ITEM 1. BUSINESS
Overview
The Fund is a Delaware limited liability company (“LLC”) formed on March 1, 2004 to primarily acquire interests in oil and natural gas properties located in the United States offshore waters of Texas, Louisiana and Alabama in the Gulf of Mexico.
The Fund initiated its private placement offering on April 1, 2004, selling whole and fractional shares of LLC membership interests (“Shares”) primarily at $150 thousand per whole Share. There is no public market for the Shares and one is not likely to develop. In addition, the Shares are subject to material restrictions on transfer and resale and cannot be transferred or resold except in accordance with the Fund's limited liability company agreement (the “LLC Agreement”) and applicable federal and state securities laws. The private placement offering was terminated on August 1, 2004. The Fund raised $70.9 million and after payment of $11.1 million in offering fees, commissions and investment fees, the Fund had $59.8 million for investments and operating expenses.
Manager
Ridgewood Energy Corporation (the “Manager” or “Ridgewood Energy”) was founded in 1982. The Manager has direct and exclusive control over the management of the Fund’s operations. With respect to project investments, the Manager locates potential projects, conducts due diligence and negotiates and completes the transactions in which the investments are made. This includes review of existing title documents, reserve information, and other technical specifications regarding a project, and review and preparation of participation agreements and other agreements relating to an investment. Additional information regarding the Manager is available through its website at www.ridgewoodenergy.com. No information on such website shall be deemed to be included or incorporated by reference into this Form 10-K.
The Manager performs, or arranges for the performance of, the management, advisory 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 unaffiliated custodians, depositories, accountants, attorneys, broker-dealers, corporate fiduciaries, insurers, banks and others as required.
The Fund is required to pay all other expenses it may incur, including insurance premiums, expenses of preparing and printing periodic reports for shareholders and the SEC, commission fees, taxes, third-party legal, accounting and consulting fees, litigation expenses and other expenses. The Fund is required to reimburse the Manager for all such expenses paid on its behalf.
In accordance with the LLC Agreement, the Manager is entitled to an annual management fee, equal to 2.5% of the total shareholder capital. During 2005, the Manager waived its management fee for the remaining life of the Fund.
The Manager is entitled to a 15% interest in cash distributions made by the Fund. During 2006, the Manager elected to waive its right to distributions of available cash from operations for the remaining life of the Fund.
Business Strategy
The Fund’s primary investment objective has been to generate cash flow for distribution to its shareholders through the acquisition of working interests in the exploration, production and sale of oil and natural gas. Distributions 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. A working interest is a percentage of ownership in an oil and natural gas lease granting its owner the right to explore, drill and produce oil and natural gas from projects on that lease block. The Fund has focused on projects that have significant reserve potential and 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. Working interest owners are obligated to pay a corresponding percentage of the cost of leasing, drilling, producing and operating a well. After royalties are paid, the working interest also entitles its owner to share in production revenues with other working interest owners, based on the percentage of working interest owned.
By virtue of its acquisition of working interests in various leases, the Fund invests and participates in exploration and production of oil and natural gas projects in leases located in the waters of the Gulf of Mexico 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 Bureau of Ocean Energy Management, Regulation and Enforcement (“BOE”) (formerly the Mineral Management Services). The Fund generally has looked to invest in working interests 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 the working interest. For certain of the Fund’s investments, the Fund may have paid the operator a “promote” on the cost of an initial exploratory well, representing a larger share of the drilling costs. 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 invested in projects that it believes contain sufficient commercial quantities of oil or natural gas and which are near existing oil or natural gas gathering and processing infrastructure and developed markets where the Fund can sell its oil or natural gas.
For project investments, the Manager reviews reserve analyses provided by the operators. The Manager employs individuals in its Houston, Texas office that can perform significant analysis of the operator’s information. However, if necessary, the Fund may retain independent engineers to review the operator’s reserve analysis and/or conduct an independent review. For producing properties, the Manager engages independent petroleum engineers to examine and provide reserve estimates on the Fund’s behalf.
Once the Manager determines that a particular project (i.e., working interest in a lease block) is an appropriate investment for the Fund, the Manager enters into a participation agreement and a joint operating agreement with the other working interest owners in a lease. Pursuant to the participation agreements and operating agreements, proposals and decisions are made based on percentage ownership approvals.
The Manager, on behalf of the Fund, and other working interest owners retain the right to make proposals involving certain operational matters associated with a project. This limits the operator’s inclination to act on its own or against the interests of the other working interest owners of the project. In accordance with the Manager’s working interest, the Manager reviews, discusses and consents to the details of the drilling plan, monitors progress under such plan, contributes ideas to the design of and budget for production facilities and then monitors the construction of those facilities. In addition, the Manager retains the right to review and audit the operator’s financial records related to the project to ensure the project is executed according to budget. Once a well is in production, the Manager continually monitors, evaluates and discusses the well production rate with the operator.
Manager’s Investment Committee
The Manager maintains an investment committee, consisting of five members, which provides operational, financial, scientific and technical oil and gas expertise to the Fund (the “Investment Committee”). Four members of the Investment Committee are based out of the Manager’s Montvale, New Jersey office and one member is based out of the Manager’s Houston, Texas office. Once the technical and economic analyses of a potential project were complete and a project was deemed to satisfy Ridgewood Energy’s technical criteria, provided an attractive economic risk/reward ratio, and fit within Ridgewood Energy’s diversification strategy, final investment approval was made by the Investment Committee. When reviewing a project for final investment approval, the Investment Committee sought to balance the economics of the projects, the potential sizes of the projects, the diversity of the operators, and the likely timing of new projects. The Investment Committee also considered the geological, financial and operating risks of the proposed project and compared these risks to the existing portfolio of Ridgewood Energy projects. The Investment Committee further focused on the initial well cost relative to the overall revenue potential of the project.
Post-Investment Activities
The Fund has reached the end of its project investment cycle. All of the projects in which the Fund owns a working interest are currently producing, have been determined to be dry holes or have been fully depleted. The Investment Committee continually evaluates the production rates of the Fund’s producing wells and takes steps to ensure that optimal prices are obtained for the oil and natural gas produced by the Fund’s wells.
Project Information
Existing projects, and future projects, if any, are located in the waters of the Gulf of Mexico offshore from Texas, Louisiana and Alabama on the OCS. The OCSLA governs certain activities with respect to working interests and the exploration of oil and natural gas in the OCS. See further discussion under the heading “Regulation” in Item 1. “Business” of this Annual Report.
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 and 800 meters and 10 years for depths in excess of 800 meters. During a 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.
Royalty Payments
Generally, working interests in an offshore oil and natural gas lease under the OCSLA pay a 16.67% or 18.75% royalty to the BOE for shallow-water projects, dependent upon the lease date, and a 12.5% royalty to the BOE for deepwater projects. Therefore, the net revenue interest of the holders of 100% of the working interest in the projects in which the Fund will invest is between 81.25% and 83.33% of the total revenue for shallow-water projects and 87.5% of the total revenue for deepwater projects, and, such net revenue amount is further reduced by any other royalty burdens that apply to a lease block. Other than BOE royalties, the Fund does not have material royalty burdens.
Properties
Productive Wells
The following table sets forth the number of productive oil and natural gas wells in which the Fund owned an interest as of December 31, 2010. Productive wells are producing wells and wells capable of production. Gross wells are the total number of wells in which the Fund has an interest. Net wells are the sum of the Fund’s fractional working interests owned in the gross wells. All of the wells are located in the offshore waters of the Gulf of Mexico and are operated by third-party operators.
Acreage Data
The following table sets forth the Fund’s interests in developed oil and gas acreage as of December 31, 2010. The Fund did not have any interests in undeveloped oil and gas acreage as of December 31, 2010. Ownership interests generally take the form of working interests in oil and gas leases that have varying terms. All of the wells are located in the offshore waters of the Gulf of Mexico and are operated by third-party operators.
Information regarding the Fund’s current projects, all of which are located in the offshore waters of the Gulf of Mexico, is provided in the following table.
In April 2010, the Deepwater Horizon, which was drilling a BP-operated project in the deepwater of the Gulf of Mexico, sank after an apparent blowout and fire. As of the date of this filing, the well has been permanently capped and environmental remediation efforts are ongoing. Neither the Fund nor any operators of the Fund’s projects owns an interest in the affected field. As a result of the explosion and resultant oil spill, the U.S. government placed a six-month moratorium on deepwater drilling operations in the Gulf of Mexico, which was lifted effective October 12, 2010. The U.S. government has also implemented additional safety and certification requirements applicable to drilling activities in the Gulf of Mexico. The extent to which these recent events may impact the Fund’s future results is uncertain. The Fund cannot predict how federal and state authorities will further respond to the incident or whether additional changes in laws and regulations governing oil and gas operations in the Gulf of Mexico will result. Such changes, if any, may impact the way the Fund conducts business and may increase the Fund’s cost of doing business.
Marketing/Customers
During 2010, the Fund had engaged a third-party marketer to sell the Fund’s proportionate share of oil and natural gas to the public market. The Fund did not contract to sell oil and natural gas to customers and therefore, had no customers or any one or few major customers upon which it depends. Effective December 2010, the Fund sells its oil and gas through an agent, Energy Upgrade, Inc.
The Fund’s current projects are near existing transportation infrastructure and pipelines. The Manager believes that it is likely that oil and natural gas from the Fund’s future projects will have access to pipeline transportation and can be marketed through its agent.
Natural gas is sold in the spot market at prevailing prices, which fluctuate with demand as a result of related industry variables. Oil is generally sold one month at a time at prevailing market prices. Historically, the markets for, and prices of, 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 that the Fund cannot control or influence; therefore, it is impossible to predict the future price of oil and natural gas with any certainty. Low commodity prices could have an adverse affect on the Fund’s future profitability.
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 producing, the operator of the project extracts oil and natural gas reserves throughout the year. Once extracted, oil and natural gas can be sold at any time during the year.
The Fund’s properties are located in the Gulf of Mexico; therefore, its operations and cash flows may be significantly impacted by hurricanes and other inclement weather. Such events may also have a detrimental impact on third-party pipelines and processing facilities, upon which the Fund relies to transport and process the oil and natural gas it produces. The National Hurricane Center defines hurricane season in the Gulf of Mexico as June through November. The Fund did not experience any damage or shut-ins, or production stoppages, due to hurricane activity in 2010.
Operator
The projects in which the Fund has invested are operated and controlled by unaffiliated third-party entities acting as operators. The operators are responsible for drilling, administration and production activities for leases jointly owned by working interest owners and act on behalf of all working interest owners under the terms of the applicable operating agreement. 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 producing properties are operated by LLOG Exploration Offshore, Inc. and BHP Billiton Petroleum Ltd.
Because the Fund does not operate any of the projects in which it has acquired an interest, shareholders 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 what it believes to be adequate insurance for the funds that it manages. The Manager has obtained hazard, property, general liability and other insurance in commercially reasonable amounts to cover its projects, as well as general liability, directors’ and officers’ 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. Further, for the policy periods August 2009 through July 2010 and August 2010 through July 2011, the Manager did not obtain coverage for named windstorm. As a result of the losses underwriters incurred from claims arising from Hurricane Ike, a named windstorm in September 2008, the Manager determined that the premiums sought by underwriters for, and the deductibles applicable to, coverage for named windstorm made obtaining such coverage for such policy period prohibitively expensive. 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. The Manager re-evaluates the insurance coverage on an annual basis. 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 be exhausted and become insufficient to cover a claim made by the Fund in a given year.
Salvage Fund
As to projects in which the Fund owns a working interest, the Fund deposits in a separate interest-bearing account, or salvage fund, cash to provide for the Fund’s proportionate share of the anticipated cost of dismantling production platforms and facilities, plugging and abandoning the wells, and removing the platforms, facilities and wells in respect of the projects after the end of their useful lives, in accordance with applicable federal and state laws and regulations. The Fund has deposited $1.0 million from capital contributions into a salvage fund, which, along with interest earned on this account, the Fund currently estimates to be sufficient to meet the Fund’s potential requirements. If, at any time, the Manager determines the salvage fund will not be sufficient to cover the Fund’s proportionate share of expense, the Fund may transfer amounts from capital contributions or operating income to fund the deficit. Payments to the salvage fund will reduce the amount of cash distributions that may be made to investors by the Fund. 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 or use of the salvage fund.
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 lease acquisitions from the BOE, 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 larger and have significant resources, they tend to focus more on projects that are larger, have greater reserve potential, and cost significantly more to explore and develop. The focus of these companies on larger projects does not necessarily mean that they will not investigate and/or acquire projects for which the Fund typically competes. The Manager is often able to win project participations ahead of such competitors for the following reasons: (i) Ridgewood Energy has an investment process that is not subject to the more layered decision-making processes that typically exist within larger oil and gas companies; such process enables Ridgewood Energy to assimilate financial, seismic and operational data in relation to a prospective project and efficiently assess the terms on which the project is being offered, which the Fund believes puts Ridgewood Energy in a position to reach an investment decision in advance of most large oil and gas companies, (ii) Ridgewood Energy is an active exploration and production participant in the Gulf of Mexico, and as a result, the management team is in regular contact with operators and is able to contribute perspectives both from a geological and operational viewpoint, and (iii) Ridgewood Energy is typically not viewed as a competitor by the syndicating operator, as Ridgewood Energy does not participate in lease block sales but principally invests in drill-ready syndicated projects.
Employees
The Fund has no employees as the Manager operates and manages the Fund.
Offices
The principal executive office of each of the Fund and the Manager is located at 14 Philips Parkway, Montvale, NJ 07645, and their phone number is 800-942-5550. The Manager leases additional office space at 11700 Old Katy Road, Houston, TX 77079. In addition, the Manager maintains leases for other offices that are used for administrative purposes for the Fund and other funds managed by the Manager.
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.
The Fund owns projects that are located in the offshore waters of the Gulf of Mexico on the OCS. The Fund’s operations and activities are therefore governed by the OCSLA and certain other laws and regulations. The Fund may own interests in properties located in state waters of the Gulf of Mexico, for which such states regulate drilling and operating activities by requiring, among other things, drilling permits and bonds and reports concerning operations. The laws of such states also govern a number of environmental and conservation matters, including the handling and disposing of waste materials, unitization and pooling of natural gas and oil properties, and the levels of production from natural gas and oil wells.
Outer Continental Shelf Lands Act
Under the 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 BOE, an agency of the United States Department of Interior. The BOE administers federal offshore leases pursuant to regulations promulgated under the OCSLA. Lessees must obtain BOE 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. The Fund is not involved in the process of obtaining any such approvals or permits. 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. BOE 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 BOE 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 BOE 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 BOE 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 duration of the lease, the amount of royalty to be paid, lease cancellation and suspension, and, to a limited 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 Oil and Natural Gas
The Fund sells its proportionate share of oil and natural gas to the market through an agent or a joint operating agreement and receives market prices from such sales. These sales are not currently subject to regulation by any federal or state agency. However, in order for the Fund to make such sales, it 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 OCSLA, the Natural Gas Policy Act of 1978 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 the Fund, although regulated, are beyond the Fund’s control. Nevertheless, such rates would apply uniformly to all transporters on that pipeline and, as a result, management does not anticipate that the impact to the Fund of any changes in such rates, terms or conditions would be materially different 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 may be 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 of 1990, as amended (the “OPA”), amends Section 311 of the Federal Water Pollution Control Act of 1972 (the “Clean Water Act”) and was enacted in response to the numerous tanker spills, including the Exxon Valdez spill, that occurred in the 1980s. Among other things, the OPA clarifies the federal response authority to, and increases penalties for, such 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 that 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 BOE, as the operators are responsible for such compliance. However, notwithstanding the operators’ responsibility for compliance, in the event of an oil spill, the Fund, along with the operators and other working interest owners, could be liable under the OPA for the resulting environmental damage.
Clean Water Act. Generally, the Clean Water Act imposes liability for the unauthorized discharge of pollutants, including 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. 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 of 1970, as amended (the “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 of 1976, as amended, 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 significant 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 thereunder. The Fund does not believe that the costs of compliance with applicable environmental laws, including federal, state and local laws, will have a material adverse impact on its financial condition and/or operations.
ITEM 1A.
ITEM 1A. RISK FACTORS
Not required.
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 under the headings “Project Information” and “Properties,” is incorporated herein by reference.
Drilling Activity
The following table sets forth the Fund’s drilling activity for the years ended December 31, 2010 and 2009. Gross wells are the total number of wells in which the Fund has an interest. Net wells are the sum of the Fund’s fractional working interests owned in the gross wells. All of the wells are located in the offshore waters of the Gulf of Mexico. During the years ended December 31, 2010 and 2009, the Fund had no drilling activity for developmental wells.
Unaudited Oil and Gas Reserve Quantities
The preparation of the Fund’s oil and gas reserve estimates are completed in accordance with the Fund’s internal control procedures over reserve estimation. The Fund’s management controls over proved reserve estimation include: 1) verification of input data that is provided to an independent petroleum engineering firm, 2) engagement of well-qualified and independent reservoir engineers for preparation of reserve reports annually in accordance with SEC reserve estimation guidelines and 3) a review of the reserve estimates by the Manager.
The primary technical person in charge of overseeing the Fund’s reserves estimates has a B.S. degree in Petroleum Engineering and is a member of the Society of Petroleum Engineers, the Association of American Drilling Engineers and the American Petroleum Institute. With over twenty years of industry experience, he is currently responsible for reserve reporting, engineering and economic evaluation of exploration and development opportunities, and the oversight of drilling and production operations.
The Fund’s reserve estimates at December 31, 2010 and 2009 were prepared by Ryder Scott Company, L.P., (“Ryder Scott”) an independent petroleum engineering firm. The information regarding the qualifications of the petroleum engineer is included within the report from Ryder Scott, which is included as Exhibit 99 of this Annual Report, and is incorporated herein by reference.
Proved oil and gas reserves are estimated quantities of oil and natural gas, which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed oil and gas reserves are those reserves expected to be recovered through existing wells with existing equipment and operating methods. The information regarding the Fund’s proved reserves, which is contained in Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” of this Annual Report under the heading “Critical Accounting Estimates - Proved Reserves”, is incorporated herein by reference. The information regarding the Fund’s unaudited net quantities of proved developed and undeveloped reserves, which is contained in Table III in the “Supplementary Financial Information - Information about Oil and Gas Producing Activities - Unaudited” included in Item 15. “Exhibits, Financial Statement Schedules” of this Annual Report, is incorporated herein by reference.
Proved Undeveloped Reserves. At December 31, 2010, the Fund had no proved undeveloped oil and natural gas reserves. At December 31, 2009, the Fund had approximately 400 barrels and 80 thousand mcf of proved undeveloped oil and natural gas reserves, respectively, attributable to South Marsh Island 111. During 2010, the Fund determined it was not economical to proceed with the development of the proved undeveloped oil and natural gas reserves related to South Marsh Island 111.
Production and Prices
The information regarding the Fund’s production of oil and natural gas, and certain price and cost information for the years ended December 31, 2010 and 2009 that is contained in Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” of this Annual Report under the headings “Results of Operations - Oil and Gas Revenue” and “Results of Operations - Operating Expenses” is incorporated herein by reference.
Delivery Commitments
As of December 31, 2010, the Fund had no obligations or delivery commitments under any existing contracts.
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, LLP, (“Perelson”) 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 Perelson. Thereafter, Perelson filed a counterclaim against the Manager on October 20, 2006, alleging breach of contract due to unpaid invoices in the amount of $326,554. During May 2010, a settlement was reached by the parties at no cost to the Fund. Legal costs related to this claim were borne by the Manager.
ITEM 4.
ITEM 4. (REMOVED AND RESERVED)
PART II
ITEM 5.
ITEM 5.
MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
There is currently no established public trading market for the Shares. As of the date of this filing, there were 856 shareholders of record of the Fund.
Distributions are made in accordance with the provisions of the LLC Agreement. At various times throughout the year, the Manager determines whether there is sufficient available cash as defined in the LLC Agreement, for distribution to shareholders. There is, however, no requirement to distribute available cash and as such, available cash is distributed to the extent and at such times as the Manager believes is advisable. During 2006, the Manager elected to waive its right to distributions of available cash from operations for the remaining life of the Fund. During the years ended December 31, 2010 and 2009, the Fund paid distributions to shareholders totaling $0.4 million and $2.1 million, respectively.
ITEM 6.
ITEM 6.
SELECTED FINANCIAL DATA
Not required.
ITEM 7.
ITEM 7.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Overview of the Fund’s Business
The Fund was organized to primarily acquire interests in oil and gas properties located in the United States offshore waters of Texas, Louisiana and Alabama in the Gulf of Mexico. The Fund’s primary investment objective is to generate cash flow for distribution to its shareholders by generating returns across a portfolio of exploratory or development oil and natural gas projects. However, the Fund is not required to make distributions to shareholders except as provided in the LLC Agreement.
The Manager performs certain duties on the Fund’s behalf including the evaluation of potential projects for investment and ongoing management, 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. See Item 1. “Business” of this Annual Report under the headings “Project Information” and “Properties” for more information regarding the projects of the Fund.
Revenues are subject to market pricing for oil and natural gas, which has been volatile, and is likely to continue to be volatile in the future. This volatility is caused by numerous factors and market conditions that the Fund cannot control or influence. Therefore, it is impossible to predict the future price of oil and natural gas with any certainty. Low commodity prices could have an adverse affect on the Fund’s future profitability.
Critical Accounting Estimates
The discussion and analysis of the Fund’s financial condition and results of operations are based upon the Fund’s financial statements, which have been prepared in conformity with accounting principles generally accepted in the United States of America (“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 its 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 actual results may differ from these estimates and assumptions and such differences may have a material impact on the results of operations, financial position, or cash flows. See Note 2 of Notes to Financial Statements - “Summary of Significant Accounting Policies” contained in Item 8. “Financial Statements and Supplementary Data” contained in this Annual Report 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 natural gas leasehold acreage, including lease bonuses, brokers’ fees and other related costs are capitalized. Annual lease rentals, exploration expenses and dry-hole costs are expensed as incurred. Costs of drilling and equipping productive wells and related production facilities are capitalized.
The costs of exploratory and developmental wells are capitalized pending determination of whether proved reserves have been found. 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 expensed as dry-hole costs. 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.
Unproved Property
Unproved property is comprised of capital costs incurred for undeveloped acreage, wells and production facilities in progress and wells pending determination. These costs are 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 unproved property balance on an ongoing basis for possible impairment or reduction in value.
Proved Reserves
Annually, the Fund engages an independent petroleum engineer, Ryder Scott, to perform a comprehensive study of the Fund’s proved properties to determine the quantities of reserves and the period over which such reserves will be recoverable. The Fund’s estimates of proved reserves are based on the quantities of oil and natural gas that 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 and future net revenues to change. Estimates of proved reserves are key components of the Fund’s most significant financial estimates involving its rate for recording depreciation, depletion and amortization.
Asset Retirement Obligations
For oil and 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 present value of asset retirement obligations once reasonably estimable. The Fund capitalizes the associated asset retirement costs as part of the carrying amount of its proved properties. Plug and abandonment costs associated with unsuccessful projects are expensed as dry-hole costs.
Impairment of Long-Lived Assets
The Fund reviews the value of its oil and gas properties whenever management determines that events and circumstances indicate that the recorded carrying value of properties may not be recoverable. Impairments of producing properties are determined by comparing future net undiscounted cash flows to the net book value at the end of each period. If the net book value exceeds the future net undiscounted cash flows, the carrying value of the property is written down to “fair value,” which is determined using net discounted future cash flows from the producing property. Different pricing assumptions, reserve estimates or discount rates could result in a different calculated impairment. The Fund provides for impairments on unproved properties when it determines that the property will not be developed or a permanent impairment in value has occurred. Given the volatility of oil and natural gas prices, it is reasonably possible that the Fund’s estimate of discounted future net cash flows from proved oil and natural gas reserves could change in the near term. If oil and natural gas prices decline significantly, even if only for a short period of time, it is possible that write-downs of oil and gas properties could occur.
Results of Operations
The following table summarizes the Fund’s results of operations for the years ended December 31, 2010 and 2009, and should be read in conjunction with the Fund’s financial statements and the notes thereto included within Item 8. “Financial Statements and Supplementary Data” contained in this Annual Report.
Overview. The Fund’s revenue, depletion and amortization, and lease operating expense were affected by the timing of the onset of production of the Fund’s wells and by the impact of well maintenance activities. During the year ended December 31, 2010, the Fund had six wells that produced for a total of 1,436 days, compared to seven wells that produced for a total of 2,038 days during the year ended December 31, 2009. The decrease in total production days was the result of one of the Fund’s wells being fully depleted at December 31, 2009 coupled with increased non-productive days related to maintenance activities. During the year ended December 31, 2010, the Fund's wells' production rate averaged 120 mcfe/producing day, compared to 262 mcfe/producing day during the year ended December 31, 2009. The decrease was primarily related to natural declines in production for two of the Fund’s wells, which were determined to be fully depleted at December 31, 2010.
Oil and Gas Revenue. Oil and gas revenue for the year ended December 31, 2010 was $0.9 million, a $1.4 million decrease from the year ended December 31, 2009. The decrease is attributable to the impact of decreased sales volumes totaling $1.6 million, partially offset by the impact of increased average prices totaling $0.2 million.
Oil sales volumes were 2 thousand barrels and 5 thousand barrels for the years ended December 31, 2010 and 2009, respectively. The Fund’s oil prices averaged $78 per barrel during the year ended December 31, 2010 compared to $53 per barrel during the year ended December 31, 2009.
Gas sales volumes were 146 thousand mcf and 492 thousand mcf for the years ended December 31, 2010 and 2009, respectively. The Fund’s gas prices averaged $4.89 per mcf during the year ended December 31, 2010 compared to $4.20 per mcf during the year ended December 31, 2009.
The decreases in oil and gas volumes were principally attributable to a reduction in the number of production days coupled with a decrease in the average production rate. See “Overview” above for additional information.
Depletion and Amortization. Depletion and amortization for the year ended December 31, 2010 was $0.7 million, a decrease of $2.2 million from the year ended December 31, 2009. The decrease resulted primarily from a decrease in production volumes totaling $2.0 million coupled with a decrease in average depletion rates totaling $0.2 million. The decrease in average depletion rates was primarily the result of the composite of productive wells coupled with a reduction in depletable costs resulting from impairments recorded during 2009.
Impairment of Oil and Gas Properties. During the year ended December 31, 2010, the Fund recorded impairments of oil and gas properties totaling $3.0 million, which were attributable to revisions in reserve estimates related to East Cameron 299, West Cameron 556, and South Marsh Island 111 and adjustments to asset retirement obligations for fully depleted wells. At December 31, 2010, the Fund’s independent petroleum engineer determined that both the East Cameron 299 and West Cameron 556 wells were fully depleted. During the year ended December 31, 2009 the Fund recorded impairments of oil and gas properties totaling $2.4 million, which were attributable to lower oil and gas commodity prices, revisions to reserve estimates, and adjustments to asset retirement obligations for fully depleted wells.
Operating Expenses. Operating expenses represent costs specifically identifiable or allocable to the Fund's wells, as detailed in the following table.
Lease operating expense was related to the Fund’s producing properties during each period as outlined above in “Overview”. The average production cost was $3.07 per mcfe during the year ended December 31, 2010 compared to $1.14 per mcfe during the year ended December 31, 2009. Workover expenses represent costs to restore or stimulate production of existing reserves of a proved property. During the years ended December 31, 2010 and 2009, workover expenses were attributable to East Cameron 299 and West Delta 67, respectively. Accretion expense is related to the asset retirement obligations established for the Fund’s proved properties. 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. At times, the Fund receives credits on certain wells from their respective operators upon review and audit of the wells’ costs.
General and Administrative Expenses. General and administrative expenses represent costs specifically identifiable or allocable to the Fund, as detailed in the following table.
Accounting fees represent audit and tax preparation fees, quarterly reviews and filing fees incurred by the Fund. Management reimbursement and other expenses relate primarily to reimbursements for various administrative costs incurred on the Fund’s behalf. Insurance expense represents premiums related to producing well and control of well insurance, which varies depending upon the number of wells producing or drilling, and directors’ and officers’ liability insurance.
Interest Income. Interest income is comprised of interest earned on money market accounts and investments in U.S. Treasury securities. Interest income for the year ended December 31, 2010 was $30 thousand, a $14 thousand decrease from the year ended December 31, 2009. The decrease was the result of a reduction in average outstanding balances earning interest, due to capital expenditures for oil and gas properties, coupled with lower interest rates earned.
Capital Resources and Liquidity
Operating Cash Flows
Cash flows provided by operating activities for the year ended December 31, 2010 were $0.3 million, primarily related to revenue received of $1.1 million, partially offset by operating expenses paid of $0.5 million and general and administrative expenses of $0.3 million.
Cash flows provided by operating activities for the year ended December 31, 2009 were $1.9 million, primarily related to revenue received of $2.6 million and favorable working capital of $0.2 million, partially offset by operating expenses of $0.6 million and general and administrative expenses of $0.3 million.
Investing Cash Flows
Cash flows used in investing activities for the year ended December 31, 2010 were $0.4 million, primarily related to capital expenditures for oil and gas properties, inclusive of advances.
Cash flows used in investing activities for the year ended December 31, 2009 were $0.3 million, primarily related to capital expenditures for oil and gas properties.
Financing Cash Flows
Cash flows used in financing activities for the year ended December 31, 2010 were $0.4 million, related to shareholder distributions.
Cash flows used in financing activities for the year ended December 31, 2009 were $2.1 million, related to shareholder distributions.
Estimated Capital Expenditures
The Fund has entered into multiple agreements for the drilling and development of its investment properties. The estimated expenditures associated with these agreements can vary depending on the stage of development on a property-by-property basis. As of December 31, 2010, the Fund had committed to spend an additional $0.2 million relating to its investment properties, principally all of which is expected to be spent during the next twelve months.
Capital expenditures for investment properties were funded with the capital raised by the Fund in its private placement offering, which is all the capital it will obtain. The number of projects in which the Fund can invest was limited and each unsuccessful project the Fund experienced reduced its ability to generate revenue and exhausted its capital.
Liquidity Needs
The Fund’s primary short-term liquidity needs are to fund its operations, inclusive of expenditures for its investment properties. Operations are funded utilizing operating income, existing cash on-hand and income earned therefrom.
Distributions, if any, are funded from available cash from operations, as defined in the LLC Agreement, and the frequency and amount are within the Manager’s discretion. During 2006, the Manager elected to waive its right to distributions of available cash from operations for the remaining life of the Fund.
Off-Balance Sheet Arrangements
The Fund had no off-balance sheet arrangements at December 31, 2010 and 2009 and does not anticipate the use of such arrangements in the future.
Contractual Obligations
The Fund enters into participation and joint 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 negotiate such contracts. No contractual obligations exist at December 31, 2010 and 2009 other than those discussed in “Estimated Capital Expenditures” above.
Recent Accounting Pronouncements
See Note 3 of Notes to Financial Statements - “Recent Accounting Standards” contained in Item 8. “Financial Statements and Supplementary Data” contained in this Annual Report for a discussion of recent accounting pronouncements.
ITEM 7A.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Not required.
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. “Exhibits, Financial Statement Schedules” and filed as part of this report.
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
ITEM 9A.
ITEM 9A. CONTROLS AND PROCEDURES
Disclosure Controls and Procedures
Under the supervision and with the participation of the Chief Executive Officer and Chief Financial Officer of the Fund, management of the Fund and the Manager carried out an evaluation of the effectiveness of the design and operation of the Fund’s disclosure controls and procedures as defined in Rule 13a-15(e) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”) as of December 31, 2010. Based upon the evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the Fund’s disclosure controls and procedures are effective as of the end of the period covered by this report.
Management's Report on Internal Control over Financial Reporting
Management of the Fund is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Exchange Act Rule 13a-15(f)). The Fund’s internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Management of the Fund, including its Chief Executive Officer and Chief Financial Officer, assessed the effectiveness of the Fund’s internal control over financial reporting as of December 31, 2010. In making this assessment, management of the Fund used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (the “COSO”) in Internal Control - Integrated Framework. Based on their assessment using those criteria, management of the Fund concluded that, as of December 31, 2010, the Fund’s internal control over financial reporting is effective.
This Annual Report does not include an attestation report of the Fund’s registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by the Fund’s registered public accounting firm pursuant to rules of the Securities and Exchange Commission that permit the Fund to provide only management’s report in this Annual Report.
Changes in Internal Control over Financial Reporting
The Chief Executive Officer and Chief Financial Officer of the Fund have concluded that there have not been any changes in the Fund’s internal control over financial reporting during the quarter ended December 31, 2010 that have materially affected, or are reasonably likely to materially affect, the Fund’s internal control over financial reporting.
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 the Manager. The Manager has very broad authority, including the authority to appoint the executive officers of the Fund. Executive officers of Ridgewood Energy and the Fund and their ages at December 31, 2010 are as follows:
The officers in the above table have also been officers of the Fund since March 1, 2004, the date of inception of the Fund, with the exception of Mr. Lang, who has been an officer of Ridgewood Energy and the Fund since June 2009. The officers are employed by and paid exclusively by the Manager. Set forth below is certain biographical information regarding the executive officers of Ridgewood Energy and the Fund:
Robert E. Swanson has served as the Chairman, Chief Executive Officer, and controlling shareholder of Ridgewood Energy since its inception and is the Chairman of the Investment Committee. Mr. Swanson is also the Chairman of Ridgewood Capital Management, LLC, and President of Ridgewood Securities Corporation, affiliates of Ridgewood Energy. 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.
Kenneth W. Lang has served as the President and Chief Operating Officer of Ridgewood Energy since June 2009 and is a member of the Investment Committee. Prior to joining the Fund, Mr. Lang was with BP for twenty-four years, ultimately serving for his last two years with BP as Senior Vice President for BP’s Gulf of Mexico business and a member of the Board of Directors for BP America, Inc. Prior to that, Mr. Lang was Vice President - Production for BP. After twenty-four years of service to BP, Mr. Lang retired and devoted fifteen months of personal time to pursue and explore other interests. Mr. Lang is a graduate of the University of Houston.
Kathleen P. McSherry has served as the Executive Vice President and Chief Financial Officer of Ridgewood Energy since 2001 and is a member of the Investment Committee. Ms. McSherry holds a Bachelor of Science degree in Accounting.
Robert L. Gold has served as the Executive Vice President of Ridgewood Energy since 1987 and is a member of the Investment Committee. 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. Mr. Gold is a graduate of Colgate University and New York University School of Law.
Daniel V. Gulino is Senior Vice President of Legal Affairs for Ridgewood Energy and has served as counsel for Ridgewood Energy since 2003. Mr. Gulino also serves as Senior Vice President of Legal Affairs of Ridgewood Capital Management and Senior Vice President & General Counsel of Ridgewood Securities Corporation. Mr. Gulino is a member of the New Jersey State and Pennsylvania State Bars. Mr. Gulino is a graduate of Fairleigh Dickinson University and Rutgers School of Law.
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” of this Annual Report for more information regarding Manager compensation and payments to affiliated entities.
ITEM 12.
ITEM 12.
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
Beneficial ownership is determined in accordance with the rules of the SEC and includes voting or investment power with respect to the securities. Percentage of beneficial ownership is based on 480.7046 shares outstanding at March 15, 2011. No officer of the Manager or the Fund owns any of the Shares and no person owns more than 5% of the Shares.
ITEM 13.
ITEM 13.
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
In accordance with the LLC Agreement, the Manager is entitled to an annual management fee equal to 2.5% of the total shareholder capital. During 2005, the Manager waived its management fee for the remaining life of the Fund. Upon the waiver of the management fee, the Fund began recording costs relating to services provided by the Manager for accounting and investor relations. Such costs totaled $80 thousand for each of the years ended December 31, 2010 and 2009, which were included in general and administrative expenses.
At times, short-term payables and receivables, which do not bear interest, arise from transactions with affiliates in the ordinary course of business.
None of the compensation paid to 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.
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 ACCOUNTING FEES AND SERVICES
The following table presents fees for services rendered by Deloitte & Touche LLP for the years ended December 31, 2010 and 2009.
(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 for consultations regarding the Fund’s disclosure controls and procedures in accordance with Section 906 of the Sarbanes-Oxley Act of 2002.
PART IV
ITEM 15.
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
(a) (1)
Financial Statements
See “Index to Financial Statements” set forth on page.
(a) (2)
Financial Statement Schedules
None.
(a) (3)
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
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 (Principal
March 15, 2011
Robert E. Swanson
Executive Officer)
/s/ KATHLEEN P. MCSHERRY
Executive Vice President and Chief
March 15, 2011
Kathleen P. McSherry
Financial Officer (Principal Financial
and Accounting Officer)
RIDGEWOOD ENERGY CORPORATION
/s/ ROBERT E. SWANSON
Chief Executive Officer of the Manager
March 15, 2011
Robert E. Swanson
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Shareholders and Manager of Ridgewood Energy K Fund, LLC:
We have audited the accompanying balance sheets of Ridgewood Energy K Fund, LLC (the “Fund”) as of December 31, 2010 and 2009, and the related statements of operations, changes in members’ capital, and cash flows for the years ended December 31, 2010 and 2009. 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 K Fund, LLC as of December 31, 2010 and 2009, and the results of its operations and its cash flows for the years ended December 31, 2010 and 2009, in conformity with accounting principles generally accepted in the United States of America.
/s/ Deloitte & Touche LLP
Parsippany, New Jersey
March 15, 2011
The accompanying notes are an integral part of these financial statements.
The accompanying notes are an integral part of these financial statements.
The accompanying notes are an integral part of these financial statements.
The accompanying notes are an integral part of these financial statements.
RIDGEWOOD ENERGY K FUND, LLC
NOTES TO FINANCIAL STATEMENTS
1. Organization and Purpose
The Ridgewood Energy K Fund, LLC ( the “Fund”), a Delaware limited liability company, was formed on March 1, 2004 and operates pursuant to a limited liability company agreement (the “LLC Agreement”) dated April 1, 2004 by and among Ridgewood Energy Corporation (the “Manager”) and the shareholders of the Fund. The Fund was organized to acquire interests in oil and gas properties located in the United States offshore waters of Texas, Louisiana and Alabama in the Gulf of Mexico.
The Manager has direct and exclusive control over the management of the Fund’s operations. With respect to project investments, the Manager locates potential projects, conducts due diligence and negotiates and completes the transactions in which the investments are made. The Manager performs, or arranges for the performance of, the management, advisory 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 unaffiliated custodians, depositories, accountants, attorneys, broker-dealers, corporate fiduciaries, insurers, banks and others as required. See Notes 2, 6 and 8.
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 (“GAAP”) 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 revenue and expense during the reporting period. On an ongoing basis, the Manager reviews its estimates, including those related to property balances, determination of proved reserves, impairments and asset retirement obligations. Actual results may differ from those estimates.
Cash and Cash Equivalents
All highly liquid investments with maturities, when purchased, of three months or less are considered cash and cash equivalents. At times, deposits may be in excess of federally insured limits. Federally insured limits of the Fund’s deposits are $250 thousand per insured financial institution. At December 31, 2010, the Fund’s bank balances exceeded federally insured limits by $2.0 million, principally all of which was invested in money market accounts that invest solely in U.S. Treasury bills and notes.
Salvage Fund
The Fund deposits in a separate interest-bearing account, or salvage fund, money to provide for the dismantling and removal of production platforms and facilities and plugging and abandoning its wells at the end of their useful lives, in accordance with applicable federal and state laws and regulations. At December 31, 2010, the Fund had investments in U.S. Treasury securities within its salvage fund that are classified as held-to-maturity, of $1.1 million, which mature in February 2012. Held-to-maturity investments are those securities that the Fund has the ability and intent to hold until maturity, and are recorded at cost plus accrued income, adjusted for the amortization of premiums and discounts, which approximates fair value.
Interest earned on the account will become part of the salvage fund. There are no restrictions on withdrawals from the salvage fund.
Oil and Gas Properties
The Fund invests in oil and gas properties, which are operated by unaffiliated entities that 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 is billed by operators.
The successful efforts method of accounting for oil and gas producing activities is followed. Acquisition costs are capitalized when incurred. Other oil and 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 as dry-hole costs. Costs to develop proved reserves, including the costs of all development wells and related facilities and equipment used in the production of oil and 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, the cost and related accumulated depletion and amortization will be eliminated from the property accounts, and the resultant gain or loss is recognized. Upon the sale or retirement of an unproved property, gain or loss on the sale is recognized.
Capitalized acquisition costs of producing oil and gas properties are depleted by the units-of-production method.
At December 31, 2010 and 2009, amounts recorded in due to operators totaling $2 thousand and $0.1 million, respectively, related to capital expenditures for oil and gas properties.
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 may be required to advance its share of estimated cash expenditures 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 reclassified to unproved or proved properties.
Asset Retirement Obligations
For oil and 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. The following table presents changes in asset retirement obligations for the years ended December 31, 2010 and 2009.
As indicated above, the Fund maintains a salvage fund to provide for the funding of future asset retirement obligations.
Syndication Costs
Syndication costs are direct costs incurred by the Fund in connection with the offering of the Fund’s shares, including professional fees, selling expenses and administrative costs payable to the Manager, an affiliate of the Manager and unaffiliated broker-dealers, which are reflected on the Fund’s balance sheet as a reduction of shareholders’ capital.
Revenue Recognition and Imbalances
Oil and gas revenues are recognized when oil and gas is sold to a purchaser at a fixed or determinable price, when delivery has occurred and title has transferred, and if collectibility of the revenue is probable. The Fund uses the sales method of accounting for gas production imbalances. The volumes of gas sold may differ from the volumes to which the Fund is entitled based on its interests in the properties. These differences create imbalances that are recognized as a liability only when the properties’ estimated remaining reserves net to the Fund will not be sufficient to enable the underproduced owner to recoup its entitled share through production. The Fund’s recorded liability, if any, would be reflected in other liabilities. No receivables are recorded for those wells where the Fund has taken less than its share of production.
Impairment of Long-Lived Assets
The Fund reviews the value of its oil and gas properties whenever management determines that events and circumstances indicate that the recorded carrying value of properties may not be recoverable. Impairments of producing properties are determined by comparing future net undiscounted cash flows to the net book value at the time of the review. If the net book value exceeds the future net undiscounted cash flows, the carrying value of the property is written down to fair value, which is determined using net discounted future cash flows from the producing property. The Fund provides for impairments on unproved properties when it determines that the property will not be developed or a permanent impairment in value has occurred. The fair value determinations require considerable judgment and are sensitive to change. Different pricing assumptions, reserve estimates or discount rates could result in a different calculated impairment. Given the volatility of oil and natural gas prices, it is reasonably possible that the Fund’s estimate of discounted future net cash flows from proved oil and natural gas reserves could change in the near term. If oil and natural gas prices decline significantly, even if only for a short period of time, it is possible that write-downs of oil and gas properties could occur.
During the year ended December 31, 2010, the Fund recorded impairments of oil and gas properties totaling $3.0 million, which were attributable to revisions in reserve estimates related to East Cameron 299, West Cameron 556, and South Marsh Island 111 and adjustments to asset retirement obligations for fully depleted wells. At December 31, 2010, the Fund’s independent petroleum engineer determined that both the East Cameron 299 and West Cameron 556 wells were fully depleted. During the year ended December 31, 2009 the Fund recorded impairments of oil and gas properties totaling $2.4 million, which were attributable to lower oil and gas commodity prices, revisions to reserve estimates, and adjustments to asset retirement obligations for fully depleted wells. The fair value of the impaired wells was determined based on level 3 inputs, which include projected income from reserves utilizing forward price curves, net of anticipated costs, discounted.
Depletion and Amortization
Depletion and amortization of the cost of proved oil and gas properties are calculated using the units-of-production method. Proved developed reserves are used as the base for depleting capitalized costs associated with successful exploratory well 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.
Income Taxes
No provision is made for income taxes in the financial statements. The Fund is a limited liability company, and as such, the Fund’s income or loss is passed through and included in the tax returns of the Fund’s shareholders.
Income and Expense Allocation
Profits and losses are allocated 85% to shareholders in proportion to their relative capital contributions and 15% to the Manager, except for interest income and certain expenses, such as dry-hole costs, trust fees, depletion and amortization, which are allocated 99% to shareholders and 1% to the Manager.
3. Recent Accounting Standards
In January 2010, the Financial Accounting Standards Board (“FASB”) issued guidance on improving disclosures about fair value measurements. This guidance has new requirements for disclosures related to recurring or nonrecurring fair-value measurements including significant transfers into and out of Level 1 and Level 2 fair-value measurements and information on purchases, sales, issuances, and settlements in a rollforward reconciliation of Level 3 fair-value measurements. This guidance was effective beginning January 1, 2010. The Level 3 reconciliation disclosures are effective for fiscal years beginning after December 15, 2010, which will be effective for the Fund December 31, 2011. The adoption of the guidance is not expected to have a material impact on the Fund’s financial statements.
4. Oil and Gas Properties
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. At December 31, 2010 or 2009, the Fund had no unproved properties.
Capitalized exploratory well 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. At times, the Fund receives credits on certain wells from their respective operators upon review and audit of the wells’ costs. The Fund had credits to dry-hole costs of $3 thousand and $16 thousand during the years ended December 31, 2010 and 2009, respectively.
5. Distributions
Distributions to shareholders are allocated in proportion to the number of shares held. The Manager determines whether available cash from operations, as defined in the LLC Agreement, will be distributed. Such distributions are allocated 85% to the shareholders and 15% to the Manager, as required by the LLC Agreement. During 2006, the Manager elected to waive its right to distributions of available cash from operations for the remaining life of the Fund.
Available cash from dispositions, as defined in the 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.
6. Related Parties
In accordance with the LLC Agreement, the Manager is entitled to an annual management fee equal to 2.5% of the total shareholder capital. During 2005, the Manager waived its management fee for the remaining life of the Fund. Upon the waiver of the management fee, the Fund began recording costs relating to services provided by the Manager for accounting and investor relations. Such costs totaled $80 thousand for each of the years ended December 31, 2010 and 2009, which were included in general and administrative expenses.
At times, short-term payables and receivables, which do not bear interest, arise from transactions with affiliates in the ordinary course of business.
None of the compensation paid to 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.
7. Fair Value Measurements
At December 31, 2010 and 2009, cash and cash equivalents, production receivable, salvage fund, accrued expenses and other liabilities approximate fair value.
8. Commitments and Contingencies
Capital Commitments
The Fund has entered into multiple agreements for the drilling and development of its investment properties. The estimated capital expenditures associated with these agreements vary depending on the stage of development on a property-by-property basis. As of December 31, 2010, the Fund had committed to spend an additional $0.2 million related to its investment properties, principally all of which is expected to be spent during the next twelve months.
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 operators of the Fund’s properties 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 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. At December 31, 2010 and 2009, there were no known environmental contingencies that required the Fund to record a liability.
In response to the recent oil spill in the Gulf of Mexico, the United States Congress is considering a number of legislative proposals relating to the upstream oil and gas industry both onshore and offshore. Such proposals could result in significant additional laws or regulations governing the Fund’s operations in the United States, including a proposal to raise or eliminate the cap on liability for oil spill cleanups under the Oil Pollution Act of 1990. Although it is not possible at this time to predict whether proposed legislation or regulations will be adopted as initially written, if at all, or how legislation or new regulation that may be adopted would impact our business, any such future laws and regulations could result in increased compliance costs or additional operating restrictions, which could have a material adverse effect on the Fund’s operating results and cash flows.
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 that 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 funds managed by the Manager. Claims made by other funds managed by the Manager can reduce or eliminate insurance for the Fund.
9. Subsequent Events
The Fund has assessed the impact of subsequent events through the date of issuance of its financial statements, and has concluded that there were no such events that require adjustment to, or disclosure in, the notes to the financial statements.
Ridgewood Energy K Fund, LLC
Supplementary Financial Information
Information about Oil and Gas Producing Activities - Unaudited
In accordance with the Financial Accounting Standards Board guidance on disclosures of oil and gas producing activities, this section provides supplementary information on oil and gas exploration and producing activities of the Fund. The Fund is engaged solely in oil and gas activities, all of which are currently located in the United States offshore waters of Louisiana in the Gulf of Mexico.
Table III - Reserve Quantity Information
Oil and gas reserves of the Fund have been estimated by an independent petroleum engineer, Ryder Scott Company, L.P. at December 31, 2010 and 2009. These reserve disclosures have been prepared in compliance with the Securities and Exchange Commission rules. Due to 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 Relating to Proved Oil and Gas Reserves
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. At December 31, 2010 and 2009, future cash inflows were determined based on average first-of-the-month prices for the prior twelve-month period. Future production and development costs are derived based on current costs assuming continuation of existing economic conditions.
Table V - Changes in the Standardized Measure for Discounted Cash Flows
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 as the computations are based on a number of estimates. 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 and governmental control. Actual future prices and costs are likely to be substantially different from the current price and cost estimates 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 limitation inherent therein.