $3,150,266 of exploratory dry hole costs related to this well in the second quarter of 2007.
During the third quarter of 2007, the Wagner 33-23 and Sirios 22-1 exploratory wells in the Wattenberg field in Colorado were determined to be economic dry holes, as the cost of extending the existing gas pipeline to bring the oil and natural gas produced by these wells to market was determined to be economically unfeasible, given the current market prices and estimated reserves for the two wells. The Partnership expensed $1,577,101 of exploratory dry hole costs related to these wells in the third quarter of 2007.
(7) Asset Retirement Obligations
Changes in carrying amount of asset retirement obligations associated with oil and gas properties as of September 30, 2007 are as follows:
| | | Nine Months Ended September 30, 2007 | | | Period from September 7, 2006 (date of inception) to December 31, 2006 | |
| | | | | | (restated) | |
| | | | | | | |
| Balance at beginning of period | | $ | 356,242 | | | $ | - | |
| Obligations assumed with development activities | | | 382,558 | | | | 353,094 | |
| Accretion expense | | | 27,623 | | | | 3,148 | |
| Balance at end of period | | $ | 766,423 | | | $ | 356,242 | |
The discount rate used in calculating the asset retirement obligation and related accretion vary from 5.10% to 5.55%, depending on the quarter in which the Partnership was required to record the retirement obligation for any specific well. These rates approximate the borrowing rate of the Managing General Partner for the quarter in which the retirement obligation was recorded.
(8) Supplemental Reserve Information (Unaudited)
Proved oil and gas reserves of the Partnership were estimated as of December 31, 2006 by an independent petroleum engineer, Ryder Scott Company, L.P., as provided for under the partnership agreement. A mid-year reserve report as of June 30, 2007 was prepared by the Managing General Partner’s petroleum engineers for the Partnership, as over sixty Partnership wells come on line in the first six months of 2007, resulting in a significant increase in reserves and estimated future cash flows. These reserves have been prepared in compliance with the Securities and Exchange Commission rules based on year end prices. All of the partnership's reserves are proved developed reserves and include reserves related to the recompletions of wells in the Codell formation of 540,500 Bbls of oil and 5,865,500 Mcfs of natural gas and 103,900 Bbls and 1,352,600 Mcfs of natural gas at June 30, 3007 and December 31, 2006, respectively. An analysis of the change in estimated quantities of proved developed oil and gas reserves is shown below:
ROCKIES REGION 2006 LIMITED PARTNERSHIP
(A West Virginia Limited Partnership)
Notes to Financial Statements
| | | Oil (Bbls) | |
| | | June 30, | | | December 31, | |
| | | 2007 | | | 2006 | |
| | | | | | | |
| Proved developed reserves: | | | | | | |
| Beginning of year | | | 960,700 | | | | - | |
| Revisions of previous estimates | | | 313,510 | | | | - | |
| New discoveries and extensions | | | 673,500 | | | | 977,400 | |
| Production | | | (163,810 | ) | | | (16,700 | ) |
| End of Period | | | 1,783,900 | | | | 960,700 | |
| | | Gas (Mcfs) | |
| | | June 30, | | | December 31, | |
| | | 2007 | | | 2006 | |
| Proved developed reserves: | | | | | | |
| Beginning of year | | | 9,013,800 | | | | - | |
| Revisions of previous estimates | | | 10,431,184 | | | | - | |
| New discoveries and extensions | | | 10,369,700 | | | | 9,066,500 | |
| Production | | | (1,122,284 | ) | | | (52,700 | ) |
| End of Period | | | 28,692,400 | | | | 9,013,800 | |
| (9) | Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Oil and Gas Reserves (Unaudited) |
Summarized in the following table is information for the Partnership with respect to the standardized measure of discounted future net cash flows relating to proved oil and gas reserves. Future cash inflows are computed by applying year-end prices of oil and gas relating to the Partnership proved reserves to the year-end quantities of those reserves. Future production, development, site restoration and abandonment costs are derived based on current costs assuming continuation of existing economic conditions. Future development costs include the development costs related to recompletions of wells drilled in the Codell formation, as described in “Item 1, Business, Drilling Activities.”
| | | June 30, | | | December 31, | |
| | | 2007 | | | 2006 | |
| | | | | | | |
| Future estimated revenues | | $ | 218,356,900 | | | $ | 96,697,800 | |
| Future estimated production costs | | | (60,730,900 | ) | | | (29,902,600 | ) |
| Future estimated development costs | | | (12,069,000 | ) | | | (15,990,200 | ) |
| Future net cash flows | | | 145,557,000 | | | | 50,805,000 | |
| 10% annual discount for estimated timing of cash flows | | | (66,017,000 | ) | | | (19,220,000 | ) |
Standardized measure of discounted future estimated net cash flows | | $ | 79,540,000 | | | $ | 31,585,000 | |
ROCKIES REGION 2006 LIMITED PARTNERSHIP
(A West Virginia Limited Partnership)
Notes to Financial Statements
The following table summarizes the principal sources of change in the standardized measure of discounted future estimated net cash flows for the six months ended June 30, 2007and the period from September 7, 2006(date of inception) to December 31, 2006:
| | | June 30, | | | December 31, | |
| | | 2007 | | | 2006 | |
| | | | | | | |
| Sales of oil and gas production, net of production costs | | $ | (11,824,900 | ) | | $ | (1,039,600 | ) |
| Net changes in prices and production costs | | | 28,010,000 | | | | - | |
| Extensions, discoveries, and improved recovery, less related cost | | | 30,229,000 | | | | 32,625,700 | |
| Development cost incurred during the period | | | - | | | | - | |
| Revisions of previous quantity estimates | | | - | | | | - | |
| Accretion of discount | | | 2,887,000 | | | | - | |
| Timing and other | | | (1,346,100 | ) | | | (1,100 | ) |
| Net change | | $ | 47,955,000 | | | $ | 31,585,000 | |
The data presented should not be viewed as representing the expected cash flow from, or current value of, existing proved reserves since the computations are based on a large number of estimates and arbitrary assumptions. Reserve quantities cannot be measured with precision and their estimation requires many judgmental determinations and frequent revisions. The required projection of production and related expenditures over time requires further estimates with respect to pipeline availability, rates of demand and governmental control. Actual future prices and costs are likely to be substantially different from the current prices and costs utilized in the computation of reported amounts. Any analysis or evaluation of the reported amounts should give specific recognition to the computational methods utilized and the limitations inherent therein.
| (10) | Commitments and Contingencies |
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 Partnership’s 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 the State of Colorado (the "Droegemueller Action"). The plaintiff seeks 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, and on July 10, 2007, the Managing General Partner filed its answer and affirmative defenses. Given the preliminary stage of this proceeding and the inherent uncertainty in litigation, the Managing General Partner is unable to predict the ultimate outcome of this suit at this time.
A second similar Colorado class action suit was filed against the Managing General Partner in the U.S. District Court for the District of Colorado on December 3, 2007. The plaintiffs seek declaratory relief and to recover compensation for alleged royalty underpayments made by the Managing General Partner for the wells in which it has a working interest in Colorado. Given the preliminary stage of this proceeding and the inherent uncertainty in litigation, the Managing General Partner is unable to predict the ultimate outcome of this suit at this time.
Although at this time the Partnership has not been named as a party in either of these suits, the Managing General Partner believes that the Partnership’s 64 wells in the Wattenberg field will be subject to these lawsuits. Although the outcome of these suits cannot be known with certainty, we believe that we have adequately accrued liabilities and that the ultimate outcome of the proceedings will not have a material adverse impact on the Partnership’s financial position or results of operations.
ROCKIES REGION 2006 LIMITED PARTNERSHIP
(A West Virginia Limited Partnership)
Notes to Financial Statements
Litigation similar to the preceding actions has recently been commenced against several other companies in other jurisdictions where the Managing General Partner and the Partnership conducts business. While the Managing General Partner and Partnership's business models differ from that of the parties involved in such other litigation, and although the Managing General Partner and Partnership have not been named as parties in such other litigation, there can be no assurance that the Managing General Partner and Partnership will not be named as a parties to such other litigation in the future.
Due to the downward trend of Colorado natural gas selling prices in the third quarter 2007, the Managing General Partner decided to shut-in 18 of the Partnership’s wells located in the Piceance Basin for a period of approximately four weeks, beginning on October 1, 2007. As the Colorado selling prices for natural gas began to rise for during the month of October, the Managing General Partner restarted production in phases between November 1, 2007 and November 5, 2007 for all 18 of the wells that were shut-in.
ROCKIES REGION 2006 LIMITED PARTNERSHIP
(A West Virginia Limited Partnership)
Notes to Financial Statements
| (12) | Quarterly Financial Information – (Unaudited) |
Quarterly financial data for the quarters ended March 31, June 30, and September 30, 2007 are as follows:
| STATEMENTS OF OPERATIONS | | | | | | | | | |
| | | For the Quarter Ended | |
| | | March 31, | | | June 30, | | | September 30, | |
| | | 2007 | | | 2007 | | | 2007 | |
| | | (restated) | | | | | | | |
| Revenues: | | | | | | | | | |
| Oil and gas sales | | $ | 4,204,666 | | | $ | 9,904,797 | | | $ | 9,470,701 | |
| Oil and gas price risk management (loss) gain, net | | | (60,931 | ) | | | 80,000 | | | | 524,671 | |
| Total revenues | | | 4,143,735 | | | | 9,984,797 | | | | 9,995,372 | |
| | | | | | | | | | | | | |
| Costs and Expenses: | | | | | | | | | | | | |
| Production and operating costs | | | 740,263 | | | | 1,544,329 | | | | 1,799,505 | |
| Direct costs | | | 21,421 | | | | 19,536 | | | | 129,973 | |
| Depreciation, depletion and amortization | | | 2,021,542 | | | | 4,778,643 | | | | 4,853,220 | |
| Accretion of asset retirement obligation | | | 8,451 | | | | 9,847 | | | | 9,325 | |
| Loss on impairment of oil and gas properties | | | 1,135,208 | | | | 1,310,409 | | | | - | |
| Exploratory dry hole costs | | | 3,395,210 | | | | 3,150,266 | | | | 1,577,101 | |
| Total costs and expenses | | | 7,322,095 | | | | 10,813,030 | | | | 8,369,124 | |
| | | | | | | | | | | | | |
| (Loss) income from operations | | | (3,178,360 | ) | | | (828,233 | ) | | | 1,626,248 | |
| | | | | | | | | | | | | |
| Interest expense | | | 1,200 | | | | 1,927 | | | | 2,058 | |
| Interest income | | | (8,545 | ) | | | (49,639 | ) | | | (36,180 | ) |
| | | | | | | | | | | | | |
| Net (loss) income | | $ | (3,171,015 | ) | | $ | (780,521 | ) | | $ | 1,660,370 | |
| | | | | | | | | | | | | |
| Net (loss) income per Investor Partner unit | | $ | (444 | ) | | $ | (109 | ) | | $ | 233 | |
| | | | | | | | | | | | | |
| Investor Partner units oustanding | | | 4,497 | | | | 4,497 | | | | 4,497 | |
ROCKIES REGION 2006 LIMITED PARTNERSHIP
(A West Virginia Limited Partnership)
Notes to Financial Statements
| STATEMENT OF OPERATIONS | | For the | |
| | | Six Months Ended | |
| | | June 30, 2007 | |
| | | (unaudited) | |
| | | | |
| Revenues: | | | |
| Oil and gas sales | | $ | 14,109,463 | |
| Oil and gas price risk management gain, net | | | 19,069 | |
| Total revenues | | | 14,128,532 | |
| | | | | |
| Costs and Expenses: | | | | |
| Production and operating costs | | | 2,284,592 | |
| Management fee | | | - | |
| Direct costs | | | 40,957 | |
| Depreciation, depletion and amortization | | | 6,800,185 | |
| Accretion of asset retirement obligation | | | 18,298 | |
| Loss on impairment of oil and gas properties | | | 2,445,617 | |
| Exploratory dry hole costs | | | 6,545,476 | |
| Total costs and expenses | | | 18,135,125 | |
| | | | | |
| Loss from operations | | | (4,006,593 | ) |
| | | | | |
| Interest expense | | | 3,127 | |
| Interest income | | | (58,184 | ) |
| | | | | |
| Net loss | | $ | (3,951,536 | ) |
| | | | | |
| Net loss per Investor Partner unit | | $ | (553 | ) |
| | | | | |
| Investor Partner units oustanding | | | 4,497 | |
ROCKIES REGION 2006 LIMITED PARTNERSHIP
(A West Virginia Limited Partnership)
Notes to Financial Statements
| BALANCE SHEETS | | March 31, | | | June 30, | |
| | | 2007 | | | 2007 | |
| Assets | | (restated) | | | | |
| | | | | | | |
| Current assets: | | | | | | |
| Cash and cash equivalents | | $ | 1,172,393 | | | $ | 1,158,121 | |
| Accounts receivable oil and gas sales | | | 5,433,350 | | | | 10,181,103 | |
| Due from Managing General Partner - derivatives, short-term | | | 5,306 | | | | 86,992 | |
| Total current assets | | | 6,611,049 | | | | 11,426,216 | |
| | | | | | | | | |
| Oil and gas properties, successful efforts method | | | 48,692,898 | | | | 95,732,636 | |
| Wells in progress | | | 58,218,584 | | | | 6,718,352 | |
| | | | 106,911,482 | | | | 102,450,988 | |
| Less accumulated depreciation, depletion and amortization | | | (2,528,406 | ) | | | (7,206,627 | ) |
| | | | 104,383,076 | | | | 95,244,361 | |
| | | | | | | | | |
| Noncurrent assets: | | | | | | | | |
| Finance charges | | | 3,792 | | | | 6,773 | |
| Due from Managing General Partner -derivatives, long-term | | | - | | | | 40,360 | |
| Total noncurrent assets | | | 3,792 | | | | 47,133 | |
| | | | | | | | | |
| Total Assets | | $ | 110,997,917 | | | $ | 106,717,710 | |
| | | | | | | | | |
| Liabilities and Partners' Equity | | | | | | | | |
| | | | | | | | | |
| Current liabilities: | | | | | | | | |
| Accounts payable and accrued expenses | | $ | 385,230 | | | $ | 702,194 | |
| Due to Managing General Partner - other | | | 811,695 | | | | 1,139,612 | |
| Total current liabilities | | | 1,196,925 | | | | 1,841,806 | |
| | | | | | | | | |
| Asset retirement obligation | | | 659,716 | | | | 770,166 | |
| | | | | | | | | |
| Partners' equity | | | 109,141,276 | | | | 104,105,738 | |
| | | | | | | | | |
| Total Liabilities and Partners' Equity | | $ | 110,997,917 | | | $ | 106,717,710 | |
ROCKIES REGION 2006 LIMITED PARTNERSHIP
(A West Virginia Limited Partnership)
Notes to Financial Statements
| STATEMENTS OF CASH FLOWS | | For the Three | | | For the Six | |
| | | Months Ended | | | Months Ended | |
| | | March 31, | | | June 30, | |
| | | 2007 | | | 2007 | |
| | | (restated) | | | | |
| Cash flows from operating activities: | | | | | | |
| | | | | | | |
| Net loss | | $ | (3,171,015 | ) | | $ | (3,951,536 | ) |
| Adjustments to reconcile net loss to net cash provided by operating activities: | | | | | | | | |
| Loss on impairment of oil and gas properties | | | 1,135,208 | | | | 2,445,617 | |
| Depreciation, depletion and amortization | | | 2,021,542 | | | | 6,800,185 | |
| Accretion of asset retirement obligation | | | 8,451 | | | | 18,298 | |
| Unrealized loss on derivative transactions | | | 60,931 | | | | (14,497 | ) |
| Exploratory dry hole costs | | | 3,395,210 | | | | 6,545,476 | |
| Changes in operating assets and liabilities: | | | | | | | | |
| Increase in Due from Managing General Partner -derivatives | | | (63,216 | ) | | | (109,834 | ) |
| Increase in accounts receivable - oil and gas sales | | | (4,204,666 | ) | | | (8,952,419 | ) |
| Increase in financing charges | | | (3,554 | ) | | | (6,535 | ) |
| Increase in accounts payable and accrued expenses | | | 271,757 | | | | 588,721 | |
| Increase in due to Managing General Partner - other | | | 567,151 | | | | 895,068 | |
| Net cash provided by operating activities | | | 17,799 | | | | 4,258,544 | |
| | | | | | | | | |
| Cash flows from financing activities: | | | | | | | | |
| Distributions to partners | | | - | | | | (4,255,017 | ) |
| Net cash used in financing activities | | | - | | | | (4,255,017 | ) |
| | | | | | | | | |
| Net increase in cash and cash equivalents | | | 17,799 | | | | 3,527 | |
| Cash and cash equivalents at beginning of period | | | 1,154,594 | | | | 1,154,594 | |
| Cash and cash equivalents at end of period | | $ | 1,172,393 | | | $ | 1,158,121 | |
| | | | | | | | | |
| Supplemental disclosure of non-cash activity: | | | | | | | | |
| Asset retirement obligation, with a corresponding increase to oil and gas properties | | $ | 295,023 | | | $ | 395,626 | |
ROCKIES REGION 2006 LIMITED PARTNERSHIP
(A West Virginia Limited Partnership)
Notes to Financial Statements
(13) Restatement of Historical Financial Statements
In 2007, errors were identified with respect to the Partnership’s accounting for capitalized costs for oil and gas properties. The Managing General Partner bills the Partnership on a cost plus basis for drilling costs incurred. The Partnership agreement states that the Managing General Partner is entitled to reimbursement of drilling costs plus 12.6% of total well costs. In calculating the capitalized costs for oil and gas properties, the Partnership erroneously applied a cost plus rate of 14% to the total well costs. Additionally, the Partnership did not apply the Managing General Partner’s overhead rate to all wells which were capitalized in 2006 and the first quarter of 2007. The net impact of these errors resulted in an understatement of capitalized oil and gas properties for the period from September 7, 2006 (date of inception) to December 31, 2006 and for the quarter ended March 31, 2007. As a result of applying the correct cost plus rate to capitalized oil and gas properties, increasing the total capitalized costs for oil and gas properties, the Partnership determined that depreciation, depletion and amortization and impairment of oil and gas properties (specifically in the Nesson field in North Dakota for the period ended December 31, 2006 which was not impaired prior to these adjustments) and dry hole costs were improperly recorded.
The restatement resulted in the following adjustments on net loss its impact on depreciation, depletion and amortization, impairment of oil and gas properties and dry hole costs.
| | | | | | Period From | |
| | | | | | September 7, 2006 | |
| | | Quarter Ended | | | (date of inception) to | |
| Income / (expense) | | March 31, | | | December 31, | |
| | | 2007 | | | 2006 | |
| | | (unaudited) | | | | |
| | | | | | | |
| Depreciation, depletion and amortization | | $ | 599,234 | | | $ | (11,758 | ) |
| Loss on impairment of oil and gas properties | | | 3,594,097 | | | | (944,970 | ) |
| Dry hole costs | | | (3,002,454 | ) | | | - | |
| Net (decrease) increase in reported net loss | | $ | 1,190,877 | | | $ | (956,728 | ) |
Restated financial statements for the quarter ended March 31, 2007 and the period from September 7, 2006 (date of inception) to December 31, 2006 are presented below.
ROCKIES REGION 2006 LIMITED PARTNERSHIP
(A West Virginia Limited Partnership)
Notes to Financial Statements
| STATEMENTS OF OPERATIONS | | | | | For the Period From | |
| | | For the Quarter Ended | | | September 7, 2006 (date of inception) | |
| | | March 31, 2007 | | | to December 31, 2006 | |
| | | Previously | | | | | | Previously | | | | |
| | | Reported | | | Restated | | | Reported | | | Restated | |
| | | (unaudited) | | | (unaudited) | | | | | | | |
| Revenues: | | | | | | | | | | | | |
| Oil and gas sales | | $ | 4,204,666 | | | $ | 4,204,666 | | | $ | 1,228,684 | | | $ | 1,228,684 | |
| Oil and gas price risk management loss, net | | | (60,931 | ) | | | (60,931 | ) | | | (408 | ) | | | (408 | ) |
| Total revenues | | | 4,143,735 | | | | 4,143,735 | | | | 1,228,276 | | | | 1,228,276 | |
| | | | | | | | | | | | | | | | | |
| Cost and expenses: | | | | | | | | | | | | | | | | |
| Production and operating costs | | | 740,263 | | | | 740,263 | | | | 189,069 | | | | 189,069 | |
| Management fee | | | - | | | | - | | | | 1,349,108 | | | | 1,349,108 | |
| Direct costs | | | 21,421 | | | | 21,421 | | | | 176,613 | | | | 176,613 | |
| Depreciation, depletion and amortization | | | 2,620,776 | | | | 2,021,542 | | | | 991,362 | | | | 1,003,120 | |
| Accretion of asset retirement obligations | | | 8,451 | | | | 8,451 | | | | 3,148 | | | | 3,148 | |
| Loss on impairment of oil and gas properties | | | 4,729,305 | | | | 1,135,208 | | | | 6,184,713 | | | | 7,129,683 | |
| Exploratory dry hole costs | | | 392,757 | | | | 3,395,210 | | | | - | | | | - | |
| Total costs and expenses | | | 8,512,973 | | | | 7,322,095 | | | | 8,894,013 | | | | 9,850,741 | |
| | | | | | | | | | | | | | | | | |
| Loss from operations | | | (4,369,238 | ) | | | (3,178,360 | ) | | | (7,665,737 | ) | | | (8,622,465 | ) |
| | | | | | | | | | | | | | | | | |
| Interest expense | | | 1,199 | | | | 1,200 | | | | 15 | | | | 15 | |
| Interest income | | | (8,545 | ) | | | (8,545 | ) | | | (1,165,941 | ) | | | (1,165,941 | ) |
| | | | | | | | | | | | | | | | | |
| Net loss | | $ | (4,361,892 | ) | | $ | (3,171,015 | ) | | $ | (6,499,811 | ) | | $ | (7,456,539 | ) |
| | | | | | | | | | | | | | | | | |
| Net loss per Investor Partner unit | | $ | (611 | ) | | $ | (444 | ) | | $ | (1,022 | ) | | $ | (1,156 | ) |
| | | | | | | | | | | | | | | | | |
| Investor Partner units outstanding | | | 4,497 | | | | 4,497 | | | | 4,497 | | | | 4,497 | |
ROCKIES REGION 2006 LIMITED PARTNERSHIP
(A West Virginia Limited Partnership)
Notes to Financial Statements
| BALANCE SHEETS | | March 31, 2007 | | | December 31, 2006 | |
| | | Previously | | | | | | Previously | | | | |
| | | Reported | | | Restated | | | Reported | | | Restated | |
| | | (unaudited) | | | (unaudited) | | | | | | | |
| Assets | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| Current assets: | | | | | | | | | | | | |
| Cash and cash equivalents | | $ | 1,172,394 | | | $ | 1,172,393 | | | $ | 1,154,594 | | | $ | 1,154,594 | |
| Accounts receivable - oil and gas sales | | | 5,433,350 | | | | 5,433,350 | | | | 1,228,684 | | | | 1,228,684 | |
| Due from Managing General Partner-derivatives | | | 5,306 | | | | 5,306 | | | | 1,549 | | | | 1,549 | |
| Total current assets | | | 6,611,050 | | | | 6,611,049 | | | | 2,384,827 | | | | 2,384,827 | |
| | | | | | | | | | | | | | | | | |
| Oil and gas properties, successful efforts method | | | 49,426,916 | | | | 48,692,898 | | | | 22,463,755 | | | | 21,835,420 | |
| Wells in progress | | | 57,470,081 | | | | 58,218,584 | | | | 89,756,535 | | | | 89,428,539 | |
| | | | 106,896,997 | | | | 106,911,482 | | | | 112,220,290 | | | | 111,263,959 | |
| Less accumulated depreciation, depletion and amortization | | | (2,748,071 | ) | | | (2,528,406 | ) | | | (623,549 | ) | | | (623,946 | ) |
| | | | 104,148,926 | | | | 104,383,076 | | | | 111,596,741 | | | | 110,640,013 | |
| | | | | | | | | | | | | | | | | |
| Finance charges | | | 3,792 | | | | 3,792 | | | | 238 | | | | 238 | |
| Due from Managing General Partner -derivatives, long-term | | | - | | | | - | | | | 1,472 | | | | 1,472 | |
| | | | | | | | | | | | | | | | | |
| Total Assets | | $ | 110,763,768 | | | $ | 110,997,917 | | | $ | 113,983,278 | | | $ | 113,026,550 | |
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| Liabilities and Partners' Equity | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| Current liabilities: | | | | | | | | | | | | | | | | |
| Accounts payable and accrued expenses | | $ | 385,230 | | | $ | 385,230 | | | $ | 113,473 | | | $ | 113,473 | |
| Due to Managing General Partner - other | | | 811,695 | | | | 811,695 | | | | 244,544 | | | | 244,544 | |
| Total current liabilities | | | 1,196,925 | | | | 1,196,925 | | | | 358,017 | | | | 358,017 | |
| | | | | | | | | | | | | | | | | |
| Asset retirement obligations | | | 659,716 | | | | 659,716 | | | | 356,242 | | | | 356,242 | |
| | | | | | | | | | | | | | | | | |
| Partners' equity | | | 108,907,127 | | | | 109,141,276 | | | | 113,269,019 | | | | 112,312,291 | |
| | | | | | | | | | | | | | | | | |
| Total Liabilities and Partners' Equity | | $ | 110,763,768 | | | $ | 110,997,917 | | | $ | 113,983,278 | | | $ | 113,026,550 | |
Statements of Cash Flows:
Only certain line items within cash flows from operating activities have been restated. The net change in cash and cash equivalents for the period and the cash and cash equivalents at the end of the period are the same as in the original presentation for the financial statements. No changes were made to the cash flows from investing and financing activities. Accordingly, no reconciliation of the statement of cash flows is provided herein.
