ITEM 1. BUSINESS
Overview
Ridgewood Energy P Fund, LLC (the “Fund”), (an exploratory stage enterprise) is a Delaware limited liability company and was formed on March 21, 2005 to acquire interests primarily in oil and natural gas projects located in the U.S. waters of the Gulf of Mexico. Ridgewood Energy Corporation (“Ridgewood Energy” or the “Manager”), a Delaware corporation, is the Manager. As the Manager, Ridgewood Energy has direct and exclusive control over the management and control of Fund operations. The Fund is engaged in the acquisition, development and production of oil and natural gas projects in the Gulf of Mexico. To date, the Fund has focused primarily on acquiring oil and natural gas projects in the shallow waters of the Gulf of Mexico in locations with access to existing gathering and processing infrastructure or where such infrastructure can be constructed economically and efficiently.
The Fund initiated its private placement offering on May 16, 2005, selling whole and fractional shares of membership interests at $150 thousand per share. There is no public market for these shares and one is not likely to develop. In addition, the shares are subject to severe restrictions on transfer and resale and cannot be transferred or resold except in accordance with the Fund’s limited liability company agreement (“LLC agreement”) and applicable federal and state securities. The offering was terminated on October 30, 2005. The Fund raised approximately $138.3 million. After payment of approximately $22.2 million in offering fees, commissions and investment fees, the Fund had approximately $116.1 million for investments and operating expenses. As of March 2, 2007, the Fund had 1,507 shareholders.
Manager
Ridgewood Energy was founded in 1982 by Robert E. Swanson. As the Manager, Ridgewood Energy has direct and exclusive control over the management of the Fund’s operations. With respect to project investment, Ridgewood Energy locates potential projects, conducts appropriate due diligence and negotiates and completes the transactions in which the investments are made. This includes not only review of existing title documents, reserve information, and other technical specifications regarding a project, but also the review and preparation of participation agreements and other agreements relating to an investment.
In addition, Ridgewood Energy performs (or arranges for the performance of) the management and administrative services required for Fund operations. Among other services, Ridgewood Energy administers the accounts and handles relations with the shareholders, including tax and other financial information. In addition, Ridgewood Energy provides the Fund with office space, equipment and facilities and other services necessary for its operation. Finally, Ridgewood Energy manages and conducts the Fund’s relations with custodians, depositories, accountants, attorneys, brokers-dealers, corporate fiduciaries, insurers, banks and others, as required.
The Fund is required to pay all other expenses it incurs, including expenses of preparing and printing periodic reports for shareholders and the SEC, commission fees, taxes, outside legal, accounting and consulting fees, litigation expenses and other expenses, if any, properly payable by us. The Fund is required to reimburse the Manager for all such Fund expenses paid by them.
As compensation for their management services, the Manager is entitled to (i) an annual Management Fee, payable monthly, equal to 2.5% of the total capital contributions made by the Fund’s shareholders and (ii) a 15% interest in the cash distributions made to the Fund’s shareholders. The Manager received from the Fund for its management services a total of approximately $3.5 million, $1.9 million and $5.3 million for the year ended December 31, 2006, the period March 21, 2005 (Inception) through December 31, 2005 and the period March 21, 2005 (Inception) through December 31, 2006, respectively. There have been no cash distributions to shareholders paid through December 31, 2006. Effective January 1, 2007, the Manager has changed its policy regarding the annual management fee. Commencing in January 2007, the management fee payable will be equal to 2.5% of the total shareholder capital contributions, net of dry-hole expenses incurred by the Fund. For the P Fund, the management fee will be reduced by $0.1 million per month, based upon dry-hole expenses of $48.7 million from inception through December 31, 2006.
Business Strategy
The Fund’s primary investment objective is to generate cash flow from the acquisition, exploration, production and sale of crude oil and natural gas from oil and natural gas projects. The Fund has invested and participates in exploration and production projects located in the waters of the Gulf of Mexico offshore Texas, Louisiana and Alabama on the Outer Continental Shelf (“OCS”). These activities are governed by the Outer Continental Shelf Lands Act (“OCSLA”) enacted in 1953 and administered by the Mineral Management Services (“MMS”). The Fund generally looks to invest in projects that have been proposed by larger independent oil and natural gas companies seeking to minimize their risks by selling a portion of their interest in a project. These investments may require the Fund to pay a disproportionate part of the drilling costs on the exploratory well of a project than its ownership interest would otherwise require. This is called a promote and is common in the oil and natural gas exploration industry. In addition, notwithstanding the sale of an interest to the Fund, the seller may retain a right for some period of time to payments from sales of oil and natural gas production from a well or project. This is called an overriding interest which is also common in this industry. Notwithstanding any such promote or overriding interest, the Fund has tried to invest in projects that it believes contain sufficient commercial quantities of oil or natural gas and which are near (i) existing oil or natural gas gathering and processing infrastructure and (ii) developed markets where the Fund can sell its oil or natural gas.
The Fund tries to focus on projects that have significant reserve potential and which are projected to have the shortest time period from investment to first production. The Fund does not operate these projects, and although it has a vote, it is not in control of the schedule pursuant to which its projects are developed and completed. Moreover, when performing due diligence with respect to a project, the Fund must rely on the independent reservoir engineers who are hired and paid, in most cases, by the operator. The Fund does engage certain consultants to examine and review such reserve estimates and seismic information on its behalf.
Manager’s Investment Committee and Investment Criteria
The New Jersey office has four executives on the investment committee, three of whom have been working together at Ridgewood Energy for 20 years. The Houston office, which opened in 2003, has five executives on the investment committee who provide operational, scientific and technical oil and gas expertise. In considering projects, the Manager and investment committee investigates each such project against a list of factors that it believes will result in the selection of those projects that have the highest probability of success. These factors, in no particular order, include, but are not limited to, the following (i) targeting projects that have or are expected to have operators with significant resources and experience in oil and gas exploration; (ii) targeting projects that have or are expected to have partners that also have significant resources and experience in oil and gas exploration; (iii) technical quality of the project including its geology, seismic profile, locational trends, and whether the project has potential for multiple prospects; (iv) oil or gas reserve potential; (v) whether and the extent to which the operator participates as a working interest owner in the project; (vi) economic factors, such as potential revenues from the project, the rate of return, and estimated time to first production; (vii) risk factors associated with exploration, as more fully described in this filing; (viii) existence of drilling rigs, platforms and other infrastructure, at or nearby the Project; (ix) proposed drilling schedule; (x) terms of the proposed transaction, including contractual restrictions and obligations and lease term; and (xi) overall cost of the project.
Properties
The following table is a summary of the Fund’s investments detailing the actual dollars spent in millions on each project. The total spent on dry-holes represents the total amount spent on each project and subsequently written off.
(a)
Dry-hole costs represent wells that have been drilled but do not have commercially productive oil and/or natural gas reservoirs.
Projects
The Fund owns a 40% working interest (as defined in Item 1. under “Working Interest in Oil and Natural Gas Leases”) ownership in West Cameron 265/266 operated by Marathon Oil Co. (“Marathon”), a 30% working interest in South Marsh Island 231 operated by Stone Energy Corporation (“Stone”), a 22.5% working interest in West Cameron 109 operated by Nexen, Inc. (“Nexen”), a 8.3% working interest in Green Canyon 246 operated by Woodside Energy LTD. (“Woodside”), a 10% interest in South Timbalier 135/136 operated by Chevron Corporation (“Chevron”) and a 43.3% working interest in West Cameron 593 operated by Newfield Exploration Company (“Newfield”). These projects, summarized in the table above, are described more fully below.
West Cameron 265/266
In 2005, the Fund acquired a 40% working interest in the exploratory project West Cameron 265/266 from Marathon, the Operator. In consideration of this interest, the Fund agreed to pay 60% of the drilling costs on the first well. The project is located in the center of the two federal lease blocks and had a five to seven reservoir potential, stacked one on top of the other between 11,000 feet and 19,000 feet. The well began drilling in February 2006. The well was deemed to be non-commercial. On May 16, 2006, the decision was made to plug and abandon the well. Dry-hole costs related to West Cameron 265/266, including plug and abandonment expenses, incurred by the Fund for the year ended December 31, 2006, the period March 21, 2005 (Inception) through December 31, 2005, and for the period March 21, 2005 (Inception) through December 31, 2006 were approximately $21.5 million, $0.6 million and $22.0 million, respectively.
South Marsh Island 231
In 2005, the Fund acquired a 30% working interest in the exploratory project South Marsh Island 231 from Stone, the Operator. In consideration for this working interest, the Fund agreed to pay 50% of the drilling costs for the first well. The target was two natural gas reservoirs between 15,000 feet and 15,800 feet. The well began drilling on February 18, 2006 and reached its total depth of 15,800 feet on March 31, 2006, 44 days after the first day of drilling. Attempts to evaluate the well with electric wireline logs failed. The well was evaluated with logging while drilling (LWD) tools. The well was deemed to be non-commercial. On April 5, 2006 the decision was made to plug and abandoned the well. Dry-hole costs related to South Marsh Island 231, including plug and abandonment expenses, incurred by the Fund for the year ended December 31, 2006, the period March 21, 2005 (Inception) through December 31, 2005, and for the period March 21, 2005 (Inception) through December 31, 2006 were approximately $8.4 million, nil and $8.4 million, respectively.
West Cameron 109
In August 2006, the fund acquired a 22.5% working interest in the exploratory project West Cameron 109 from Nexen, the operator. In consideration for this interest, the Fund agreed to pay 30% of the drilling costs for the first well. On December 1, 2006, the Fund was informed by Nexen, that the exploratory well being drilled in West Cameron 109 lease block did not have commercially productive quantities of either oil or natural gas and was therefore deemed an unsuccessful well or dry-hole. In addition, the well was plugged and abandoned. Dry-hole costs related to West Cameron 109, including plug and abandonment expenses, incurred by the Fund for the year ended December 31, 2006, the period March 21, 2005 (Inception) through December 31, 2005, and for the period March 21, 2005 (Inception) through December 31, 2006 were approximately $8.2 million, nil and $8.2 million, respectively.
Green Canyon 246
In July 2006, the Fund acquired a 5% working interest in the exploratory project Green Canyon 246 from Marathon, the operator from acquisition date until December 28, 2006. In consideration for the interest from Marathon, the Fund agreed to pay 10% of the drilling costs on the first well. The project, located offshore Louisiana in 3,280 feet of water, had multiple target reservoirs between 13,000 and 17,000 feet. In December 2006, oil was discovered in one reservoir of the well, however, a side-track operation would need to be performed to determine the commercial viability of the well. Marathon elected not to participate in the side-track and forfeited its 40% interest. Woodside and the Fund elected to proceed, taking over, on a pro-rated basis, Marathon’s 40% interest at no additional cost to the Fund, which increased its ownership to 8.3%, or Woodside, which took over the project as operator. Upon completion of the side-track, on January 24, 2007, the Fund was informed that the exploratory well being drilled did not have commercially productive quantities of either oil or natural gas and had therefore been deemed an unsuccessful well or dry-hole. The Fund owns an 8.3% working interest in Green Canyon 246. Dry-hole costs related to Green Canyon 246, including plug and abandonment expenses, incurred by the Fund for the year ended December 31, 2006, the period March 21, 2005 (Inception) through December 31, 2005, and for the period March 21, 2005 (Inception) through December 31, 2006 were approximately $4.8 million, nil and $4.8 million, respectively. The Fund incurred additional dry-hole costs related to Green Canyon 246 of $1.4 million during 2007.
South Timbalier 135/136
In 2006, the Fund acquired a 10% working interest in the exploratory project South Timbalier 135/136 from Chevron, the operator. In consideration for this interest, the Fund agreed to pay 10% of the drilling costs on the first well. The project, located offshore Louisiana in 3,280 feet of water, had multiple target reservoirs between 13,000 and 17,000 feet. On January 24, 2007, the Fund was informed by Chevron, that the exploratory well being drilled did not have commercially productive quantities of either oil or natural gas and has therefore been deemed an unsuccessful well or dry-hole. Dry-hole costs related to South Timbalier, including plug and abandonment expenses, incurred by the Fund for the year ended December 31, 2006, the period March 21, 2005 (Inception) through December 31, 2005, and for the period March 21, 2005 (Inception) through December 31, 2006 were approximately $5.2 million,
nil and $5.2 million, respectively. The Fund incurred additional dry-hole costs related to South Timbalier 135/136 of $1.6 million during 2007.
West Cameron 593
In July 2006, the Fund acquired a 43.28% working interest in the exploratory project West Cameron 593 from Newfield Exploration, the operator.
On August 15, 2006, the Fund started drilling West Cameron 593 a 12,849 foot single well project in approximately 257 feet of water offshore Louisiana. West Cameron 593 was deemed successful in mid-September and the well was completed in October. A flow test was performed in October indicating strong flow rates. Newfield has an existing production platform approximately 10,000 feet away, also on lease block 593, that will produce and sell the Fund’s proportionate share of gas after a flow-line is built to connect the production platforms. Newfield estimates the tie-in to be complete in mid-spring 2007, at which point the well will be put in production. The Fund has made capital expenditures of $10.7 million towards an estimated budget of $13.5 million.
Working Interest in Oil and Natural Gas Leases
Existing projects, and future projects, if any, are expected to be located in the waters of the Gulf of Mexico offshore from Texas, Louisiana and Alabama on the OCS. The OCSLA, which was enacted in 1953, governs certain activities with respect to working interests and the exploration of oil and natural gas in the OCS.
Under OCSLA, the United States federal government has jurisdiction over oil and natural gas exploration and development on the OCS. As a result, the United States Secretary of the Interior is empowered to sell exploration, development and production leases of a defined submerged area of the OCS, or a block, through a competitive bidding process. Such activity is conducted by the MMS, an agency of the United States Department of Interior. As part of the leasing activity and as required by the OCSLA, the leases auctioned include specified lease terms such as the length of the lease, the amount of royalty to be paid, lease cancellation and suspension, and, to a degree, the planned activities of exploration and production to be conducted by the lessee. In addition, the OCSLA grants the Secretary of the Interior continuing oversight and approval authority over exploration plans throughout the term of the lease.
The winning bidder(s) at the lease sale, or the lessee(s), are given a lease by the MMS that grants such lessee(s) the exclusive right to conduct oil and natural gas exploration and production activities within a specific lease block, or working interest. Leases in the OCS are generally issued for a primary lease term of 5, 8 or 10 years depending on the water depth of the lease block. The 5-year lease term is for blocks in water depths generally less than 400 meters, 8 years for depths between 400 meters to 800 meters and 10 years for depths in excess of 800 meters. During this primary lease term, except in limited circumstances, lessees are not subject to any particular requirements to conduct exploratory or development activities. However, once a lessee drills a well and begins production, the lease term is extended for the duration of commercial production.
The lessee of a particular block, for the term of the lease, has the right to drill and develop exploratory wells and conduct other activities throughout the block. If the initial well on the block is successful, a lessee (or third-party operator for a project) may conduct additional geological studies and may determine to drill additional or development wells. If a development well is to be drilled in the block, each lessee owning working interests in the block must be offered the opportunity to participate in, and cover the costs of, the development well up to that particular lessee’s working interest ownership percentage.
Generally, working interests in an offshore gas lease under the OCSLA pay a 16.67% royalty to the MMS. Therefore, the net revenue interest of the holders of 100% of the working interest in the projects in which the Fund will invest is approximately 83.33% of the total revenue of the project, and, is further reduced by any other royalty burdens that apply to a lease block. However, as described below, the MMS has adopted royalty relief for existing OCS leases for those who drill deep oil and natural gas projects.
Mineral Management Services Deep Natural Gas Royalty Incentive
On January 26, 2004, the MMS promulgated a rule providing incentives for companies to increase deep oil and natural gas production in the Gulf of Mexico (the “Royalty Relief Rule”). Under the Royalty Relief Rule, lessees will be eligible for royalty relief on their existing leases if they drill and perforate wells for new and deeper reserves at depths greater than 15,000 feet subsea. In addition, an even larger royalty relief would be available for wells drilled and perforated deeper than 18,000 feet subsea. It should be noted that the Royalty Relief Rule does not extend to deep waters of the Gulf of Mexico off the continental shelf nor does it apply if the price of natural gas exceeds $9.91 Million British Thermal Units (“mmbtu”), adjusted annually for inflation. The Royalty Relief Rule is limited to leases in a water depth less than 656 feet, or 200 meters. With respect to the Fund’s projects that are currently drilling, the Fund will determine once completed if the project will be able to claim relief under the Royalty Relief Rule.
Oil and Natural Gas Agreements
None of the Fund’s projects are producing and therefore no definitive arrangements have been made for the sale or transportation of oil and natural gas that may be produced from the Fund’s projects. The Manager believes however, that it is likely that oil and natural gas from the Fund’s other projects will have access to pipeline transportation and can be marketed in a similar fashion. All of the Fund’s current projects are near existing transportation infrastructure and pipelines. As mentioned above in Manager’s Investment Committee and Investment Criteria, as part of the Manager’s review of a potential project, access to existing transportation infrastructure is an extremely important factor as the existence of such infrastructure enables production from a successful well to get to market quickly.
Operator
The projects in which the Fund has invested are operated and controlled by unaffiliated third-party entities acting as operators. The operator is responsible for drilling, administration and production activities for leases jointly owned by working interest owners and acts on behalf of all working interest owners under the terms of the applicable offshore operating agreements. In certain circumstances, operators will enter into agreements with independent third-party subcontractors and suppliers to provide the various services required for operating leases. Currently, the Fund’s projects are operated by Marathon, Stone, Nexen, Chevron, Woodside and Newfield.
Because the Fund does not operate any of the projects in which it has acquired an interest, shareholders must not only bear the risk that the Manager will be able to select suitable projects, but also that, once selected, such projects will be managed prudently, efficiently and fairly by the operators.
Insurance
The Manager has obtained hazard, property, general liability and other insurance in commercially reasonable amounts to cover the projects, as well as general liability and similar coverage for its business operations. However, there is no assurance that such insurance will be adequate to protect the Fund from material losses related to the projects. In addition, the Manager’s past practice has been to obtain insurance as a package that is intended to cover most, if not all, of the funds under its management. These projects are owned by affiliates of the Fund. While the Manager believes it has obtained adequate insurance in accordance with customary industry practices, the possibility exists, depending on the extent of the incident, that insurance coverage may not be sufficient to cover all losses. In addition, depending on the extent, nature, and payment of any claims to the Fund’s affiliates, yearly insurance limits may become exhausted and be insufficient to cover a claim made by the Fund in that year.
Salvage Fund
As to projects in which the Fund owns a working interest, the Fund deposits in a separate interest-bearing account, or a salvage fund, which is in the nature of a sinking fund, money to help provide for the Fund’s proportionate share of the cost of dismantling production platforms and facilities, plugging and abandoning the projects, and removing the platforms, facilities and projects in respect of each of such projects after their useful life, in accordance with applicable federal and state laws and regulations. There is no assurance that the salvage fund will have sufficient assets to meet these requirements and any unfunded expenses, and the Fund may be liable for such expenses. The Fund has deposited approximately $1 million from capital contributions into a salvage fund which the Fund estimates to be sufficient to meet its potential requirements. If management later determines the deposit and earned interest is not enough to cover the Fund’s proportionate share of expense, the Fund will deposit payments from operating income to make up any differences. Any portion of a salvage fund that remains after the Fund pays its share of the actual salvage cost will be distributed to the shareholders. There are no legal restrictions on the withdrawal of the salvage fund.
Seasonality
Generally, the Fund’s business operations are not subject to seasonal fluctuations in the demand for oil and natural gas that would result in more of the Fund’s oil and natural gas being sold, or likely to be sold, during one or more particular months or seasons. Once a project is drilled and reserves of oil and natural gas are determined to exist, the operator of the project extracts such reserves throughout the year. Oil and natural gas, once extracted, can be sold at any time during the year.
However, the Fund’s drilling, production and transportation operations are subject to seasonal risks, such as hurricanes, that may affect the Fund’s ability to bring such oil or natural gas to the market and, consequently, affect the price for such oil and natural gas. The National Hurricane Center defines hurricane season in the Atlantic Region, Caribbean, and Gulf of Mexico to be from June 1 through November 30. During hurricane season, the number and intensity of and resulting damage from hurricanes in the Gulf of Mexico region could affect the gathering and processing infrastructure, drilling platforms or the availability or price of repair or replacement equipment. As a result, these factors may affect the supply and, consequently, the price of oil and natural gas resulting in an increase in price if supplies are reduced. However, even if commodity prices increase because of weather related shortages, the Fund may not be in a position to take immediate advantage of any such price increase if, as a result of such weather related incident, damage occurred to its projects, the gathering infrastructure or in the transportation network.
The Manager has had past experiences which indicate the typical interruption in operations resulting from a hurricane that does not result in significant damage may be approximately three to seven days. The Manager has experienced the range of possible interruptions in operations due to hurricanes from as little as no damage and insignificant or no interruptions to significant damage and extended interruptions. However, it is impossible to predict whether and to what extent hurricanes and damage may occur and to what projects.
Customers
The Fund’s existing projects have not yet been developed to the point where reserves of oil and natural gas have been discovered or extracted. As a result, the Fund has not yet contracted with third parties to sell such oil and natural gas and therefore has no customers or any one customer upon which it depends for more than ten percent (10%) of the Fund’s revenues.
Competition
Strong competition exists in the acquisition of oil and natural gas leases and in all sectors of the oil and natural gas exploration and production industry. Although the Fund does not compete for the lease acquisition of working interests from the MMS, it does compete with other companies for the acquisition of percentage ownership interests in oil and natural gas working interests in the secondary market.
In many instances, the Fund competes for projects with large independent oil and natural gas producers who generally have significantly greater access to capital resources, have a larger staff, and more experience in oil and natural gas exploration and production than the Fund. As a result, these larger companies are in a position that they could outbid the Fund for a project. However, because these companies are so large and have such significant resources, they tend to focus more on projects that are larger, have greater reserve potential, but cost significantly more to explore and develop. These larger projects increasingly tend to be projects in the deepwater areas of the Gulf of Mexico and the North Sea off the coast of Great Britain. However, the focus of these companies on larger projects does not necessarily mean that they will not investigate and/or acquire smaller projects in shallow waters for which the Fund competes. Many of these larger companies have participated in the auctions for lease blocks directly from the U.S. Government. In such cases, these companies obtain from the U.S. Government 100% of the leasehold of a particular lease block in the Gulf of Mexico. In order to obtain even more resources to invest in other larger and more expensive projects, they diversify current holdings, including projects they own in the shallow waters of the Gulf of Mexico, by selling off percentage interests in these lease blocks. As a result, very good projects in the shallow waters of the Gulf of Mexico become available. The Fund, therefore, has opportunities to acquire interests in these smaller, yet economically attractive projects.
Employees
The Fund has no employees as the Manager operates and manages the Fund.
Offices
The Manager’s principal executive offices are located at 947 Linwood Avenue, Ridgewood, NJ 07450, and its phone number is 800-942-5550. The Manager also leases additional office space at 11700 Old Katy Road, Houston, TX 77079.
Regulation
Oil and natural gas exploration, development and production activities are subject to extensive federal and state laws and regulations. Regulations governing exploration and development activities require, among other things, the Fund’s operators to obtain permits to drill projects and to meet bonding, insurance and environmental requirements in order to drill, own or operate projects. In addition, the location of projects, the method of drilling and casing projects, the restoration of properties upon which projects are drilled and the plugging and abandoning of projects are also subject to regulations.
Outer Continental Shelf Lands Act
The Fund’s projects are located in the offshore waters of the Gulf of Mexico on the OCS. The Fund’s operations and activities, therefore, are governed by, among other things, the OCSLA.
Under OCSLA, the United States federal government has jurisdiction over oil and natural gas development on the OCS. As a result, the United States Secretary of the Interior is empowered to sell exploration, development and production leases of a defined submerged area of the OCS, or a block, through a competitive bidding process. Such activity is conducted by the MMS, an agency of the United States Department of Interior. The MMS administers federal offshore leases pursuant to regulations promulgated under the OCSLA. Lessees must obtain MMS approval for exploration, development and production plans prior to the commencement of offshore operations. In addition, approvals and permits are required from other agencies such as the U.S. Coast Guard, the Army Corps of Engineers and the Environmental Protection Agency. Offshore operations are subject to numerous regulatory requirements, including stringent engineering and construction specifications related to offshore production facilities and pipelines and safety-related regulations concerning the design and operating procedures of these facilities and pipelines. MMS regulations also restrict the flaring or venting of production and proposed regulations would prohibit the flaring of liquid hydrocarbons and oil without prior authorization.
The MMS has also imposed regulations governing the plugging and abandonment of wells located offshore and the installation and removal of all production facilities. Under certain circumstances, the MMS may require operations on federal leases to be suspended or terminated. Any such suspension or termination could adversely affect the Fund’s operations and interests.
The MMS conducts auctions for lease blocks of submerged areas offshore. As part of the leasing activity and as required by the OCSLA, the leases auctioned include specified lease terms such as the length of the lease, the amount of royalty to be paid, lease cancellation and suspension, and, to a degree, the planned activities of exploration and production to be conducted by the lessee. In addition, the OCSLA grants the Secretary of the Interior continuing oversight and approval authority over exploration plans throughout the term of the lease.
Sales and Transportation of Natural Gas/Oil
The Fund expects to sell its proportionate share of oil and natural gas to the market and to receive market prices from such sales. These sales are not currently subject to regulation by any federal or state agency. However, in order for it to make such sales the Fund is dependent upon unaffiliated pipeline companies whose rates, terms and conditions of transport are subject to regulation by the Federal Energy Regulatory Commission (“FERC”). The rates, terms and conditions are regulated by FERC pursuant to a variety of statutes including the OSCLA, the Natural Gas Policy Act and the Energy Policy Act of 1992. Generally, depending on certain factors, pipelines can charge rates that are either market-based or cost-of-service. In some circumstances, rates can be agreed upon pursuant to settlement. Thus, the rates that pipelines charge us, although regulated, are beyond the Fund’s control. Nevertheless, such rates would apply uniformly to all transporters on that pipeline and, as a result, the impact to the Fund of any changes in such rates, terms or conditions would not impact its operations differently in any material way than the impact upon other oil or natural gas producers and marketers.
Environmental Matters and Regulation
The Fund’s operations are subject to pervasive environmental laws and regulations governing the discharge of materials into the air and water and the protection of aquatic species and habitats. However, although it shares the liability along with its other working interest owners for any environmental damage, most of the activities to which these environmental laws and regulations apply are conducted by the operator on the Fund’s behalf. Nevertheless, environmental laws and regulations to which its operations are subject may require the Fund, or the operator, to acquire permits to commence drilling operations, restrict or prohibit the release of certain materials or substances into the environment, impose the installation of certain environmental control devices, require certain remedial measures to prevent pollution and other discharges such as the plugging of abandoned projects and, finally, impose in some instances severe penalties, fines and liabilities for the environmental damage that is caused by the Fund’s projects.
Some of the environmental laws that apply to oil and natural gas exploration and production are:
The Oil Pollution Act. The Oil Pollution Act (“OPA”) amends Section 311 of the Federal Water Pollution Act (the “Clean Water Act”) and was enacted in response to the numerous tanker spills, including the Exxon Valdez that occurred in the 1980s. Among other things, the OPA clarifies the federal response authority to and increases penalties for spills. The OPA establishes a new liability regime for oil pollution incidents in the aquatic environment. Essentially, the OPA provides that a responsible party for a vessel or facility from which oil is discharged or which poses a substantial threat of a discharge could be liable for certain specified damages resulting from a discharge of oil, including clean-up and remediation, loss of subsistence use of natural resources, real or personal property damages, as well as certain public and private damages. A responsible party includes a lessee of an offshore facility.
The OPA also requires a responsible party to submit proof of its financial responsibility to cover environmental cleanup and restoration costs that could be incurred in connection with an oil spill. Under the OPA, parties responsible for offshore facilities must provide financial assurance of at least $35 million to address oil spills and associated damages. In certain limited circumstances, that amount may be increased to $150 million. As indicated earlier, the Fund has not been required to make any such showing to the MMS as the operator is responsible for such compliance. However, notwithstanding the operator’s responsibility for compliance, in the event of an oil spill, the Fund, along with the operator and other working interest owners, could be liable under the OPA for the resulting environmental damage.
Federal Water Pollution Act/Clean Water Act. Generally, the Federal Water Pollution Act/Clean Water Act imposes liability for the unauthorized discharge of petroleum products into the surface and coastal U.S. waters except in strict conformance with discharge permits issued by the federal (or state if applicable) agency. Regulations governing water discharges also impose other requirements, such as the obligation to prepare spill response plans. Again, the Fund’s operators are responsible for compliance with the Clean Water Act although the Fund may be liable for any failure of the operator to do so.
Federal Clean Air Act. The Federal Clean Air Act restricts the emission of certain air pollutants. Prior to constructing new facilities, permits may be required before work can commence and existing facilities may be required to incur additional capital costs to add equipment to ensure and maintain compliance. As a result, the Fund’s operations may be required to incur additional costs to comply with the Clean Air Act.
Other Environmental Laws. In addition to the above, the Fund’s operations may be subject to the Resource Conservation and Recovery Act, which regulates the generation, transportation, treatment, storage, disposal and cleanup of certain hazardous wastes, as well as the Comprehensive Environmental Response, Compensation and Liability Act which imposes joint and several liability without regard to fault or legality of conduct on classes of persons who are considered responsible for the release of a hazardous substance into the environment.
The above represents a brief outline of the major environmental laws that may apply to the Fund’s operations. The Fund believes that its operators are in compliance with each of these environmental laws and the regulations promulgated there under.
Potential Tax Benefits
The following discussion is a summary of the primary tax benefits of ownership of a membership interest in the Fund and does not include all possible tax benefits or other tax implications of such ownership.
Deduction of Intangible Drilling and Development Costs
Section 263(c) of the Internal Revenue Code of 1986, as amended (the “Code”) authorizes an election by the Fund to deduct as expenses intangible drilling and development costs incurred in connection with oil and natural gas properties at the time such costs are incurred in accordance with the Fund’s method of accounting, provided that the costs are not more than would be incurred in an arm’s length transaction with an unrelated drilling contractor. Such costs include, for example, amounts paid for labor, fuel, wages, repairs, supplies and hauling necessary to the drilling of the project and preparation of the project for production. Generally, this election applies to items that in themselves do not have salvage value. Alternatively, each Fund shareholder may elect to capitalize their share of the intangible drilling and development costs and amortize them ratably over a 60-month period.
The Fund may enter into “carried interest” arrangements whereby the Fund would purchase interests in certain leases and agree to pay a disproportionate part of the costs of drilling the first project thereon. In such situations, the party who is paying more than their share of costs of drilling may not deduct all such costs as intangible drilling and development costs unless their percentage of ownership of the lease is not reduced before they have recovered from the first production of the project an amount equal to the cost they incurred in drilling, completing, equipping and operating the project. The Fund may not have this right in certain of the transactions of this type in which it may engage. If circumstances permit, however, the Fund will adopt the position that all of the intangible drilling and development costs incurred are deductible (even though such costs may be disproportionate to its ownership of the lease) on the basis that such arrangements constitute partnerships for federal income tax purposes and that the excess intangible drilling and development costs are specifically allocable to the Fund. There can be no assurance that this position would prevail against challenge by the Internal Revenue Service (“IRS”).
In the case of a shareholder who constitutes an integrated oil company, 30% of the amount otherwise allowable as a deduction for intangible drilling costs under Section 263(c) must be capitalized and deducted ratably over a 60-month period beginning with the month the costs are paid or incurred. This provision does not apply to nonproductive projects. For this purpose, an integrated oil company is generally defined as an individual or entity with retail sales of oil and natural gas aggregating more than $5 million and refining more than 50,000 barrels per day for the taxable year.
To the extent that drilling and development services were performed for the Fund in 2006, amounts incurred pursuant to bona fide arm’s-length drilling contracts and constituting intangible drilling and development costs were deductible by the Fund in 2006. To the extent that such services are performed in 2007, however, the Fund will only be allowed to deduct for the year 2007 amounts that are:
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incurred pursuant to bona fide arm’s-length drilling contracts which provide for absolute noncontingent liability for payment, and
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attributable to wells spud within 90 days after December 31, 2006.
Sections 461(h)(1) and 461(i)(2) of the Code provide, in relevant part:
...in determining whether an amount has been incurred with respect to any item during any taxable year, the all events tests shall not be treated as met any earlier than when economic performance with respect to such item occurs.
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...economic performance with respect to the act of drilling an oil or natural gas well shall be treated as having occurred within a taxable year if drilling of the well commences before the close of the 90th day after the close of a taxable year.
The clear implication of these provisions is that an amount incurred during a taxable year for drilling or completion services which could otherwise be accrued for federal tax purposes will not be disqualified as a deduction merely because the services are performed during the subsequent taxable year (provided that the services commence within the first 90 days of such subsequent year).
Consequently, intangible drilling and development costs meeting the above criteria were deducted by the Fund in 2006 even though a portion of such costs are attributable to services performed during 2007.
Each shareholder, however, may deduct their share of amounts paid in 2006 for services performed in 2007 only to the extent of their cash basis in the Fund as of the end of 2006. For this purpose, a taxpayer’s cash basis in a tax shelter which is taxable as a partnership (such as the Fund) is the taxpayer’s basis in the Fund determined without regard to any amount borrowed by the taxpayer with respect to the Fund which (a) is arranged by the Fund or by any person who participated in the organization, sale or management of the Fund (or any person related to such person within the meaning of Section 461(b)(3)(c)) of the Code,or (b) is secured by any asset of the Fund. Inasmuch as cash basis excludes borrowing arranged by an extremely broad group of persons who could be related to a person who participated in the organization, sale or management of the Fund, it is not possible to express an opinion as to whether each shareholder of the Fund will be allowed to deduct their allocable share of any prepaid drilling expenses to the extent that they exceed their actual cash investment in the Fund.
Depletion Deductions
Subject to the limitations discussed hereafter, the shareholders will be entitled to deduct, as allowances for depletion under Section 611 of the Code, their share of percentage or cost depletion, whichever is greater, for each oil and natural gas producing project owned by the Fund.
Cost depletion is computed by dividing the basis of the project by the estimated recoverable reserves to obtain a unit cost, then multiplying the unit cost by the number of units sold in the current year. Cost depletion cannot exceed the adjusted basis of the project to which it relates. Thus, cost depletion deductions are limited to the capitalized cost of the project, while percentage depletion may be taken as long as the project is producing income. The depletion allowance for oil and natural gas production will be computed separately by each shareholder and not by the Fund. The Fund will allocate to each shareholder their proportionate share of production and the adjusted basis of each Fund project. Each shareholder must keep records of their share of the adjusted basis and any depletion taken on the project and use their adjusted basis in the computation of gain or loss on the disposition of the project by the Fund.
Percentage depletion with respect to production of oil and natural gas is available only to those qualifying for the independent producer’s exemption, and is limited to an average of 1,000 barrels per day of domestic oil production or 6,000,000 cubic feet per day of domestic natural gas production. The applicable rate of percentage depletion on production under the independent producer exemption is 15% of gross income from oil and natural gas sales. The depletion deduction under the independent producer exemption may not exceed 65% of the taxpayer’s taxable income for the year, computed without regard to certain deductions. Any percentage depletion not allowed as a deduction due to the 65% of adjusted taxable income limitation may be carried over to subsequent years subject to the same annual limitation. For a shareholder that is a trust, the 65% limitation shall be computed without deduction for distributions to beneficiaries during the taxable year.
The determination of whether a shareholder will qualify for the independent producer exemption will be made at the shareholder level. A shareholder who qualifies for the exemption, but whose average daily production exceeds the maximum number of barrels on which percentage depletion can be computed for that year, will have to allocate their exemption proportionately among all of the properties in which they have an interest, including those owned by the Fund. In the event percentage depletion is not available, the shareholder would be entitled to utilize cost depletion as discussed above.
The independent producer exemption is not available to a taxpayer who refines more than 50,000 barrels of oil on any one day in a taxable year or who directly or through a related person sells oil or natural gas or any product derived therefrom (i) through a retail outlet operated by them or a related person or (ii) to any person who occupies a retail outlet which is owned and controlled by the taxpayer or a related person. In general, a related person is defined by Section 613A of the Code as a corporation, partnership, estate, or trust in which the taxpayer has a 5% or greater interest. For the purpose of applying this provision: (a) bulk sales of oil or oil and natural gas to commercial or industrial users are excluded from the definition of retail sales; (b) if the taxpayer or a related person does not export any domestic oil or natural gas production during the taxable year or the immediately preceding year, retail sales outside the U.S. are not deemed to be disqualifying sales; and (c) if the taxpayer’s combined receipts from disqualifying sales do not exceed $5.0 million for the taxable year of all retail outlets taken into account for the purpose of applying this restriction, such taxpayer will not be deemed a retailer.
Depreciation
Costs of equipment, such as casing, tubing, tanks, pumping units, pipelines, production platforms and other types of tangible property and equipment generally cannot be deducted currently, but may be eligible for accelerated cost recovery. All or part of the depreciation claimed may be subsequently recaptured upon disposition of the property by the Fund or of a share by any shareholder.
In addition, the Code provides for certain uniform capitalization rules which could result in the capitalization rather than deduction of Fund management fee and administration costs.
ITEM 1A.
ITEM 1A. RISK FACTORS
In addition to the other information set forth elsewhere in this report, you should carefully consider the following factors when evaluating the Fund:
RISKS INHERENT IN THE FUND’S BUSINESS
The Fund’s exploration and production activities are subject to risks that it cannot control and it may have insufficient insurance to cover these risks. To the extent the fund is not covered by insurance, it could incur losses and liabilities which could reduce revenues, increase costs or eliminate dollars available for future exploration and development projects.
Costs of drilling, completing and operating projects are often uncertain and drilling operations may be curtailed, delayed or canceled as a result of a variety of factors including:
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Fires, explosions, blowouts and cratering
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Equipment failures, casing collapse, pipe and cement failures
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Marine risks such as capsizing or collisions
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Adverse weather conditions, including hurricanes
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Shortages or delays in the delivery of equipment
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Acts of terrorism
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Environmental hazards
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Pipeline ruptures and discharge of toxic gases
Many of the above-mentioned risks could result in damage to life and / or property, or cause sustained interruption of production.
Insurance to cover certain of these risks may be prohibitively expensive or unavailable, particularly with respect to acts of terrorism. Additionally, insurance coverage may not be sufficient to cover certain catastrophic events. The Fund could be liable for costs in excess of its insurance coverage.
In addition, it is significantly less costly for insurance to be acquired and maintained by the Manager as a package that covers all of the oil and natural gas projects under its management. The majority of these projects are owned by other entities that are likewise managed by Ridgewood Energy. As a result, given insurance limits, if significant damage occurs to other projects owned by other investment vehicles managed by the Manager in any given year, the amount of insurance available to cover any damage to the Fund’s projects could be significantly reduced.
The Fund’s investment activities may result in unsuccessful projects.
There is always significant risk that a project will not have commercially productive oil or natural gas reservoirs. In other words, the well may be a dry-hole. The successful acquisition of producing properties requires assessment of reserves, seismic and other engineering information, future commodity prices, operating costs and potential environmental liabilities. The Fund’s assessment of these factors may not be successful.
The Fund has already experienced dry-holes and further dry-holes will adversely impact the Fund’s profitability and returns.
The Fund has already had five dry holes. Cumulative dry-hole costs to the Fund for the year ended December 31, 2006, the period ended December, 31, 2005 and the period March 21, 2005 (Inception) through December 31, 2006 totaled approximately $48.1 million, $0.6 million and $48.7 million, respectively. With respect to these dry-holes, the Fund does not anticipate incurring any significant future costs as all the wells have been plugged and abandoned. However, given that the Fund’s capital is limited to the amount it raised (less various fees) in the offering of its shares, the aforementioned dry-holes, and every other dry-hole that the Fund may experience, has the effect of reducing the limited capital available for investment. In addition, because dry-holes reduce the capital available for additional investment, a significant number of dry-holes will reduce the returns of the Fund because the remaining capital, even if invested in successful wells, may not generate enough cash for investors to see significant or positive returns on their investments.
The actual costs to drill a well, or dry-hole costs, can materially exceed estimates due to cost overruns. In such event, the risks associated with the well increase.
When the Fund invests in a particular project the operator will generally provide what is referred to as an “AFE” or “authorization for expenditures”. The AFE’s for a particular project generally represent the Dry-hole costs associated with that project and not the development costs should the project be successful. Dry-hole costs are generally an estimate made by the Operator after considering numerous factors, such as water depth, drilling depth, seismic information, and equipment costs and availability. Notwithstanding the Operator’s best estimates of drilling cost, the actual drilling of the well may result in cost overruns that materially increase the costs of the drilling the project. The cost overruns can occur for any number of reasons including but not limited to, weather delays, equipment unavailability, pressure or irregularities in formations and other risks identified herein. The Fund has little choice but to pay these costs overruns or potentially lose its right to participate in the well by going “non-consent”. Significant cost overruns will increase the risk associated with the project as additional Fund capital that would otherwise be used for other projects is being allocated to cover the overruns.
The Fund’s reserve estimates are inherently uncertain and may be inaccurate and if so, may adversely affect the Fund’s revenue and profitability.
Once reserves are proved, there are many uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of development expenditures, including many factors beyond the Fund’s control. Estimates of reserves by necessity are projections based on engineering and geological data, including but not limited to volumetrics, reservoir size, reservoir characteristics, the projection of future rates of production and the timing of future expenditures. The accuracy of any reserve estimate is a function of the amount and quality of available data and of engineering and geological interpretation and judgment. As a result, estimates of different engineers normally vary and may not be accurate. Development of the Fund’s reserves may not occur as scheduled and the actual results may not be as estimated.
In addition, results of drilling, testing and production subsequent to the date of an estimate may justify revision of such reserve and cost estimate upward or downward. Accordingly, reserve estimates are often different, sometimes materially, from the quantities ultimately recovered. The Manager reviews the reserve estimates provided by the operators of projects in which the Fund participates and may retain independent reserve engineers to review such reserve estimates and/or conduct an independent review, as appropriate. Future performance that deviates significantly from reserve estimates could have a material effect (positive or negative) on the Fund’s operations, business and prospects, as well as on the amounts of such reserves.
Moreover, the Fund’s estimated or proved oil and natural gas reserves and the estimated future net revenues from such reserves will be based upon various assumptions, including available geological, geophysical, engineering and production data. The process also requires certain economic assumptions such as oil and natural gas prices, drilling and operating expenses, capital expenditures, and availability of funds. As a result, the Fund is required to make assumptions and judgments, all of which can be wrong or inaccurate. Thus, these estimates are inherently imprecise and the quality and reliability of this information can vary, perhaps significantly, from actual results.
The prices that the Fund may receive for its oil or natural gas are highly volatile and unpredictable and may not be sufficient to generate enough cash flow to make distributions to investors.
When oil and natural gas production begins, the Fund’s revenue, profitability and cash flow are highly dependent on the prices of oil and natural gas. Historically, the markets for crude oil and natural gas have been extremely volatile, and they are likely to continue to be volatile in the future. This volatility is caused by numerous factors and market conditions. Therefore, it is impossible to predict the future price of crude oil and natural gas with any certainty. Low commodity prices could have an adverse affect on the Fund’s future profitability and, in such an event, the Fund may be required by accounting rules to write down the carrying value of the Fund’s projects.
The Fund has not engaged in any price risk management programs or hedges to date and does not anticipate engaging in those types of transactions in the future.
The Fund may be required to take writedowns if natural gas and oil prices decline.
The Fund may be required under successful efforts accounting rules to write down the carrying value of its properties if natural gas and oil prices decline or if the Fund has substantial downward adjustments to its estimated proved reserves, increases in the Fund’s estimates of development costs or deterioration in the Fund’s exploration results.
The Fund utilizes the successful efforts method of accounting for natural gas and oil exploration and development activities. If the net book value of its natural gas and oil properties exceeds its undiscounted cash flows, principles generally accepted in the United States (“GAAP”) requires the Fund to impair or “writedown” the book value of its natural gas and oil properties. Depending on the magnitude of any future impairment, a writedown could significantly reduce the Fund’s income, or produce a loss. As impairment computations involve the prevailing price on the last day of the quarter, it is impossible to predict the timing and magnitude of any future impairment. To the extent the Fund’s finding and development costs continue to increase as the Fund expects, the Fund will become more susceptible to impairments in low price environments.
The unavailability and cost of needed equipment may adversely affect the Fund’s profitability and operations.
As a result of the increase in oil and natural gas prices, drilling activity in the Gulf of Mexico has increased significantly. Drilling rigs and other equipment have become harder to obtain and more costly to acquire, especially if weather occurrences, such as hurricanes, occur with frequency in the Gulf of Mexico. These circumstances could have a negative impact on the Fund’s operations.
The Fund has a limited amount of capital available to invest and therefore has limited ability to invest in many more projects. Further, each unsuccessful project erodes the Fund’s limited capital.
The capital raised by the Fund in its private placement is more than likely all the capital it will be able to obtain for investments in projects. Given its structure, obtaining traditional financing from public markets is unlikely and it is not practical to assume the Fund can raise additional funds through a supplemental offering or through debt financing. As a result, it has little, if any, ability to grow its business beyond its current projects or through investing its available cash in new projects. In any event, the number of projects in which the Fund can invest will naturally be limited and each unsuccessful project the Fund experiences, if any, will not only reduce its ability to generate revenue, but also exhaust its limited supply of capital.
The Fund may incur costs to comply with the many environmental and other governmental regulations that apply to its operations, which may adversely impact its ability to generate cash flow for distributions.
The oil and natural gas industry, in general, and offshore activities, in particular, are subject to numerous governmental laws and regulations which may affect the ongoing and future operational decisions and financial results of the Fund. United States legislation affecting the oil and natural gas industry is under constant review for amendment and expansion. Also, numerous departments and agencies, both federal and state, are authorized by statute to issue and have issued rules and regulations which, among other things, require permits for the drilling of projects, impose construction, abandonment and remediation requirements, prevent the waste of natural gas and liquid hydrocarbons through restrictions on flaring, require drilling bonds and regulate environmental and safety matters. Additionally, governmental regulations may also impact the demand for oil and natural gas, which could adversely affect the price at which oil and natural gas is sold. The regulatory burden on the oil and natural gas industry increases its cost of doing business and, subsequently, affects its profitability. Finally, as additional legislation or amendments may be enacted in the future, the Fund is unable to predict the ultimate cost of compliance.
The Fund relies on third parties to operate, manage and maintain its projects over which it has limited control. Therefore, decisions may be made by these third parties that adversely affect the Fund or its operations.
Neither the Fund nor the Manager currently own or have any plans to acquire drilling or production equipment nor does the Fund or Manager maintain a staff of technical employees required for on-site drilling operations. Therefore, the Fund must rely on unrelated third party operators to oversee and/or perform all drilling, completion and ongoing maintenance and production activities for the projects in which it participates. For example, lack of operating control could lead to higher operating costs, drilling delays, increased rig costs or labor issues. As such, the Fund has little or no control over the day-to-day operations of these projects. However, the Fund has acquired and will continue to seek projects, to the extent of its available capital, in which the operators have significant resources, are experienced in offshore operations and have a long term presence and track record of success in the Gulf of Mexico.
The Fund owns projects jointly with other companies over whom it has no control and who may influence the manner in which the project is operated.
The Fund participates in projects as a working interest owner along with other unrelated third party entities, including the operator. While the Manager may monitor and participate in decisions affecting exploration and development of the leases or projects in which the Fund participates, other decisions with respect to lease exploration and development activities may be controlled by the other participants and could be unfavorable to the Fund. Finally, the Fund could be held liable for the joint activity obligations or tortuous actions of the operator or other working interest owners. If the Fund’s co-participants fail to pay their portion of the drilling and completion or ongoing maintenance costs, the project may lack sufficient funds to perform such work. As a result, the Fund, as well as the remaining working interest owners, may be required to pay such additional sums in order to complete drilling or development of the project.
The Fund faces competition from larger entities with greater capital resources that could limit the number and availability of economically attractive projects.
As an independent oil and natural gas producer, the Fund faces competition in all aspects of its business. Many of its competitors are large, well-established companies that have significantly larger staffs and have greater capital resources. These companies may be able to pay more for a project or sustain losses for a longer period of time than the Fund.
The Fund maintains a salvage fund that may be insufficient to cover such salvage costs, in which event the Fund could be liable for any excess.
The Fund has created a salvage fund to cover certain anticipated salvage costs associated with its projects. The salvage fund may not have sufficient assets to meet salvage costs and thus the Fund may be liable for its proportionate share of the unfunded expenses if in excess of the salvage fund.
The Fund’s projects and operations are located exclusively in the Gulf of Mexico and are subject to interruptions and damage from hurricanes that could adversely affect the Fund’s cash flow due to such exclusivity.
The Fund has invested in projects exclusively within the Gulf of Mexico and any future investments by the Fund in projects will likewise be located in the Gulf of Mexico. As a result of such exclusivity in location, the Fund is particularly susceptible to hurricane risks in that the impact to the Fund’s operations of a severe storm or storms could be more pronounced and severe (depending on the storm, its path, and resulting damage) because the Fund does not have projects in other areas of the globe to offset such damage. If, for example, the Fund had projects in areas not affected by hurricanes those projects could still operate and generate cash flow during the interruptions in operations in the Gulf of Mexico. As it is, a hurricane, or series of hurricanes in a season, has the potential of interrupting all of the Fund’s operations, at least for some period of time, if all of the Fund’s projects were affected. In such event, the Fund would not have sufficient cash flow to make distributions to investors and, additionally and as disclosed earlier, insurance may not be sufficient to cover all of the damages caused by the hurricanes.
The Fund’s internal control over financial reporting could be adversely affected by material weaknesses in the Fund’s internal controls.
In the Fund’s Form 10-A for the year ended December 31, 2005, filed November 13, 2006, the Fund reported material weaknesses with respect to its lack of technical accounting resources on staff and the need for additional training, formalized policies and procedures on documenting financial controls. These control deficiencies resulted in the restatement of the Fund’s Form 10. As a result of these material weaknesses, the Fund concluded in its Form 10-A that its control over financial reporting was not effective as of the end of the periods covered by the reports. The Fund has remediated these material weaknesses. Investors, however, should be aware that the Fund cannot guarantee that future material weaknesses will not develop or be identified. Any new
material weaknesses identified could harm the Fund’s operating results, cause the Fund to fail to meet its reporting obligations or result in material misstatements in its financial statements. Any such failure also could affect the ability of management to certify that the Fund’s internal controls are effective when it provides an assessment of the Fund’s internal control over financial reporting.
RISKS RELATED TO THE NATURE OF THE FUND’S SHARES
The Fund’s shares have severe restrictions on transferability and liquidity and shareholders are required to hold the shares indefinitely.
The Fund’s shares are illiquid investments. There is currently no market for these shares and one is not likely to develop. Because there will be a limited number of persons who purchase shares and because there are significant restrictions on the transferability of such shares under the Fund’s LLC Agreement and under applicable federal and state securities laws, it is expected that no public market will develop. Moreover, neither the Fund nor the Manager will provide any market for the shares. Shareholders are generally prohibited from selling or transferring their shares except in the circumstances permitted under the LLC Agreement and applicable law, and all such sales or transfers require the Fund’s consent, which it may withhold at its sole discretion. Accordingly, shareholders have no assurance that an investment can be transferred and must be prepared to bear the economic risk of the investment indefinitely.
Shareholders are not permitted to participate in the Fund’s management or operations and must rely exclusively on the Manager.
Shareholders have no right, power or authority to participate in the Fund’s management or decision making or in the management of the Fund’s projects. The Manager has the exclusive right to manage, control and operate the Fund’s affairs and business and to make all decisions relating to its operation.
The Fund’s assets are illiquid and therefore, cash flow for distributions, if any, must come from operations and not from dispositions of assets.
The Fund’s interest in projects is illiquid. It does not anticipate selling any interests in the projects, or any part thereof. Even if it elected to sell, it is likely that there will be little or no market for these assets. However, if the Fund were to attempt to sell any such interest, a successful sale would depend upon, among other things, the operating history and prospects for the project or interest being sold, proven oil and natural gas reserves, the number of potential purchasers and the economics of any bids made by them and the current economics of the oil and natural gas market. In addition, any such sale may result in adverse tax consequences to the shareholders. The Manager has full discretion to determine whether any project, or any partial interest, should be sold and the terms and conditions under which such project would be sold. Consequently, shareholders will depend on the Manager for the decision to sell all or a portion of a project, or retain it, for the benefit of the shareholders and for negotiating and completing the sale transaction.
The Fund indemnifies its officers, as well as the Manager and its employees, for certain actions taken on its behalf and therefore Fund assets may be used to reimburse such officers.
The LLC Agreement provides that the Fund’s officers and agents, the Manager, the affiliates of the Manager and their respective directors, officers and agents when acting on behalf of the Manager or its affiliates on the Fund’s behalf, will be indemnified and held harmless by the shareholders from any and all claims rising out of its management, except for claims arising out of bad faith, gross negligence or willful misconduct or a breach of the LLC Agreement. Therefore, the Fund may have difficulty sustaining an action against the Manager, or its affiliates and their officers based on breach of fiduciary responsibility or other obligations to the shareholders.
The Manager will receive a management fee regardless of the Fund’s profitability and also receives cash distributions.
The Manager is entitled to receive an annual management fee from the Fund regardless of whether the Fund is profitable in that year. The annual fee, payable monthly, is equal to 2.5% of total capital contributed by shareholders. For the year ended December 31, 2006, the period March 21, 2005 (Inception) through December 31, 2005, and the period March 21, 2005 (Inception) through December 31, 2006, the management fee was $3.5 million, $1.9 million and $5.3 million, respectively. Effective January 1, 2007, the Manager has changed its policy regarding the annual management fee. Commencing in January 2007, the management fee payable will be equal to 2.5% of the total shareholder capital contributions, net of dry-hole expenses incurred by the Fund. For the Fund, the management fee will be reduced
by $0.1 million per month, based upon dry-hole expenses of $48.7 million from inception through December 31, 2006.
In addition to its annual management fee, the Manager, as compensation for its management services, will receive 15% of the Fund’s cash distributions to shareholders although the Manager has not contributed any cash to the Fund. Accordingly, shareholders contribute all of the cash utilized for the Fund’s investments and activities. If the Fund’s projects are unsuccessful, the shareholders lose 100% of their investment while the Manager, not having contributed any capital, will lose nothing.
Inherent in these fee arrangements is the possibility of conflicts between the Fund’s interests and the best interests of the Manager. The Manager may have incentive to act in its best interests rather than in the Fund’s best interest by taking actions designed to increase its fees but with significant risk to the Fund. Any such conflict of interests will be addressed by the Manager as described in the risk factor below headed “Because the Manager manages many other oil and natural gas funds, it may have conflicts of interest in its management of the Fund’s operations”.
None of the compensation to be received by the Manager has been derived as a result of arm’s length negotiations.
Under Delaware law, shareholders have limited access to information and therefore, the Fund and Manager can restrict certain information, including shareholder information, making communications with other shareholders difficult. As a result, the information you receive about the Fund and its activities will be limited to what the Manager chooses to provide.
Delaware law permits Delaware limited liability companies to restrict access to certain information provided that such restricted access is set forth in the LLC Agreement. The Fund’s LLC Agreement contains provisions that limit shareholder access to certain sensitive or confidential information such as trade secrets, agreements or confidential or proprietary information. Moreover, shareholder access to information regarding other shareholders is likewise limited and the Fund may refuse to give shareholder information, such as name and address of other shareholders, which could make it difficult for a shareholder to contact other shareholders. Nevertheless, shareholders do have access to tax, other financial information or any other reasonable information regarding Fund operations.
Cash distributions are not guaranteed and may be less than anticipated or estimated.
Distributions depend primarily on available cash from oil and natural gas operations. At times, distributions may be delayed to repay the principal and interest on fund borrowings, if any, or to fund other costs, although the Fund does not anticipate such borrowings. The Fund’s taxable income will be taxable to the shareholders in the year earned, even if cash is not distributed.
Because the Manager manages many other oil and natural gas funds, it may have conflicts of interest in its management of the Fund’s operations.
Shareholders will not be involved in the management of the Fund’s operations. Accordingly, they must rely on the Manager’s judgment in such matters. Inherent with the exercise of its judgment, the Manager will be faced with conflicts of interest. While neither the Fund nor the Manager have specific procedures in place in the event of any such conflicting responsibilities, the Manager recognizes that it has fiduciary duties to the Fund in connection with its position and responsibilities as Manager and it intends to abide by such fiduciary responsibilities in performing its duties. Therefore, the Manager and its affiliates will attempt, in good faith, to resolve all conflicts of interest in a fair and equitable manner with respect to all parties affected by any such conflicts of interest. The Manager is not liable to the Fund for how conflicts of interest are resolved unless it has acted in bad faith, or engaged in gross negligence or willful misconduct.
TAX RISKS ASSOCIATED WITH AN INVESTMENT IN SHARES
The Fund is organized as a Delaware limited liability company and the Manager intends to qualify the Fund as a partnership for federal tax purposes. The principal tax risks to shareholders are that:
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The Fund may recognize income taxable to the shareholders but may not distribute enough cash to cover the income taxes on the Fund’s taxable income.
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The allocation of Fund items of income, gain, loss, and deduction may not be recognized for federal income tax purposes.
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All or a portion of the Fund’s expenses could be considered either investment expenses (which would be deductible by a shareholder only to the extent the aggregate of such expenses exceeded 2% of such shareholder’s adjusted gross income) or as nondeductible items that must be capitalized.
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All or a substantial portion of the Fund’s income could be deemed to constitute unrelated business taxable income, such that tax-exempt shareholders could be subject to tax on their respective portions of such income.
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If any Fund income is deemed to be unrelated business taxable income, a shareholder that is a charitable remainder trust could have all of its income from any source deemed to be taxable.
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All or a portion of the losses, if any, allocated to the shareholders will be passive losses and thus deductible by the shareholder only to the extent of passive income.
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The shareholders could have capital losses in excess of the amount that is allowable as a deduction in a particular year.
Although the Fund has obtained an opinion of counsel regarding the matters described in the preceding paragraph, it will not obtain a ruling from the IRS as to any aspect of the Fund’s tax status. The tax consequences of investing in the Fund could be altered at any time by legislative, judicial, or administrative action.
If the IRS audits the Fund, it could require investors to amend or adjust their tax returns of result in an audit of their tax.
The IRS may audit the Fund’s tax returns. Any audit issues will be resolved at the Fund level by the Manager. If adjustments are made by the IRS, corresponding adjustments will be required to be made to the federal income tax returns of the shareholders, which may require payment of additional taxes, interest, and penalties. An audit of the Fund’s tax return may result in the examination and audit of a shareholder’s return that otherwise might not have occurred, and such audit may result in adjustments to items in the shareholder’s return that are unrelated to the Fund operations. Each shareholder bears the expenses associated with an audit of that shareholder’s return.
In the event that an audit of the Fund by the IRS results in adjustments to the tax liability of a shareholder, such shareholder will be subject to interest on the underpayment and may be subject to substantial penalties. In addition, a number of substantial penalties could potentially be asserted by the IRS on any such deficiencies.
The tax treatment of the Fund can not be guaranteed for the life of the Fund. Changes in law or regulations may adversely affect any such tax treatment.
Deductions, credits or other tax consequences may not be available to shareholders. Legislative or administrative changes or court decisions could be forthcoming which would significantly change the statements herein. In some instances, these changes could have substantial effect on the tax aspects of the Fund. Any future legislative changes may or may not be retroactive with respect to transactions prior to the effective date of such changes. Bills have been introduced in Congress in the past and may be introduced in the future which, if enacted, would adversely affect some of the tax consequences of the Fund.
ITEM 1B.
ITEM 1B. UNRESOLVED STAFF COMMENTS
Not applicable.
ITEM 2.
ITEM 2. PROPERTIES
The information regarding the Fund’s properties that is contained in Item 1. Business of this Annual Report on Form 10-K is incorporated herein by reference.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS
On August 16, 2006, the Manager of the Fund filed a lawsuit against the former independent registered public accounting firm for the Fund, Perelson Weiner (“PW”), in New Jersey Superior Court, captioned Ridgewood Energy Corporation v. Perelson Weiner, LLP, Docket No. L-6092-06. The suit alleged professional malpractice and breach of contract in connection with audit and accounting services performed for the Fund by PW. Thereafter, PW filed a counterclaim against the Manager on October 20, 2006, alleging breach of contract due to unpaid invoices in the amount of $326,554. Discovery is ongoing and no trial date has been set.
ITEM 4.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
PART II.
ITEM 5.
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED SECURITY HOLDER MATTERS, AND ISSUER PURCHASES OF EQUITY SECURITIES
Market Price of Common Units, Distributions and Related Shareholder Matters
There is currently no established public trading market for the shares of membership interest of the Fund. The Fund is not currently offering or proposing to offer any shares for sale to the public. There are no outstanding options or warrants to purchase, or securities convertible into shares and the Fund does not have any equity-based compensation plans. The shares are restricted as to resale. Shareholders wishing to transfer shares should also consider the applicability of state securities laws. The shares have not been registered under the Securities Act of 1933, as amended (the “Securities Act”) or under any other similar law of any state (except for certain registrations that do not permit free resale) in reliance upon what the Fund believes to be exemptions from the registration requirements contained therein. Because the shares have not been registered, they are restricted securities as defined in Rule 144 under the Securities Act. As of March 2, 2007, no shares of the Fund could be sold pursuant to Rule 144. The Fund has not agreed to register any shares under the Securities Act for sale by security holders.
As of March 2, 2007, there were approximately 1,507 holders of Fund shares.
To date, the Fund has not declared or paid cash dividends to the Fund shareholders. Ridgewood Energy Corporation, the Manager, may distribute dividends from available cash from operations as defined in the LLC Agreement.
Participation in Costs and Revenues
The Fund’s investment objective is primarily to generate current cash flow for distribution to shareholders from the operation of the Fund projects to the extent that such distributions are consistent with the reserve requirements and operational needs of those projects. If the Fund does make distributions, this section describes how the Fund will:
•
determine what cash flow will be available for distributions to Investors,
•
distribute available cash flow,
•
give the Manager a share of cash flow, if available,
•
handle returns of capital contributions,
•
allocate income and deductions for tax purposes, and
•
maintain capital accounts for Investors.
Available cash determines what amounts in cash the Fund will be able to distribute in cash to Investors. There are three types of available cash as follows:
“Available Cash from Capital Transactions” is total cash received by the Fund from the proceeds of the sale or other disposition of the Fund’s property (including items such as insurance proceeds, refinancing proceeds, condemnation proceeds and other amounts received out of the ordinary course of business), but excluding dispositions of temporary investments of the Fund.
“Available Cash from Temporary Investments” is cash from short-term investments (i.e. U.S. Treasury Bills, certificates of deposits) and other interest bearing cash accounts.
“Available Cash from Operations” is all other available cash.
There is no fixed requirement to distribute available cash; instead, it will be distributed to shareholders to the extent and at such times as the Manager believes is advisable. Once the amount and timing of a distribution is determined, it shall be made to shareholders as described below.
Distributions from Operations
At various times during a calendar year, the Fund will determine whether there is enough Available Cash from Operations for a distribution to shareholders. The amount of Available Cash from Operations determined to be available, if any, will be distributed to the shareholders. At all times, the Manager will be entitled to 15% and shareholders will be entitled to 85% of the Available Cash from Operations distributed.
Distributions of Available Cash from Capital Transactions
Available Cash from Capital Transactions that the Fund decides to distribute will be paid as follows:
•
Before shareholders have received total distributions equal to their capital contributions, 99% of Available Cash from Capital Transactions will be distributed to shareholders and 1% to the Manager.
•
After shareholders have received total distributions equal to their capital contributions, 85% of Available Cash from Capital Transactions will be distributed to Investors and 15% to the Manager.
General Distribution Provisions
Distributions to shareholders under the foregoing provisions will be apportioned among them in proportion to their ownership of their shares. The Manager has the sole discretion to determine the amount and frequency of any distributions; provided, however, that a distribution may not be made selectively to one shareholder or group of shareholders but must be made ratably to all shareholders entitled to that type of distribution at that time. The Manager in its discretion nevertheless may credit select persons with a portion of its compensation from the Fund or distributions otherwise payable to the Manager.
Because distributions, if any, will be dependent upon the earnings and financial condition of the Fund, its anticipated obligations, the Manager’s discretion and other factors, there can be no assurance as to the frequency or amounts of any distributions that the Fund may make.
Return of Capital Contributions
If the Fund for any reason at any time does not find it necessary or appropriate to retain or expend all capital contributions, in its sole discretion it may return any or all of such excess capital contributions ratably to shareholders. A return of capital contributions is not treated as a distribution. The Fund and the Manager will not be required to return any fees deducted from the original capital contribution or any costs and expenses incurred and paid by the Fund. Any such return of capital will decrease the shareholders’ capital contributions.
Capital Accounts and Allocations
The tax consequences of an investment in the Fund to a shareholder in the event of dissolution depend on the shareholder’s capital account and on the allocations of profits and losses to that account. The Fund’s taxable profits or losses are allocated among the shareholders as described below and profits or losses are added to or subtracted from the shareholders’ capital accounts. The amounts allocated to each shareholder will generally not be equal to the distributions the shareholder receives until final liquidating distributions are made to shareholders.
The Fund does not currently anticipate that any contributions or distributions of property will be made. Certain additional adjustments to capital accounts will be made if necessary to account for the effects of non-recourse debt incurred by the Fund, if any, or contributions of property, if any, to the Fund.
During the period from March 21, 2005 until December 31, 2005, the Fund issued an aggregate 933.06 shares for gross proceeds of approximately $138.3 million. All sales of unregistered securities relied on Section 4(2) of the Securities Act and Rule 506 of Regulation D promulgated thereunder. All of the sales were made without the use of an underwriter. All purchasers of shares represented and warranted to the Fund that they were accredited investors as defined in Rule 501(a) under the Securities Act and that the shares were being purchased for investment and not for resale.
From the amount raised, approximately $15.9 million was disbursed for commissions and legal syndication fees. Additionally, approximately $6.3 million was paid as an investment fee to Ridgewood Energy Corporation, the Manager, for the investigation and evaluation of investment property prospects. Remaining funds are expected to be used for exploration and development activities of oil and gas properties as well as the operation of the Fund.
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA
The following table summarizes certain selected financial data at December 31, 2006 and 2005, and for the year ended December 31, 2006, the period March 21, 2005 (Inception) through December 31, 2005 and the period March 21, 2005 (Inception) through December 31, 2006, and is derived from the audited financial statements included herein. Although the date of formation of the Fund is March 21, 2005, the Fund did not begin business activities until May 16, 2005 when it began its private offering of shares. There were no business activities prior to May 16, 2005. The information summarized below should be read in conjunction with Management’s Discussion and Analysis of Financial Condition and Results of Operations and the Fund’s audited Financial Statements and related Notes.
ITEM 7.
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Overview of the Fund’s Business
The Fund (an exploratory stage enterprise) is an independent oil and natural gas producer. The Fund’s primary investment objective is to generate cash flow for distribution to its shareholders through participation in oil and natural gas exploration and development projects in the Gulf of Mexico. The Fund began its operations by offering its shares in a private offering on May 16, 2005. As a result of such offering, the Fund raised approximately $138.3 million through the sale of 933.0600 shares of LLC membership interests. After the payment of approximately $22.2 million in offering fees, commissions and investment fees to Ridgewood Energy Corporation, affiliates and broker-dealers, the Fund retained approximately $116.1 million available for investment. Investment fees represent a one time fee of 4.5% of initial capital contributions. The fee is payable for the service of investigating and evaluating investment opportunities and affecting transactions when the capital contributions are made. Since inception in March 2005, the Fund has acquired an interest in six offshore projects and has participated in the drilling of five wells. During 2006 the Fund was notified by the project operators that three of the five projects resulted in dry-holes. In January 2007, the Fund was notified by the project operators that two other projects resulted in dry-holes. See “Subsequent Events” below. West Cameron 593 was determined to be a successful property in September 2006 and the Fund anticipates putting this well on production during spring 2007. See also Items 1. and 2. “Business and Properties”.
The Manager performs certain duties on the Fund’s behalf including the evaluation of potential projects for investment and on-going administrative and advisory services associated with these projects. The Fund does not currently, nor is there any plan to operate any project in which the Fund participates. The Manager enters into operating agreements with third-party operators for the management of all exploration, development and producing operations, as appropriate. As compensation for the above duties, the Manager is paid a one time investment fee (4.5%) for the evaluation of projects on the Fund’s behalf and an annual management fee (2.5%), payable monthly, for ongoing administrative and advisory duties as well as reimbursement of expenses. The Manager also participates in distributions as additional compensation for its administrative and management services. See also Item 1. “Business”.
The following review of operations for the year ended December 31, 2006, the period March 21, 2005 (Inception) through December 31, 2005 and the period March 21, 2005 (Inception) through December 31, 2006 should be read in conjunction with the Fund’s financial statements and the notes thereto.
Subsequent Events
Management Fee
Effective January 1, 2007, the Manager has changed its policy regarding the annual management fee. Commencing in January 2007, the management fee payable will be equal to 2.5% of the total shareholder capital contributions, net of dry-hole expenses incurred by the Fund. For the Fund, the management fee will be reduced by $0.1 million per month, based upon dry-hole expenses of $48.7 million from inception to date.
Green Canyon 246
On January 24, 2007, the Fund was informed by its operator, Woodside, that the exploratory well being drilled by Woodside in the Green Canyon 246 lease block did not have commercially productive quantities of either oil or natural gas and had therefore been deemed an unsuccessful well or dry-hole. The Fund owns an 8.3% working interest in Green Canyon 246. Dry-hole costs related to Green Canyon 246, including plug and abandonment expenses, incurred by the Fund for the year ended December 31, 2006, the period March 21, 2005 (Inception) through December 31, 2005, and for the period March 21, 2005 (Inception) through December 31, 2006 were approximately $4.8 million, nil and $4.8 million, respectively. The Fund incurred additional dry-hole costs related to Green Canyon 246 of $1.4 million during 2007.
South Timbalier 135/136
On January 24, 2007, the Fund was informed by its operator, Chevron, that the exploratory well being drilled by Chevron in the South Timbalier 135/136 lease block did not have commercially productive quantities of either oil or natural gas and has therefore been deemed an unsuccessful well or dry-hole. The Fund owns a 10% working interest in South Timbalier 135/136. Dry-hole costs related to South Timbalier, including plug and abandonment expenses, incurred by the Fund for the year ended December 31, 2006, the period March 21, 2005 (Inception) through December 31, 2005, and for the period March 21, 2005 (Inception) through December 31, 2006 were approximately $5.2 million, nil and $5.2 million, respectively. The Fund incurred additional dry-hole costs related to South Timbalier 135/136 of $1.6 million during 2007.
Critical Accounting Estimates
The discussion and analysis of the Fund’s financial condition and results of operations are based upon its consolidated financial statements, which have been prepared in conformity with U.S. generally accepted accounting principles, or GAAP. In preparing these financial statements, the Fund is required to make certain estimates, judgments and assumptions. These estimates, judgments and assumptions affect the reported amounts of the Fund’s assets and liabilities, including the disclosure of contingent assets and liabilities, at the date of the financial statements and the reported amounts of the Fund’s revenues and expenses during the periods presented. The Fund evaluates these estimates and assumptions on an ongoing basis. The Fund bases its estimates and assumptions on historical experience and on various other factors that the Fund believes to be reasonable at the time the estimates and assumptions are made. However, future events and their effects cannot be predicted with absolute certainty. Therefore, the determination of estimates requires the exercise of judgment. Actual results inevitably will differ from these estimates and assumptions under different circumstances or conditions, and such differences may be material to the financial statements. See Note 2 - Summary of Significant Accounting Policies of Item 8. contained in this Form 10-K for a discussion of the Fund’s significant accounting policies.
Accounting for Exploration and Development Costs
Exploration and production activities are accounted for using the successful efforts method. Costs of acquiring unproved and proved oil and gas leasehold acreage, including lease bonuses, brokers’ fees and other related costs, are capitalized. Annual lease rentals, exploration expenses and exploratory dry-hole costs are expensed as incurred. Costs of drilling and equipping productive wells, including development dry holes, and related production facilities are capitalized.
The costs of exploratory wells that find oil and gas reserves are capitalized pending determination of whether proved reserves have been found. Exploratory drilling costs remain capitalized after drilling is completed if (1) the well has found a sufficient quantity of reserves to justify completion as a producing well and (2) sufficient progress is being made in assessing the reserves and the economic and operating viability of the project. If either of those criteria is not met, or if there is substantial doubt about the economic or operational viability of the project, the capitalized well costs are charged to expense. Indicators of sufficient progress in assessing reserves and the economic and operating viability of a project include: commitment of project personnel, active negotiations for sales contracts with customers, negotiations with governments, operators and contractors and firm plans for additional drilling and other factors.
Proved Reserves
The Fund’s reserves are fully engineered on an annual basis by independent petroleum engineers. The Fund’s estimates of proved reserves are based on the quantities of natural gas and oil which geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under existing economic and operating conditions. However, there are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future revenues, rates of production and timing of development expenditures, including many factors beyond the Fund’s control. The estimation process is very complex and relies on assumptions and subjective interpretations of available geologic, geophysical, engineering and production data and the accuracy of reserve estimates is a function of the quality and quantity of available data, engineering and geological interpretation, and judgment. In addition, as a result of volatility and changing market conditions, commodity prices and future development costs will change from period to period, causing estimates of proved reserves to change, as well as causing estimates of future net revenues to change. For the years ended December 31, 2006 and 2005, the Fund did not have any proved reserves. Estimates of proved reserves are key components of the Fund’s most significant financial estimates involving the Fund’s rate for recording depreciation, depletion and amortization.
Unproved Properties
Unproved properties is comprised of capital costs incurred for undeveloped acreage, wells and production facilities in progress, wells pending determination and related capitalized interest. These costs are initially excluded from the depletion base until the outcome of the project has been determined, or generally, until it is known whether proved reserves will or will not be assigned to the property. The Fund assesses all items in its unevaluated property balance on an ongoing basis for possible impairment or reduction in value. The Fund believes that substantially all of the costs included in its unevaluated property balance will be evaluated in the next two years.
Asset Retirement Obligations
For oil and natural gas properties, there are obligations to perform removal and remediation activities when the properties are retired. When a project reaches drilling depth and is determined to be either proved or dry, a liability is recognized for the fair value of legally required asset retirement obligations once it can be reasonably estimated. The Fund capitalizes the associated asset retirement costs as part of the carrying amount of the long-lived assets. Plug and abandonment costs associated with unsuccessful projects are expensed as dry-hole costs.
Impairment of Long-Lived Assets
The Fund reviews long-lived assets, including oil and gas fields, for impairment whenever events or changes in circumstances indicate that the carrying amounts may not be recovered. Long-lived assets are tested based on identifiable cash flows (the field level for oil and gas assets) and are largely independent of the cash flows of other assets and liabilities. If the carrying amounts of the long-lived assets are not expected to be recovered by undiscounted future net cash flow estimates, the assets are impaired and an impairment loss is recorded. The amount of impairment is based on the estimated fair value of the assets determined by discounting anticipated future net cash flows.
In the case of oil and gas fields, the present value of future net cash flows is based on management’s best estimate of future prices, which is determined with reference to recent historical prices and published forward prices, applied to projected production volumes of individual fields and discounted at a rate commensurate with the risks involved. The projected production volumes represent reserves, including probable reserves, expected to be produced based on a stipulated amount of capital expenditures. The production volumes, prices and timing of production are consistent with internal projections and other externally reported information. Oil and gas prices used for determining asset impairments will generally differ from those used in the standardized measure of discounted future net cash flows, since the standardized measure requires the use of actual prices on the last day of the year.
Results of Operations
The following review of operations for the year ended December 31, 2006, the period March 21, 2005 (Inception) through December 31, 2005, and the period March 21, 2005 (Inception) through December 31, 2006 should be read in conjunction with the Fund’s financial statements and the notes thereto. The following table summarizes the Fund’s results of operations (in thousands, except per share data):
Year Ended December 31, 2006 Compared to the Period March 21, 2005 (Inception) through December 31, 2005
For the year ended December 31, 2006, the period March 21, 2005 (Inception) through December 31, 2005 and the period March 21, 2005 (Inception) through December 31, 2006, the loss from operations totaled approximately $52.4 million, $8.8 million and $61.2 million, respectively. The losses for the year ended December 31, 2006, the period March 21, 2005 (Inception) through December 31, 2005 and the period March 21, 2005 (Inception) through December 31, 2006, were primarily a result of five projects that were determined to be dry-holes, investment fees and management fees.
Operating Revenues. From inception of the Fund in March 2005 through December 31, 2006, the Fund is considered an exploratory stage enterprise and has not recorded any operating revenues.
Operating and Other Expenses
Dry-hole costs. Dry-hole costs are those costs incurred to drill and develop a well that is ultimately found to be incapable of producing either oil or natural gas in sufficient quantities to justify completion of the well. The following table summarizes dry-hole costs inclusive of plug and abandonment costs for the year ended December 31, 2006, the period March 21, 2005 (Inception) through December 31, 2005 and the period March 21, 2005 (Inception) through December 31, 2006.
Investment Fee. The Manager was paid a one time investment fee of 4.5% of initial capital contributions. The fee is payable for the service of investigating and evaluating investment opportunities and affecting transactions when the capital contributions are made. Investment fees incurred and paid during the period March 21, 2005 (Inception) through December 31, 2005 were approximately $6.3 million. There was no investment fee paid in 2006.
Management Fee. The Manager receives an annual management fee, payable monthly, of 2.5% of total capital contributions. Management fees are charged to cover expenses associated with overhead incurred by the Manager for its on-going management, administrative and advisory services. Such overhead expenses include but are not limited to rent, payroll and benefits for employees of the Manager, and other administrative costs. Management fees incurred and paid for the year ended December 31, 2006, the period March 21, 2005 (Inception) through December 31, 2005 and the period March 21, 2005 (Inception) through December 31, 2006 totaled approximately $3.5 million, $1.9 million and $5.3 million, respectively. Effective January 1, 2007, the Manager has changed its policy regarding the annual management fee. Commencing in January 2007, the management fee payable will be equal to 2.5% of the total shareholder capital contributions, net of dry-hole expenses incurred by the Fund. For the Fund, the management fee will be reduced by $0.1 million per month, based upon dry-hole expenses of $48.7 million from inception to date.
General and Administrative Expenses. Accounting, legal, fiduciary fees and insurance expenses represent costs specifically identifiable or allocable to the Fund. Accounting and legal fees represent annual audit and tax preparation fees, quarterly reviews and filing fees of the Fund, which increased due to an increase in the number of required SEC filings during 2006. Fiduciary fees represent bank fees associated with the management of the Fund’s short-term investment portfolio in US Treasury Notes and have increased in 2006 due to greater investment activity. Insurance expense represents premiums related to well control insurance and directors and officers liability policy and are allocated by the Manager to the Fund based on capital raised by the Fund to total capital raised by all oil and natural gas funds managed by the Manager. The increase is attributable to increased drilling in 2006 compared to 2005.
The following table summarizes general and administrative expenses for the year ended December 31, 2006, the period March 21, 2005 (Inception) through December 31, 2005 and the period March 21, 2005 (Inception) through December 31, 2006.
Other Income. Other income is comprised solely of interest income and represents interest earned on money market accounts and short-term US Treasury Notes. Interest income for the year ended December 31, 2006, the period March 21, 2005 (Inception) through December 31, 2005 and the period March 21, 2005 (Inception) through December 31, 2006, totaled approximately $4.6 million, $1.6 million and $6.1 million, respectively. In 2006 the average monthly interest income increased as a result of higher interest rates in 2006 as compared to 2005, as well as a full year of interest income compared to the 2005 period.
Other Comprehensive (Loss) Income. Other comprehensive (loss) income is comprised solely of unrealized (losses) gains on short-term investments and represents unrealized (losses) gains on available-for-sale marketable debt securities. For the period March 21, 2005 (Inception) through December 31, 2005, other comprehensive income totaled approximately $51 thousand. During 2006, the US Treasury Note reached its maturity and the previously recorded unrealized gain was reclassified to other income. As of December 31, 2006, all investments in short-term US Treasury Notes are considered held-to-maturity investments and are recorded at cost plus accrued interest.
Capital Resources and Liquidity
Operating Cash Flows
Cash flow used in operating activities for the year ended December 31, 2006 was $3.1 million, primarily related to payments for management fees and general and administrative expenses of $3.5 million and $0.8 million, respectively, and a decrease in working capital of $0.6 million, offset by interest income received of $1.8 million.
Cash flow used in operating activities for the period March 21, 2005 (Inception) through December 31, 2005 was approximately $7.1 million, primarily related to payments for investment fees and management fees of approximately $6.3 million and approximately $1.9 million, respectively, offset by interest income received of approximately $1.1 million.
Cash flow used in operating activities for the period March 21, 2005 (Inception) through December 31, 2006 was approximately $10.2 million, primarily related to payments for investment fees, management fees, and general and administrative expenses of approximately $6.3 million, $5.3 million, and $0.9 million, respectively, and a decrease in working capital of $0.5 million offset by interest income received of approximately $2.9 million.
Investing Cash Flows
Cash flow provided by investing activities for the year ended December 31, 2006 was approximately $21.2 million. The Fund received proceeds of approximately $130.1 million from marketable securities that matured during 2006 and made investments in marketable securities of approximately $89.1 million. Cash used in investing activities primarily related to capital expenditures of approximately $8.6 million for unproved oil and natural gas properties and $11.1 million for properties that were determined to be unsuccessful, or dry-holes, during 2006.
Cash flow used in investing activities for the period March 21, 2005 (Inception) through December 31, 2005 was approximately $109.8 million, primarily related to investments in marketable securities of $83.3 million, cash expenditures of approximately $24.9 million for payment to operators for working interests and expenditures and approximately $0.6 million of capital expenditures for oil and natural gas properties that were determined to be unsuccessful, or dry-holes. Additionally, the Fund made investments in marketable securities of approximately $84.3 million, inclusive of the salvage fund.
Cash flow used in investing activities for the period March 21, 2005 (Inception) through December 31, 2006 was approximately $88.6 million, primarily related to $8.6 million of capital expenditures for oil and natural gas properties, and $36.6 million for properties that were determined to be unsuccessful, or dry-holes. Additionally, the Fund made investments in marketable securities of approximately $173.4 million, inclusive of the salvage fund, of which approximately $130.1 million matured during 2006.
Financing Cash Flows
Cash flow used in financing activities for the year ended December 31, 2006 was approximately $2 thousand related to cash expenditures for payment of syndication costs.
Cash flow provided by financing activities for the period March 21, 2005 (Inception) through December 31, 2005 and for the period March 21, 2005 (Inception) through December 31, 2006 was approximately $122.4 million, primarily related to cash receipts of $138.3 million obtained from the Fund’s private offering, offset by $15.9 million of payments for syndication costs.
Estimated Capital Expenditures
The Fund has entered into multiple offshore operating agreements for the drilling and development of its investment properties. The estimated capital expenditures associated with these agreements can vary depending on the stage of development on a property-by-property basis. As of December 31, 2006, such estimated capital expenditures to be spent totaled approximately $5.8 million, all of which is expected to be paid out of unspent capital contributions within the following 12 months.
The table below presents exploration and development capital expenditures from inception as well as estimated budgeted amounts for future periods. Remaining unspent development capital will be reallocated to one or more new unspecified projects.
Liquidity Needs
The Fund’s primary short-term liquidity needs are to fund its 2007 operations, including management fees and capital expenditures, with existing cash on-hand and income earned from its short-term investments and cash and cash equivalents. The Manager is entitled to receive an annual management fee from the Fund regardless of whether the Fund is profitable in that year. The annual fee, payable monthly, is equal to 2.5% of total capital contributed by shareholders. Effective January 1, 2007, the Manager has changed its policy regarding the annual management fee. Commencing in January 2007, the management fee payable will be equal to 2.5% of the total shareholder capital contributions, net of dry-hole expenses incurred by the Fund. For the Fund, the management fee will be reduced by $0.1 million per month based upon dry-hole expenses of $48.7 million from inception through December 31, 2006.
With respect to the payment of management fees, until one of the Fund’s projects begins producing, all or a portion of the management fee is paid generally from the interest or dividend income generated by the Fund’s development capital that has not been spent, although the management fee can be paid out of capital contributions. Such interest and/or dividend income is more than enough to cover Fund expenses, including the management fee. Generally, it can take anywhere from 18 to 24 months to bring a project to production. Once a well is on production, the management fee and fund expenses are paid from operating income. Over time, as a well produces, the Fund may recover some or the entire management fee that may have been paid out of capital contributions.
Distributions, if any, are funded from cash flow from operations, and the frequency and amount are within the Manager’s discretion subject to available cash from operations, reserve requirements and Fund operations.
The capital raised by the Fund in its private placement is more than likely all the capital it will be able to obtain for investments in projects. The number of projects in which the Fund can invest will naturally be limited and each unsuccessful project the Fund experiences, if any, will not only reduce its ability to generate revenue, but also exhaust its limited supply of capital. Typically for a fund, the Manager seeks an investment portfolio that combines high and low risk exploratory projects.
When the Manager makes a decision for participation in a particular project, it assumes that the well will be successful and allocates enough capital to budget for the completion of that well and the additional development wells that are anticipated to be drilled. If the exploratory well is deemed a dry-hole or if it is un-economical, the capital allocated to the completion of that well and to the development of additional wells is then reallocated to a new project or used to make additional investments.
Off-Balance Sheet Arrangements
The Fund had no off-balance sheet arrangements as of December 31, 2006 and December 31, 2005 and does not anticipate the use of such arrangements in the future.
Contractual Obligations
The Fund enters into operating agreements with operators. On behalf of the Fund, an operator enters into various contractual commitments pertaining to exploration, development and production activities. The Fund does not discuss or negotiate any such contracts. No contractual obligations exist at December 31, 2006 and December 31, 2005.
ITEM 7A.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Projects drilled may not have commercially productive oil and natural gas reservoirs. In such an event, the Funds’ revenue, future results of operations and financial condition would be adversely impacted.
The Fund does not have or use, any derivative instruments nor does it have any plans to enter into such derivative arrangements. The Fund will generally invest cash in high-quality credit instruments consisting primarily of money market funds, bankers acceptance notes and government agency securities with maturities of six months or less. The Fund does not expect any material loss from cash equivalents and therefore believes its potential interest rate exposure is not material. The Fund has no plan to conduct any international activities and therefore believes it is not subject to foreign currency risk.
The principal market risks to which the Fund is exposed that may adversely impact the Fund’s results of operations and financial position are changes in oil and natural gas prices.
Low commodity prices could have an adverse affect on the Fund’s future profitability and, in such an event the Fund may be required by accounting rules to write down the carrying value of the Fund’s projects. Revenue to the Fund will be sensitive to changes in price to be received for oil and natural gas production. Prevailing market prices fluctuate in response to many factors that are outside of the Fund’s control such as the supply and demand for oil and natural gas. Availability of alternative fuels as well as seasonal risks such as hurricanes can also impact the supply and demand.
High oil and natural gas prices have resulted in a strong demand for and a tight supply of drilling rigs necessary to drill new projects. The increased cost in daily rig rates could have a negative impact on the return to shareholders in the Fund. The shortage of drilling rigs could delay the application of capital to such projects and thus delay revenue from operations.
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
All financial statements meeting the requirements of Regulation S-X and the supplementary financial information required by Item 302 of Regulation S-K are included in the financial statements listed in Item 15 and filed as part of this report.
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING FINANCIAL DISCLOSURE
As reported on a Form 8-K filed with the SEC on July 27, 2006, the Manager of the Fund dismissed Perelson Weiner, LLP as the Fund’s independent registered public accountants effective June 8, 2006.
The Fund was formed on March 21, 2005 and filed its Registration Statement on Form 10 in April 2006; thus, the period beginning March 21, 2005 (Inception) and ended December 31, 2005 was the Fund’s first audited reporting period. Perelson Weiner’s audit report on the financial statements of the Fund for the period March 21, 2005 (inception) through December 31, 2005 did not contain an adverse opinion or disclaimer of opinion, nor was such report qualified or modified as to uncertainty, audit scope or accounting principles.
From the date of inception of the Fund through June 8, 2006, there were no disagreements with Perelson Weiner on any matter of accounting principles or practices, financial statement disclosure or auditing scope or procedure, which disagreements, if not resolved to the satisfaction of Perelson Weiner, would have caused Perelson Weiner to make reference to the subject matter of the disagreements in their report on the Fund’s financial statements for such period.
From the date of inception of the Fund through June 8, 2006, there were no “reportable events” as defined in Item 304(a)(1)(v) of Regulation S-K.
As reported on a Form 8-K filed with the SEC on July 13, 2006, the Manager of the Fund appointed Deloitte & Touche LLP (“D&T”) as the Fund’s independent registered public accountants effective July 12, 2006.
ITEM 9A.
ITEM 9A. CONTROLS AND PROCEDURES
Disclosure Controls and Procedures
The Fund maintains “disclosure controls and procedures”, as such term is defined under Securities and Exchange Act of 1934 (“Exchange Act”) Rule 13a-15(e), that are designed to ensure that information required to be disclosed in the Fund’s Exchange Act reports is recorded, processed, summarized and reported within the same time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to its management, including its Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosures. In designing and evaluating the disclosure controls and procedures, the Fund’s management recognized that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives and its management necessarily was required to apply its judgment in evaluating the cost-benefit relationship of possible controls and procedures. The Fund has carried out an evaluation, as of December 31, 2006, under the supervision and with the participation of its management, including its Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of the Fund’s disclosure controls and procedures. Based upon their evaluation and subject to the foregoing, such procedures were effective.
Changes in Internal Controls over Financial Reporting
In previous Exchange Act filings, the Fund has disclosed material weaknesses. Corrective actions have been implemented to address these material weaknesses. As of the period covered by this report, Management believes these material weaknesses have been remediated.
In the fourth quarter of 2006, the following material changes in internal control over financial reporting (as defined in Exchange Act Rule 13a-15(f)) have been implemented:
•
Expansion of accounting and SEC reporting staff and various resources, by hiring five personnel with GAAP and/or SEC accounting and reporting expertise;
•
Created detailed training programs, and policies and procedures surrounding the accounting for oil and natural gas projects and GAAP and SEC financial reporting controls; and
•
Enhanced tools and added appropriate resources to perform consistent, routine analytical reviews of the GAAP financial results, including key balance sheet and income statement account analyses.
Because the Fund is not an “Accelerated Filer” as defined in Rule 12b-2 of the Exchange Act, the Fund is not presently required to file Management’s annual report on internal control over financial reporting and the Attestation report of the registered public accounting firm required by Item 308(a) and (b) of Regulation S-K promulgated under the Securities Act. Under current rules, because the Fund is neither a “large accelerated filer” nor an “accelerated filer”, the Fund is not required to provide management’s report on internal control over financial reporting until the Fund files its annual report for 2007 and compliance with the auditor’s attestation report requirement is not required until the Fund files its annual report for 2008. The Fund currently expects to comply with these requirements at such time as the Fund is required to do so.
ITEM 9B.
ITEM 9B. OTHER INFORMATION
None.
PART III
ITEM 10.
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
The Fund has engaged Ridgewood Energy as Manager. Ridgewood Energy was founded in 1982 and, as Manager, has very broad authority, including the election of executive officers.
Executive officers of Ridgewood Energy and the Fund and their ages at December 31, 2006 are as follows:
Set forth below are the names and certain biographical information regarding the executive officers of Ridgewood Energy and the Fund:
Robert E. Swanson has served as the President, Chief Executive Officer, sole director, and sole stockholder of Ridgewood Energy since its inception. Mr. Swanson is also the controlling member of Ridgewood Power and Ridgewood Capital, affiliates of Ridgewood Energy. Mr. Swanson has been President and registered principal of Ridgewood Securities and has served as the Chairman of the Board of Ridgewood Capital since its organization in 1998. Mr. Swanson is a member of the New York State and New Jersey State Bars, the Association of the Bar of the City of New York and the New York State Bar Association. He is a graduate of Amherst College and Fordham University Law School.
Greg Tabor has served as the Executive Vice President and Director of Business Development for Ridgewood Energy since January 2004. Mr. Tabor was senior business development manager for El Paso Production Company from December 2001 to December 2003. From April 2000 to December 2001, Mr. Tabor was Vice President, Business Development for Madison Energy Advisors. Mr. Tabor is a graduate of the University of Houston.
Robert L. Gold has served as the Executive Vice President of Ridgewood Energy since 1987. Mr. Gold is also Executive Vice President of Ridgewood Power. Mr. Gold has also served as the President and Chief Executive Officer of Ridgewood Capital since its inception in 1998. Mr. Gold is a member of the New York State Bar. He is a graduate of Colgate University and New York University School of Law.
Kathleen P. McSherry has served as the Senior Vice President and Chief Financial Officer of Ridgewood Energy since 2000. Ms. McSherry has been employed by Ridgewood Energy since 1987, first as the Assistant Controller and then as the Controller before being promoted to Chief Financial Officer in 2000. Ms. McSherry also serves as Vice President of Systems and Administration of Ridgewood Power. Ms. McSherry holds a Bachelor of Science degree in Accounting.
Daniel V. Gulino has served as Senior Vice President and General Counsel of Ridgewood Energy since August 2003. Mr. Gulino also serves as Senior Vice President and General Counsel of Ridgewood Power Management, Ridgewood Power, and Ridgewood Capital and has done so since 2000. Mr. Gulino is a member of the New Jersey State and Pennsylvania State Bars. He is a graduate of Fairleigh Dickinson University and Rutgers School of Law.
Adrien Doherty has served as Executive Vice President of Ridgewood Energy since 2006. Mr. Doherty joined Ridgewood Energy after a thirty year career in investment banking, most recently as Head of Barclay’s Capital’s oil and gas banking effort. Mr. Doherty is a graduate of Amherst College and the Wharton Graduate Division of the University of Pennsylvania.
Board of Directors and Board Committees
The Fund does not have its own board of directors or any board committees. The Fund relies upon the Manager to provide recommendations regarding dispositions and financial disclosure. Officers of the Fund are not compensated by the Fund, and all compensation matters are addressed by the Manager, as described in Item 11
ITEM 11. EXECUTIVE COMPENSATION
The executive officers of the Fund do not receive compensation from the Fund. The Manager, or its affiliates, compensates the officers without additional payments by the Fund. See Item 13. “Certain Relationships and Related Transactions and Director Independence” for more information regarding Manager compensation and payments to affiliated entities.
Compensation Discussion and Analysis
The executive officers of the Fund, Mr. Swanson, Mr. Tabor, Mr. Gold, Ms. McSherry, Mr. Gulino and Mr. Doherty, are employed by, and are executive officers of, the Manager, Ridgewood Energy, and provide managerial services to the Fund in accordance with the terms of the Fund’s LLC operating agreement. The Fund does not have any other executive officers. The Manager determines and pays the compensation of these officers. Each of the executive officers of the Fund also serves as an executive officer of each of the other funds managed by the Manager. Because the executive officers are employees of our Manager and provide managerial services to all of the funds managed by our Manager in the course of such employment, they do not receive additional compensation for providing managerial services to the Fund or to any one or more new funds established by the Manager than they would otherwise receive from the Manager if they did not serve in such capacities for the Fund or any such other funds.
The Manager is fully responsible for the payment of compensation to the executive officers. The Fund does not pay any compensation to its executive officers and does not reimburse the Manager for the compensation paid to executive officers. The Fund does, however, pay the Manager a management fee and the Manager may determine to use a portion of the proceeds from the management fee to pay compensation to executive officers of the Fund.
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED SECURITY HOLDER MATTERS
The following table sets forth information with respect to beneficial ownership of the shares as of December 31, 2006 (no person owns more than 5% of the shares) by:
•
each executive officer (there are no directors); and
•
all of the executive officers as a group.
Beneficial ownership is determined in accordance with the rules of the SEC and includes voting or investment power with respect to the securities. Except as indicated by footnote, and subject to applicable community property laws, the persons named in the table below have sole voting and investment power with respect to all shares shown as beneficially owned by them. Percentage of beneficial ownership is based on 933.0600 shares outstanding at December 31, 2006. Other than the above, no officer and director owns any of the Fund’s shares.
* Represents less than one percent.
(1) Includes shares owned by the spouse of Mr. Swanson or one of his Trust’s.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE
In connection with the sale of shares in 2005, Ridgewood Securities Corporation, an affiliate of the Manager, earned a placement fee and commissions totaling approximately $1.6 million included in syndication costs. The Manager earned an investment fee for the services of investigating and evaluating projects for future investment totaling approximately $6.3 million.
The Manager was paid approximately $4.9 million to cover legal and syndication fees for the organization, distribution and offering expenses.
The Manager receives an annual management fee, payable monthly, equal to 2.5% of total capital contributions, for general and administrative and management services supplied to us. Additionally, when distributions are made, the Manager is entitled to a portion of funds distributed to shareholders. For the year ended December 31, 2006, the period March 21, 2005 (Inception) through December 31, 2005 and the period March 21, 2005 (Inception) through December 31, 2006 the manager was paid fees which totaled approximately $3.5 million, $1.9 million and $5.3 million, respectively. There have been no distributions for the period March 21, 2005 (Inception) through December 31, 2006. Effective January 1, 2007, the Manager has changed its policy regarding the annual management fee. Commencing in January 2007, the management fee payable will be equal to 2.5% of the total shareholder capital contributions, net of dry-hole expenses incurred by the Fund. For the P Fund, the management fee will be reduced by $0.1 million per month, based upon dry-hole expenses of $48.7 million from inception through December 31, 2006.
Profits and losses are allocated in accordance with the LLC Agreement. In general, profits and losses in any year are allocated 85% to shareholders and 15% to the Manager. The primary exception to this treatment is that all items of expense, loss, deduction and credit attributable to the expenditure of shareholders’ capital contributions are allocated 99% to shareholders and 1% to the Manager.
ITEM 14.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
The following table presents fees and services rendered by Deloitte and Touche, LLP for the year ended December 31, 2006 and Perelson Weiner LLP for the period March 21, 2005 (Inception) through December 31, 2005:
(1)
Fees for audit of annual financial statements, reviews of the related quarterly financial statements, and reviews of documents filed with the SEC.
(2)
Fees related to professional services for tax compliance, tax advice and tax planning.
PART IV.
ITEM 15.
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES.
(a) (1) Financial Statements
See “Index to Financial Statements” set forth on page.
(a) (2) Financial Statement Schedules
None.
Exhibits
Page
Report of Independent Registered Public Accounting Firm
Balance Sheets as of December 31, 2006 and December 31,
Statements of Operations and Other Comprehensive Loss for the year ended December 31, 2006, the period March 21, 2005 (Inception) through December 31, 2005 and for the period March 21, 2005 (Inception) through December 31, 2006
Statements of Changes in Members’ Capital for the year ended December 31, 2006, the period March 21, 2005 (Inception) to December 31, 2005 and the period March 21, 2005 (Inception) to December 31,
Statements of Cash Flows for the year ended December 31, 2006, the period March 21, 2005 (Inception) through December 31, 2005 and for the period March 21, 2005 (Inception) through December 31, 2006
Notes to Financial Statements
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Shareholders and Manager of Ridgewood Energy P Fund, LLC:
We have audited the accompanying balance sheets of Ridgewood Energy P Fund, LLC (an exploratory stage enterprise) (the “Fund”) as of December 31, 2006 and 2005, the related statements of operations and other comprehensive loss and cash flows for the year ended December 31, 2006, for the period March 21, 2005 (Inception) through December 31, 2005 and for the period March 21, 2005 (Inception) through December 31, 2006 and the related statements of changes in members’ capital for the year ended December 31, 2006 and for the period March 21, 2005 (Inception) through December 31, 2005. These financial statements are the responsibility of the Fund’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 Fund 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 control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Fund’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also 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, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such financial statements present fairly, in all material respects, the financial position of Ridgewood Energy P Fund, LLC at December 31, 2006 and 2005, and the results of its operations and its cash flows for the year ended December 31, 2006, for the period March 21, 2005 (Inception) through December 31, 2005 and for the period March 21, 2005 (Inception) through December 31, 2006, in conformity with accounting principles generally accepted in the United States of America.
/s/ Deloitte and Touche LLP
March 30, 2007
Parsippany, New Jersey
RIDGEWOOD ENERGY P FUND, LLC
(An exploratory stage enterprise)
BALANCE SHEETS
(in thousands, except for share data)
The accompanying notes are an integral part of these financial statements.
RIDGEWOOD ENERGY P FUND, LLC
(An exploratory stage enterprise)
STATEMENTS OF OPERATIONS AND OTHER COMPREHENSIVE LOSS
(in thousands, except per share data)
The accompanying notes are an integral part of these financial statements.
RIDGEWOOD ENERGY P FUND, LLC
(An exploratory stage enterprise)
STATEMENT OF CHANGES IN MEMBERS’ CAPITAL
(in thousands, except for share data)
The accompanying notes are an integral part of these financial statements.
RIDGEWOOD ENERGY P FUND, LLC
(An exploratory stage enterprise)
STATEMENTS OF CASH FLOWS
(in thousands)
The accompanying notes are an integral part of these financial statements.
RIDGEWOOD ENERGY P FUND, LLC
(An exploratory stage enterprise)
NOTES TO FINANCIAL STATEMENTS
1. Organization and Purpose
The Ridgewood Energy P Fund, LLC (“Fund”), a Delaware limited liability company, was formed on March 21, 2005 and operates pursuant to a limited liability company agreement (“Agreement”) dated as of May 16, 2005 by and among Ridgewood Energy Corporation (“Manager”), and the shareholders of the Fund. Although the date of formation is March 21, 2005, the Fund did not begin business activities until May 16, 2005 when it began its private offering of shares. There were no business activities prior to May 16, 2005.
The Fund was organized to acquire, drill, construct and develop oil and natural gas properties located in the United States offshore waters of Texas, Louisiana and Alabama in the Gulf of Mexico. The Fund has devoted most of its efforts to raising capital and oil and natural gas exploration activities. To date, the Fund has not earned revenue from these operations and is considered in the exploratory stage.
The Manager performs (or arranges for the performance of) the management and administrative services required for Fund operations. Such services include, without limitation, the administration of shareholder accounts, shareholder relations and the preparation, review and dissemination of tax and other financial information. In addition, the Manager provides office space, equipment and facilities and other services necessary for Fund operations. The Manager also engages and manages the contractual relations with outside custodians, depositories, accountants, attorneys, broker-dealers, corporate fiduciaries, insurers, banks and others as required (Notes 2, 6 and 7).
2. Summary of Significant Accounting Policies
Use of Estimates
The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities as of the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. On an ongoing basis, the Manager reviews its estimates, including those related to amounts advanced to and billed by operators, determination of proved reserves, impairment allowances and environmental liabilities. Actual results may differ from those estimates.
Advances to Operators for Working Interests and Expenditures
The Fund’s acquisition of a working interest in a well or a project requires it to make a payment to the seller for the Fund’s rights, title and interest. The Fund is required to advance its share of estimated cash outlay for the succeeding month’s operation. The Fund accounts for such payments as advances to operators for working interests and expenditures. As drilling costs are incurred, the advances are transferred to unproved properties.
Oil and Natural Gas Properties
Investments in oil and natural gas properties are operated by unaffiliated entities (“Operators”) who are responsible for drilling, administering and producing activities pursuant to the terms of the applicable Operating Agreements with working interest owners. The Fund’s portion of exploration, drilling, operating and capital equipment expenditures relating to the wells are advanced and billed by Operators through authorization for expenditures.
The successful efforts method of accounting for oil and gas producing activities is followed. Acquisition costs are capitalized when incurred. Other oil and natural gas exploration costs, excluding the costs of drilling exploratory wells, are charged to expense as incurred. The costs of drilling exploratory wells are capitalized pending the determination of whether the wells have discovered proved commercial reserves. If proved commercial reserves have not been found, exploratory drilling costs are expensed to dry-hole expense. Costs to develop proved reserves, including the costs of all development wells and related facilities and equipment used in the production of natural crude oil and natural gas, are capitalized. Expenditures for ongoing repairs and maintenance of producing properties are expensed as incurred.
Upon the sale or retirement of a proved property (i.e. a producing well), the cost and related accumulated depletion and amortization will be eliminated from the property accounts, and the resultant gain or loss is recognized. On the sale or retirement of an unproved property, gain or loss on the sale is recognized. It is not the Manager’s intention to sell any of the Fund’s property interests.
Capitalized acquisition costs of producing oil and natural gas properties after recognizing estimated salvage values are depleted by the unit-of-production method.
As of December 31, 2006 and 2005 amounts recorded in due to operators totaling approximately $14.0 million and nil, respectively, related to the acquisition of oil and gas property, both successful and unsuccessful.
Revenue Recognition
Oil and natural gas sales are recognized when delivery is made by the Operator to the purchaser and title is transferred (i.e., production has been delivered to a pipeline or transport vehicle). The Fund has not earned revenue from inception to date.
The volume of oil and natural gas sold on the Fund’s behalf may differ from the volume of oil and natural gas the Fund is entitled to. The Fund will account for such oil and natural gas production imbalances by the entitlements method. Under the entitlements method, the Fund will recognize a receivable from other working interest owners for volumes oversold by other working interest owners, and a payable to other working interest owners for volumes oversold by the Fund. At December 31, 2006 and 2005, there were no oil or natural gas balancing arrangements between the Fund and other working interest owners.
Syndication Costs
Direct costs associated with offering the Fund’s shares including professional fees, selling expenses and administrative costs payable to the Manager, an affiliate of the Manager and outside brokers are reflected as a reduction of shareholders’ capital.
Asset Retirement Obligations
For oil and natural gas properties, there are obligations to perform removal and remediation activities when the properties are retired. When a project reaches drilling depth and is determined to be either proved or dry, an asset retirement obligation is incurred. Plug and abandonment costs associated with unsuccessful projects are expensed as dry-hole costs.
Impairment of Long-Lived Assets
In accordance with the provisions of SFAS No. 144, “Accounting for the Impairment of Long-Lived Assets”, long-lived assets, such as oil and natural gas properties, are evaluated when events or changes in circumstances indicate the carrying value of such assets may not be recoverable. The determination of whether impairment has occurred is made by comparing the carrying values of long-lived assets to the estimated future undiscounted cash flows attributable to the asset. The impairment loss recognized is the excess of the carrying value over the future discounted cash flows attributable to the asset or the estimated fair value of the asset. No impairments have been recorded in the Fund since inception.
Depletion and Amortization
Depletion and amortization of the cost of proved oil and natural gas properties are calculated using the units of production method. Proved developed reserves are used as the base for depleting the cost of successful exploratory drilling and development costs. The sum of proved developed and proved undeveloped reserves is used as the base for depleting (or amortizing) leasehold acquisition costs, the costs to acquire proved properties and platform and pipeline costs. At December 31, 2006 and December 31, 2005, the Fund did not have accumulated depletion as production has not yet occurred.
Income Taxes
No provision is made for income taxes in the financial statements. Because the fund is an LLC, the income or losses are passed through and included in the tax returns of the individual shareholders.
Cash and cash equivalents
All highly liquid investments with maturities when purchased of three months or less are considered as cash and cash equivalents. At times, bank deposits may be in excess of federal insured limits. At December 31, 2006 and December 31, 2005, bank balances inclusive of the salvage fund exceeded federally insured limits by approximately $23.5 million and $5.3 million, respectively. The Fund maintains bank deposits with accredited financial institutions to mitigate such risk.
Salvage Fund
Pursuant to the Fund’s LLC Agreement, the Fund deposits in a separate interest-bearing account, or a salvage fund, money to provide for dismantling production platforms and facilities, plugging and abandoning the wells and removing the platforms, facilities and wells after their useful lives, in accordance with applicable federal and state laws and regulations.
Interest earned on the account will become part of the salvage fund; there are no legal restrictions on the withdrawal from the salvage fund.
Income and Expense Allocation
Profits and losses are to be allocated 85% to shareholders in proportion to their relative capital contributions and 15% to the Manager, except for items of expense, loss, deduction and credit that are attributable to the expenditure of shareholders’ capital contributions, which are allocated 99% to shareholders and 1% to the Manager.
3. Recent Accounting Standards
In February 2007, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities” (“SFAS No. 159”), which permits entities to measure many financial instruments and certain other items at fair value that are not currently required to be measured at fair value. An entity would report unrealized gains and losses on items for which the fair value option has been elected in earnings at each subsequent reporting date. 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. The decision about whether to elect the fair value option is applied instrument by instrument, with a few exceptions; the decision is irrevocable; and it is applied only to entire instruments and not to portions of instruments. The statement requires disclosures that facilitate comparisons (a) between entities that choose different measurement attributes for similar assets and liabilities and (b) between assets and liabilities in the financial statements of an entity that selects different measurement attributes for similar assets and liabilities. SFAS No. 159 is effective for financial statements issued for fiscal years beginning after November 15, 2007. Early adoption is permitted as of the beginning of a fiscal year provided the entity also elects to apply the provisions of SFAS No. 157, “Fair Value Measurements,” (“SFAS No.157”). Upon implementation, an entity shall report the effect of the first remeasurement to fair value as a cumulative-effect adjustment to the opening balance of Retained Earnings. Since the provisions of SFAS No.159 are applied prospectively, any potential impact will depend on the instruments selected for fair value measurement at the time of implementation. The Fund does not believe that its financial position, results of operations or cash flows will be impacted by the adoption of SFAS No. 159.
In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements” (“SFAS No. 157”), which applies under most other accounting pronouncements that require or permit fair value measurements. SFAS No. 157 provides a common definition of fair value as the price that would be received to sell an asset or paid to transfer a liability in a transaction between market participants. The new standard also provides guidance on the methods used to measure fair value and requires expanded disclosures related to fair value measurements. SFAS No. 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007. The Fund does not expect this guidance to have a material impact on the financial statements.
In September 2006, the SEC Staff issued Staff Accounting Bulletin (“SAB”) No. 108, “Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements,” (“SAB No. 108”) in an effort to address diversity in the accounting practice of quantifying misstatements and the potential for improper amounts on the balance sheet. Prior to the issuance of SAB No. 108, the two methods used for quantifying the effects of financial statement errors were the rollover and iron curtain methods. Under the rollover method, the primary focus is the income statement, including the reversing effect of prior year misstatements. The iron curtain method focuses on the effect of correcting the ending balance sheet, with less importance on the reversing effects of prior year errors in the income statement. SAB No. 108 establishes a dual approach which requires the quantification of the effect of financial statement errors on each financial statement, as well as related disclosures. Public companies are required to record the cumulative effect of initially adopting the dual approach method in the first year ending after November 16, 2006 by recording any necessary corrections to asset and liability balances with an offsetting adjustment to the opening balance of retained earnings. The use of this cumulative effect transition method also requires detailed disclosures of the nature and amount of each error being corrected and how and when they arose. The Fund has adopted the provisions of SAB No. 108 and there was no impact to its financial position, results of operations and cash flows as a result of this pronouncement.
4. Unproved Properties - Capitalized Exploratory Well Costs
Leasehold acquisition and exploratory drilling costs are capitalized pending determination of whether the well has found proved reserves. Unproved properties are assessed on a quarterly basis by evaluating and monitoring if sufficient progress is made on assessing the reserves. Capitalization costs are expensed as dry-hole costs in the event that reserves are not found or are not in sufficient quantities to complete the well and develop the field.
The following table reflects the net changes in unproved properties for the years ended December 31, 2006 and 2005. As of December 31, 2006 and 2005, the Fund had no capitalized exploratory well costs greater than one year.
5. Short-term Investments in Marketable Securities inclusive of Salvage Fund
Short-term investments are comprised of United States Treasury Notes with maturities greater than six months and are considered held-to-maturity investments. Held-to-maturity securities are those investments that the Fund has the ability and intent to hold until maturity. Held-to-maturity investments are recorded at cost plus accrued income, adjusted for the amortization of premiums and discounts, which approximate market value. Interest income is accrued as earned. Held-to maturity investments as of December 31, 2006 were $45.5 million and mature in January and May 2007.
Available for sale securities are carried in the financial statements at fair value. The Fund had no short-term investments considered available for sale as of December 31, 2006. Available for sale investments as of December 31, 2006 matured in May 2006. The following table is a summary of short-term investments considered available for sale at December 31, 2005.
6. Distributions
Distributions to shareholders are allocated in proportion to the number of shares held.
The Manager will determine whether Available Cash from Operations, as defined in the Fund’s LLC Agreement, is to be distributed. Such distribution will be allocated 85% to the shareholders and 15% to the Manager, as defined in the Fund’s Operating Agreement.
Available Cash from Dispositions, as defined in the Fund’s LLC Agreement, will be paid 99% to shareholders and 1% to the Manager until the shareholders have received total distributions equal to their capital contributions. After shareholders have received distributions equal to their capital contributions, 85% of Available Cash from Dispositions will be distributed to shareholders and 15% to the Manager.
There have been no distributions made by the Fund.
7. Related Parties
Ridgewood Energy Corporation, the Manager, was paid a one time investment fee of 4.5% of capital contributions. These fees are payable for services provided by the Manager of locating, investigating and evaluating investment opportunities and effecting transactions when the capital contribution is made. For the period March 21, 2005 (Inception) through December 31, 2005, investment fees were approximately $6.3 million. Of this amount nil and approximately $12 thousand were included in due to affiliates at December 31, 2006 and December 31, 2005, respectively. In 2006, there were no investment fees.
A management agreement provides that the Manager render management, administrative and advisory services. For such services, the Manager receives an annual management fee, payable monthly, of 2.5% of total capital contributions. Management fees of $3.5 million, $1.9 million and $5.3 million were incurred and paid for the year ended December 31, 2006, for the period March 21, 2005 (Inception) through December 31, 2005, and for the period from March 21, 2005 (Inception) through December 31, 2006, respectively. The Manager changed its policy regarding the calculation of the management fees effective January 1, 2007. See Note 11. Subsequent Events.
The Manager was paid an offering fee which approximated 3.5% of capital contributions to cover expenses incurred in the offer and sale of shares of the Fund. Such offering fee was included in syndication costs (Note 2) of approximately $15.9 million. For the year ended December 31, 2005, offering fees were $4.9 million. Of this amount nil and approximately $10 thousand, were included in due to affiliates as of December 31, 2006 and December 31, 2005, respectively.
From time to time, short-term payables and receivables, which do not bear interest, arise from transactions with affiliates in the ordinary course of business. As of December 31, 2006 and December 31, 2005, the Manager owed the Fund approximately nil and $1 thousand, respectively, for the overpayment of fees which is included in due to affiliates.
In 2005, Ridgewood Securities Corporation, a registered broker-dealer affiliated with the Manager, was paid selling commissions and placement fees of approximately $0.3 million and $1.4 million, respectively, for shares of the Fund sold which are reflected in syndication costs (Note 2). At December 31, 2006 and December 31, 2005, approximately nil and $9 thousand, respectively, was included in due to affiliates.
None of the compensation to be received by the Manager has been derived as a result of arm’s length negotiations.
The Fund has working interest ownership in certain projects to acquire and develop oil and natural gas projects with other entities that are likewise managed by the Manager.
8. Fair Value of Financial Instruments
As of December 31, 2006, and for the period March 21, 2005 (Inception) through December 31, 2005, the carrying value of cash and cash equivalents, short-term investments in marketable securities, and salvage fund, approximate fair value.
9. Commitments and Contingencies
Environmental Considerations
The exploration for and development of oil and natural gas involves the extraction, production and transportation of materials which, under certain conditions, can be hazardous or cause environmental pollution problems. The Manager and the Operators are continually taking action they believe appropriate to satisfy applicable federal, state and local environmental regulations and do not currently anticipate that compliance with federal, state and local environmental regulations will have a material adverse effect upon capital expenditures, results of operations or the competitive position of the Fund in the oil and natural gas industry. However, due to the significant public and governmental interest in environmental matters related to those activities, the Manager cannot predict the effects of possible future legislation, rule changes, or governmental or private claims. As of December 31, 2006 and December 31, 2005, there were no known environmental issues that required the Fund to record a liability.
Insurance Coverage
The Fund is subject to all risks inherent in the exploration for and development of oil and natural gas. Insurance coverage as is customary for entities engaged in similar operations is maintained, but losses may occur from uninsurable risks or amounts in excess of existing insurance coverage. The occurrence of an event which is not insured or not fully insured could have an adverse impact upon earnings and financial position. Moreover, insurance is obtained as a package covering all of the Manager’s investment programs. Claims made by other such programs can reduce or eliminate insurance for the Fund.
10. Information about Oil and Natural Gas Producing Activities
In accordance with Statement of Financial Accounting Standards No. 69, “Disclosures about Oil and Gas Producing Activities,” this section provides supplemental information on oil and natural gas exploration and producing activities of the Fund. Tables I through V provide historical cost information pertaining to capitalized costs, costs incurred in exploration, and property acquisitions and development.
The Fund is engaged solely in oil and natural gas activities, all of which are located in the United States offshore waters of Texas, Louisiana and Alabama in the Gulf of Mexico.
Table I - Capitalized Costs Related to Oil and Gas Producing Activities (in thousands)
Table II - Costs Incurred in Exploration, Property Acquisitions and Development (in thousands)
Table III - Reserve Quantity Information (Unaudited)
Oil and gas reserves of the Fund have been estimated by an independent petroleum engineer for the year ended December 31, 2006. The reserve estimates for December 31, 2006 were based on estimated future reserves as of September 30, 2006 provided by an independent petroleum engineer. These reserves have been prepared in compliance with the Securities and Exchange Commission rules.
Proved reserves are classified as either developed or undeveloped. Proved developed reserves are the quantities expected to be recovered through existing wells with existing equipment and operating methods.
Due to the inherent uncertainties and the limited nature of recovery data, estimates of reserve information are subject to change as additional information becomes available.
Table IV - Standardized Measure of Discounted Future Net Cash Flows Related to Proved Oil and Gas Reserves (Unaudited, in thousands)
Summarized in the following table is information for the Fund 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 Fund’s proved reserves to the year-end quantities of those reserves. Future production, development, site restoration and abandonment costs are derived based on current costs assuming continuation of existing economic conditions.
Table V - Changes in the Standardized Measure of Discounted Future Net Cash Flows Related to Proved Oil and Gas Reserves (Unaudited, in thousands)
The changes in present values between years, which can be significant, reflect changes in estimated proved reserve quantities and prices and assumptions used in forecasting production volumes and costs.
It is necessary to emphasize that the data presented should not be viewed as representing the expected cash flow from, or current value of, existing proved reserves since the computations are based on a large number of estimates and arbitrary assumptions. Reserve quantities cannot be measured with precision and their estimation requires many judgmental determinations and frequent revisions. The required projection of production and related expenditures over time requires further estimates with respect to pipeline availability, rates of demand and governmental control. Actual future prices and costs are likely to be substantially different from the current prices and costs utilized in the computation of reported amounts. Any analysis or evaluation of the reported amounts should give specific recognition to the computational methods utilized and the limitations inherent therein.
11. Subsequent Events
Management Fee
Effective January 1, 2007, the Manager has changed its policy regarding the annual management fee. Commencing in January 2007, the management fee payable will be equal to 2.5% of the total shareholder capital contributions, net of dry-hole expenses incurred by the Fund. For the Fund, the management fee will be reduced by $0.1 million per month, based upon dry-hole expenses of $48.7 million from inception to date.
Green Canyon 246
On January 24, 2007, the Fund was informed by its operator, Woodside, that the exploratory well being drilled by Woodside in the Green Canyon 246 lease block did not have commercially productive quantities of either oil or natural gas and had therefore been deemed an unsuccessful well or dry-hole. The Fund owns a working interest in Green Canyon 246. Dry-hole costs related to Green Canyon 246, including plug and abandonment expenses, incurred by the Fund for the year ended December 31, 2006, the period March 21, 2005 (Inception) through December 31, 2005, and for the period March 21, 2005 (Inception) through December 31, 2006 were approximately $4.8 million, nil and $4.8 million, respectively. The Fund incurred additional dry-hole costs related to Green Canyon 246 of $1.4 million during 2007.
South Timbalier 135/136
On January 24, 2007, the Fund was informed by its operator, Chevron, that the exploratory well being drilled by Chevron in the South Timbalier 135/136 lease block did not have commercially productive quantities of either oil or natural gas and has therefore been deemed an unsuccessful well or dry-hole. The Fund owns a working interest in South Timbalier 135/136. Dry-hole costs related to South Timbalier 135/136, including plug and abandonment expenses, incurred by the Fund for the year ended December 31, 2006, the period March 21, 2005 (Inception) through December 31, 2005, and for the period March 21, 2005 (Inception) through December 31, 2006 were approximately $5.2 million, nil and $5.2 million, respectively. The Fund incurred additional dry-hole costs related to South Timbalier 135/136 of $1.6 million during 2007.
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
Signature
Capacity
Date
/s/ ROBERT E. SWANSON
Chief Executive Officer
March 30, 2007
(Principal Executive Officer)
Robert E. Swanson
/s/ KATHLEEN P. MCSHERRY
Senior Vice President and Chief Financial Officer
March 30, 2007
(Principal Accounting Officer)
Kathleen P. McSherry