ITEM 1. BUSINESS
Overview
The Fund is a Delaware limited liability company (“LLC”) formed on August 30, 2007 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 January 2, 2008, selling whole and fractional shares of membership interests (“Shares”), consisting of Limited Liability Shares of Membership Interests (“Limited Liability Shares”) and Investor GP Shares of Membership Interests (“Investor GP Shares”), primarily at $200 thousand per whole Share. The Limited Liability Shares and the Investor GP Shares constitute a single class of securities as defined in Section 12(g) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). In January 2015, pursuant to the LLC Agreement, Ridgewood Energy Corporation, as manager of the Fund converted all then outstanding Investor GP Shares to Limited Liability Shares. 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 April 30, 2008. The Fund raised $94.7 million and after payment of $15.4 million in offering fees, commissions and investment fees, the Fund had $79.3 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. 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. Historically when the Fund had sought project investment, the Manager located potential projects, conducted due diligence, and negotiated the investment transactions with respect to those projects. 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.
As compensation for its services, the Manager is entitled to an annual management fee, payable monthly, equal to 2.5% of the total capital contributions made by the Fund’s shareholders, net of cumulative dry-hole and related well costs incurred by the Fund. The Manager is entitled to receive an annual management fee from the Fund regardless of the Fund’s profitability in that year. Management fees for each of the years ended December 31, 2014 and 2013 were $1.3 million. Additionally, the Manager is entitled to receive a 15% interest in cash distributions from operations made by the Fund. Distributions paid to the Manager for the years ended December 31, 2014 and 2013 were $0.4 million and $0.8 million, respectively.
In addition to the management fee, 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 Securities Exchange Commission (“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.
Business Strategy
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. 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. The Fund has invested in the drilling and development of both shallow and deepwater oil and natural gas projects in the U.S. offshore waters of Texas, Louisiana, and Alabama in the Gulf of Mexico, in partnership with exploration and production companies. At December 31, 2014, the Fund’s participation in investments in oil and natural gas properties had been completely identified and contracted and the balance of the Fund’s capital has been fully allocated to complete such projects and since that time, the Fund has not investigated or invested in, and does not expect in the future to investigate or invest in, any additional projects, other than those in which the Fund currently has a working interest.
The Fund has invested its capital with operators through working interest joint ventures with such operators and, in some cases, other energy companies that also own or acquire working interests in the projects. A working interest is an undivided fractional interest in a lease block acquired from the U.S. government or from an operator that has acquired the working interest. A working interest includes the right to drill, produce and conduct operating activities and share in any resulting oil and natural gas production. Operators will generally retain 25% to 50% interests in multiple drilling projects, rather than 100% interests in a few projects, in order to share risk, obtain independent technical validation and stretch exploration budgets that are split across numerous regions of the world.
Investment Committee
Ridgewood Energy 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”). Two members of the Investment Committee are based out of the Manager’s Montvale, New Jersey office and three members are based out of the Manager’s Houston, Texas office. Currently, the Investment Committee activities surrounding the Fund are principally related to the development and operation of properties for which it already has a working interest.
Participation and Joint Operating Agreements
Ridgewood Energy negotiates participation and joint operating agreements with the goal of achieving the best possible economics and governance rights for the Fund in connection with acquiring the interest. Under the joint operating agreement, proposals and decisions are generally made based on percentage ownership approvals and although an operator’s percentage ownership may constitute a majority ownership, operators generally seek consensus relating to project decisions. As a result, Ridgewood Energy and other partners generally retain the right to make proposals and influence decisions involving certain operational matters associated with a project. This approval discretion and the operator’s desire to execute the project efficiently and expeditiously can function to limit the operator’s inclination to act on its own, or against the interests of the participants in the project.
Project Information
Existing projects are located in the waters of the Gulf of Mexico, offshore Louisiana, on the Outer Continental Shelf (“OCS”). The Outer Continental Shelf Lands Act (“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. See further discussion under the heading “Regulation” in this 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. 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 exploratory 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 12.5%, 16.67% or 18.75% royalty to the Bureau of Ocean Energy Management (“BOEM”) depending on the lease. Other than BOEM royalties, the Fund does not have material royalty burdens.
Deep Gas Royalty Relief
On January 26, 2004, the BOEM promulgated a rule providing incentives for companies to increase deep natural gas production in the Gulf of Mexico (the "Royalty Relief Rule"). The Royalty Relief Rule does not extend to deep waters of the Gulf of Mexico off the Outer Continental Shelf nor does it apply if the price of natural gas exceeds $11.35 (estimated) Million British Thermal Units (“mmbtu”), adjusted annually for inflation. The Fund currently has two leases, the Liberty and Carrera projects, which qualify for royalty relief under the Royalty Relief Rule.
Deepwater Royalty Relief
In addition to the Royalty Relief Rule, the Deep Water Royalty Relief Act of 1995 (the “Deepwater Relief Act”) was enacted to promote exploration and production of oil and natural gas in the deepwater of the Gulf of Mexico and relieves eligible leases from paying royalties to the U.S. Government on certain defined amounts of deepwater production. The Deepwater Relief Act expired in the year 2000 but was extended for qualified leases by the BOEM to promote continued interest in deepwater. The Fund currently has one lease, the Liberty Project, which qualifies for royalty relief under the Deepwater Relief Act.
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, 2014. Productive wells are producing wells and wells mechanically capable of production. Gross wells are the total number of wells in which the Fund owns a working 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.
During January 2015, the Fund determined that the Carrera Project, one of the productive wells included in the table above, was no longer mechanically capable of producing.
Acreage Data
The following table sets forth the Fund’s interests in developed and undeveloped oil and gas acreage as of December 31, 2014. Gross acres are the total number of acres in which the Fund owns a working interest. Net acres are the sum of the fractional working interests owned in gross acres. 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. The budget for each project is inclusive of estimated asset retirement obligations.
Marketing/Customers
The Manager, on behalf of the Fund, has engaged Energy Upgrade, Inc. to market the Fund’s oil and natural gas. The number of customers purchasing the Fund’s oil and natural gas may vary from time to time. Currently, and during 2014, the Fund had two major customers in the public market. Because a ready market exists for oil and natural gas, the Fund does not believe that the loss of any individual customer would have a material adverse effect on its financial position or results of operations.
The Fund’s current producing projects are near existing transportation infrastructure and pipelines. The Manager believes that oil and natural gas from the Fund’s non-producing projects will have access to pipeline transportation and will be marketed through Energy Upgrade, Inc. The Fund is participating in the financing of both platform and pipeline infrastructure for its non-producing projects.
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 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 effect on the Fund’s future profitability. Historically, the Fund has entered, and in the future, may continue to enter, into transactions, or derivative contracts, that fix the future prices or establish a price floor for portions of its oil or natural gas production.
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, shut-ins, or production stoppages due to hurricane activity in 2014.
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 properties are operated by Deep Gulf Energy LP and LLOG Exploration Offshore, L.L.C.
Because the Fund does not operate any of the projects in which it has acquired a working 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 to cover the risks associated with the Fund’s passive investments, including those of the Fund. Although the Fund is not an operator, the Manager has, nonetheless, 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 its 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. 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
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. As of December 31, 2014, the Fund has deposited $1.5 million from capital contributions and reinvested interest into a salvage fund. As a result of the significant capital required and number of wells anticipated for the Diller and Marmalard projects, any further contributions to the salvage fund will reduce the amount of cash distributions that would 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 and the Manager. 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. The Fund, through its Manager has competed with other companies for the acquisition of leases as well as percentage ownership interests in oil and natural gas working interests in the secondary market. The Fund does not anticipate the acquisition of any additional ownership interests in oil and natural gas working interests as its capital has been fully allocated to current and past projects.
Employees
The Fund has no employees. The Manager operates and manages the Fund.
Offices
The principal administrative office of both 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 1254 Enclave Parkway, Houston, TX 77077 and also owns additional office space at 79 Turtle Point, Tuxedo Park, NY, 10987. 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, production and transportation 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.
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 BOEM, an agency of the United States Department of Interior (the “Department of Interior”). Federal offshore leases are managed both by the BOEM and the Bureau of Safety and Environmental Enforcement (the “BSEE”) pursuant to regulations promulgated under the OCSLA. The OCSLA authorizes regulations relating to safety and environmental protection applicable to lessees and permittees operating on the OCS. Specific design and operational standards may apply to OCS vessels, rigs, platforms, vehicles and structures. The BSEE regulates the design and operation of well control and other equipment at offshore production sites, implementation of safety and environmental management systems, and mandatory third-party compliance audits, among other requirements. BSEE has proposed stricter requirements for subsea drilling production equipment and has indicated that there will be an additional, separate rulemaking to govern the design, performance and maintenance of blowout preventers, but that rule has not yet been published. BSEE has also published a draft statement of policy on safety culture with nine proposed characteristics of a robust safety culture. Violations of environmentally related lease conditions or regulations issued pursuant to the OCSLA can result in substantial civil and criminal penalties as well as potential court injunctions curtailing operations and the cancellation of leases. Such enforcement liabilities, delay or restriction of activities can result from either governmental or citizen prosecution.
Sales and Transportation of Oil and Natural Gas
The Fund sells its proportionate share of oil and natural gas to the market through a marketer 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 Act of 1938, The Natural Gas Policy Act of 1978 and the Energy Policy Acts of 1992 and 2005. 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 described below:
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, as amended (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. OPA imposes strict, joint and several liabilities on “responsible parties” for damages, including natural resource damages, resulting from oil spills into or upon navigable waters, adjoining shorelines or in the exclusive economic zone of the United States. A “responsible party” includes the owner or operator of an onshore facility and the lessee or permit holder of the area in which an offshore facility is located. The OPA establishes a liability limit for onshore facilities of $350 million, while the liability limit for offshore facilities is equal to all removal costs plus up to $75 million in other damages. These liability limits may not apply if a spill is caused by a party’s gross negligence or willful misconduct, if the spill resulted from violation of a federal safety, construction or operating regulation, or if a party fails to report a spill or to cooperate fully in a clean-up. Regulations under the OPA require owners and operators of rigs in United States waters to maintain certain levels of financial responsibility. The failure to comply with the OPA’s requirements may subject a responsible party to civil, criminal, or administrative enforcement actions. The Fund is not aware of any action or event that would subject us to liability under the OPA, and the Fund believes that compliance with the OPA’s financial assurance and other operating requirements will not have a material impact on its operations or financial condition.
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, as amended, 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 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 its environmental, health and safety risks are materially different from those of comparable companies in the United States in the offshore oil and gas industry. However, there are no assurances that the environmental regulations described above will not result in curtailment of production or material increases in the costs of production, development or exploration, or otherwise have a material adverse effect on the Fund’s operating results and cash flows.
Dodd-Frank Act. The Dodd-Frank Act, signed into law in July 2010, among other provisions, establishes federal oversight and regulation of the over-the-counter derivatives market and entities that participate in that market and, in addition, requires certain additional SEC reporting requirements.
The Fund has the authority to utilize derivative instruments to manage the price risk attributable to its oil and gas production. Dodd-Frank mandates that many derivatives be executed in regulated markets and submitted for clearing to regulated clearinghouses. Derivatives will be subject to minimum daily margin requirements set by the relevant clearinghouse and, potentially, by the SEC or the CFTC, and derivatives dealers may demand the unilateral ability to increase margin requirements beyond any regulatory or clearinghouse minimums. In addition, as required by Dodd-Frank, the CFTC has set “speculative position limits” (limits imposed on the maximum net long or net short speculative positions that a person may hold or control with respect to futures or options contracts traded on the U.S. commodities exchange) with respect to most energy contracts. These requirements under Dodd-Frank could significantly increase the cost of any derivatives transactions of the Fund (including through requirements to post collateral, which could adversely affect the Fund’s liquidity), materially alter the terms of derivatives transactions and make it more difficult for the Fund to enter into customized transactions, cause the Fund to liquidate certain positions it may hold, reduce the ability of the Fund to protect against price volatility and other risks by making certain hedging strategies impossible or so costly that they are not economical to implement, and increase the Fund’s exposure to less creditworthy counterparties. If the Fund alters any hedging program as a result of the legislation and regulations, the Fund’s operations may become more volatile and its cash flows may be less predictable, which could adversely affect the Fund’s performance.
ITEM 1A.
ITEM 1A. RISK FACTORS
Not required.
ITEM 1B.
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
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, 2014 and 2013. 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 in-progress at December 31, 2014 and 2013 are expected to produce both oil and natural gas, and are located in the offshore waters of the Gulf of Mexico. See Item 1. “Business” of this Annual Report under the heading “Properties” for more information about wells in-progress at December 31, 2014.
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 Manager’s primary technical person in charge of overseeing the Fund’s reserve 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-five 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, 2014 and 2013 were prepared by Netherland, Sewell & Associates, Inc. (“NSAI”), an independent petroleum engineering firm. The information regarding the qualifications of the petroleum engineer is included within the report from NSAI, which is filed as Exhibit 99.1 to 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 8. “Financial Statements and Supplementary Data” of this Annual Report, is incorporated herein by reference.
Proved Undeveloped Reserves. At December 31, 2014, the Fund had approximately 477 thousand barrels and 1.2 million mcf of proved undeveloped oil and natural gas reserves, respectively. At December 31, 2013, the Fund had approximately 468 thousand barrels and 1.1 million mcf of proved undeveloped oil and natural gas reserves, respectively. Such reserves are related to the Diller and Marmalard projects, which were determined to be discoveries in 2012.
During the year ended December 31, 2014, the Fund incurred costs to advance the development of proved undeveloped reserves of approximately $2.1 million, which related to the Diller and Marmalard projects. Information regarding estimated future development costs relating to the development of the Fund’s non-producing properties, which is contained in Item 1. “Business” of this Annual Report under the heading “Properties”, is incorporated herein by reference. Estimated future development costs include capital spending on major development projects, some of which will take several years to complete. Proved undeveloped reserves related to major development projects will be reclassified to proved developed reserves when production commences.
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, 2014 and 2013 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 - Overview” and “Results of Operations - Operating Expenses” is incorporated herein by reference.
Delivery Commitments
As of December 31, 2014, the Fund had no delivery obligations or delivery commitments under any existing contracts.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS
None.
ITEM 4.
ITEM 4. MINE SAFETY DISCLOSURES
None.
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 1,303 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. Due to the significant capital required to develop the Diller and Marmalard projects, distributions have been impacted, and will be impacted in the future, by amounts reserved to provide for their ongoing development costs and funding their estimated asset retirement obligations. There is 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 the years ended December 31, 2014 and 2013, the Fund paid distributions totaling $2.4 million and $5.3 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 primarily 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 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, or arranges for the performance of, the management, advisory and administrative services required for Fund operations. 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.
Factors affecting market pricing for oil and natural gas include:
·
weather conditions;
·
economic conditions, including demand for petroleum-based products;
·
actions by OPEC, the Organization of Petroleum Exporting Countries;
·
political instability in the Middle East and other major oil and gas producing regions;
·
governmental regulations, both domestic and foreign;
·
domestic and foreign tax policy;
·
the pace adopted by foreign governments for the exploration, development, and production of their national reserves;
·
the price of foreign imports of oil and gas;
·
the cost of exploring for, producing and delivering oil and gas;
·
the discovery rate of new oil and gas reserves;
·
the rate of decline of existing and new oil and gas reserves;
·
available pipeline and other oil and gas transportation capacity;
·
the ability of oil and gas companies to raise capital;
·
the overall supply and demand for oil and gas; and
·
the availability of alternate fuel sources.
Changes in commodity prices may significantly affect liquidity and expected operating results. Price changes will directly affect revenues. Reductions in oil and gas prices not only reduce revenues and profits, but could also reduce the quantities of reserves that are commercially recoverable. Significant declines in prices could result in non-cash charges to earnings due to impairment.
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 1 of “Notes to Financial Statements” - “Organization and Summary of Significant Accounting Policies” contained in Item 8. “Financial Statements and Supplementary Data” within this Annual Report for a discussion of the Fund’s significant accounting policies.
Accounting for Exploration, Development and Acquisition Costs
Exploration, development and acquisition costs 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. Costs of drilling and equipping productive wells and related production facilities are capitalized. Annual lease rentals and exploration expenses are expensed as incurred. Costs of developing production facilities and pipelines that service multiple oil and gas properties are segregated as “Equipment and facilities - in progress.”
Proved Reserves
Estimates of proved reserves are key components of the Fund’s most significant financial estimates involving its rate for recording depletion and amortization. Annually, the Fund engages an independent petroleum engineer 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.
Asset Retirement Obligations
Asset retirement obligations include costs to plug and abandon the Fund’s wells and to dismantle and relocate or dispose of the Fund’s production platforms and related structures and restoration costs of land and seabed. The Fund develops estimates of these costs based upon the type of production structure, water depth, reservoir depth and characteristics, and ongoing discussions with the wells’ operators. Because these costs typically extend many years into the future, estimating these future costs is difficult and requires significant judgment that is subject to future revisions based upon numerous factors, including changing technology and the political and regulatory environment. Estimates are reviewed on a bi-annual basis, or more frequently if an event occurs that would dictate a change in assumptions or estimates.
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 proved 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 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.
Results of Operations
The following table summarizes the Fund’s results of operations for the years ended December 31, 2014 and 2013, 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” in this Annual Report.
Overview. The following table provides information related to the Fund’s oil and gas production and oil and gas revenue during the years ended December 31, 2014 and 2013. Natural gas liquid (“NGL”) sales are included within gas sales.
The decreases in production days and sales volume were primarily attributable to the Carrera Project, which was shut-in periodically throughout 2014 due to ongoing mechanical issues and various repair and maintenance activities. During January 2015, the Fund determined that the Carrera Project was no longer mechanically capable of producing and has determined that the well was fully impaired at December 31, 2014. See Item 1. “Business” of this Annual Report under the heading “Properties” for more information.
Oil and Gas Revenue. Oil and gas revenue for the year ended December 31, 2014 was $5.2 million, a decrease of $2.3 million from the year ended December 31, 2013. The decrease was attributable to decreased sales volume totaling $1.7 million coupled with the impact of the change in average prices totaling $0.6 million. See “Overview” above for additional information.
Depletion, Depreciation and Amortization. Depletion, depreciation and amortization for the year ended December 31, 2014 was $1.3 million, a decrease of $0.1 million from the year ended December 31, 2013. The decrease resulted from a decrease in production volumes totaling $0.3 million, partially offset by an increase in average depletion rates totaling $0.2 million. The increase in average depletion rates was attributable to increased estimated asset retirement costs coupled with decreases in reserve estimates. See “Overview” above for additional information.
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. At times, the Fund receives adjustments to certain wells from their respective operators upon review and audit of the wells’ costs. During the year ended December 31, 2014, dry-hole costs were $36 thousand. During the year ended December 31, 2013, dry-hole costs of $1.9 million related to the Staurolite Project.
Impairment of Oil and Gas Properties. During January 2015, the Carrera Project was shut-in due to ongoing mechanical issues related to a blockage in the flowline. Upon evaluation, it was determined that estimated costs to bring the well back on production were not economic relative to the remaining reserves and the well was fully impaired. Accordingly, during the year ended December 31, 2014, the Fund recorded an impairment of oil and gas properties of $1.6 million, representing the remaining net book value at the date of impairment. There were no impairments of oil and gas properties during the year ended December 31, 2013.
Management Fees to Affiliate. Management fees for each of the years ended December 31, 2014 and 2013 were $1.3 million. An annual management fee, totaling 2.5% of total capital contributions, net of cumulative dry-hole and related well costs incurred by the Fund, is paid monthly to the Manager.
Operating Expenses. Operating expenses represent costs specifically identifiable or allocable to the Fund’s wells, as detailed in the following table.
Lease operating expense relates to the Fund’s producing properties during each period as outlined above in “Overview”. The average production cost was $13.65 per barrel of oil equivalent (“BOE”) during the year ended December 31, 2014 compared to $11.22 per BOE during the year ended December 31, 2013. Accretion expense related to the asset retirement obligations established for the Fund’s proved properties. Geological costs represent costs incurred to obtain seismic data, surveys and lease rentals.
Workover Expense. Workover expense represents costs to restore or stimulate production of existing reserves. Workover expense of $0.4 million during the year ended December 31, 2014 related to the Carrera Project. Workover expense of $0.6 million during the year ended December 31, 2013 related to the Carrera and Liberty projects.
General and Administrative Expenses. General and administrative expenses represent costs specifically identifiable or allocable to the Fund, as detailed in the following table.
Accounting and professional fees represent expenses for audits, quarterly reviews, tax preparation, reserve data engineering and reporting, and administration of filings. 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. Trust fees represent bank fees associated with the management of the Fund’s cash accounts.
Interest Income. Interest income is comprised of interest earned on cash and cash equivalents, salvage fund and held-to-maturity investments.
Capital Resources and Liquidity
Operating Cash Flows
Cash flows provided by operating activities for the year ended December 31, 2014 were $2.5 million, primarily related to revenue received of $5.3 million, partially offset by management fees of $1.3 million, operating expenses paid of $0.9 million, workover expense paid of $0.4 million and general and administrative expenses paid of $0.2 million.
Cash flows provided by operating activities for the year ended December 31, 2013 were $4.9 million, primarily related to revenue received of $8.4 million, partially offset by management fees of $1.3 million, operating expenses paid of $1.2 million, workover expense paid of $0.6 million and general and administrative expenses paid of $0.4 million.
Investing Cash Flows
Cash flows used in investing activities for the year ended December 31, 2014 were $2.3 million, related to capital expenditures for oil and gas properties of $2.1 million, inclusive of advances, and investments in salvage fund of $0.2 million.
Cash flows provided by investing activities for the year ended December 31, 2013 were $1.0 million, primarily related to proceeds from the maturity of U.S. Treasury securities of $5.0 million, partially offset by capital expenditures for oil and gas properties of $3.8 million, inclusive of advances, and investments in the salvage fund of $0.2 million.
Financing Cash Flows
Cash flows used in financing activities for the year ended December 31, 2014 were $2.4 million related to manager and shareholder distributions.
Cash flows used in financing activities for the year ended December 31, 2013 were $5.3 million related to manager and shareholder distributions.
Estimated Capital Expenditures
The Fund has entered into multiple agreements for the acquisition, drilling and development of its oil and gas 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, 2014, the Fund has two non-producing properties, the Diller and Marmalard projects, for which additional development costs must be incurred in order to commence production. The Fund currently expects to spend an additional $6.3 million related to the development of these projects, which the Fund anticipates will include the development of eight wells, with related platform and pipeline infrastructure. See “Liquidity Needs” below for additional information.
Capital expenditures for oil and gas properties have been funded with the capital raised by the Fund in its private placement offering, which may be all the capital it will obtain. The number of projects in which the Fund could invest was limited, and each unsuccessful project the Fund experienced exhausted its capital and reduced its ability to generate revenue.
Liquidity Needs
The Fund’s primary short-term liquidity needs are to fund its operations and capital expenditures for its oil and gas properties. Such needs are funded utilizing operating income, existing cash on-hand and income earned therefrom.
As of December 31, 2014, the Fund’s estimated capital commitments related to its oil and gas properties were $7.8 million (which include asset retirement obligations for the Fund’s projects of $2.3 million), of which $3.2 million is expected to be spent during the year ending December 31, 2015.
Based upon its current cash position and its current reserve estimates, the Fund expects cash flow from operations to be sufficient to cover its commitments, as well as ongoing operations. Reserve estimates are projections based on engineering data that cannot be measured with precision, require substantial judgment, and are subject to frequent revision.
The Manager is entitled to receive an annual management fee from the Fund regardless of the Fund’s profitability in that year.
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. Due to the significant capital required to develop the Diller and Marmalard projects, distributions have been impacted, and will be impacted in the future, by amounts reserved to provide for their ongoing development costs and funding their estimated asset retirement obligations.
Off-Balance Sheet Arrangements
The Fund had no off-balance sheet arrangements at December 31, 2014 and 2013 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, 2014 and 2013 other than those discussed in “Estimated Capital Expenditures” above.
Recent Accounting Pronouncements
The Fund has considered recent accounting pronouncements and believes that these recent pronouncements will not have a material effect on the Fund’s financial statements.
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, 2014. 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 all 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, 2014. 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 (2013). Based on their assessment using those criteria, management of the Fund concluded that, as of December 31, 2014, 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, 2014 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 the Fund and their ages at December 31, 2014 are as follows:
The officers in the above table have been officers of the Fund since August 30, 2007, the date of inception of the Fund, with the exception of Mr. Lang, who has been an officer of 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 Ridgewood Private Equity Partners, LLC, and President of Ridgewood Securities Corporation, affiliates of Ridgewood Energy. Mr. Swanson is an inactive member of the New York and New Jersey State Bars. 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. Ms. McSherry holds a Bachelor of Science degree in Accounting.
Robert L. Gold has served as a senior officer 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 - Legal Affairs and Secretary 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, LLC and Ridgewood Private Equity Partners, LLC 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 and its affiliates compensate 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 477.8874 Shares outstanding as of the date of this filing. 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
Pursuant to the terms of the LLC Agreement, the Manager renders management, administrative and advisory services to the Fund. For such services, the Manager is paid an annual management fee, payable monthly, of 2.5% of total capital contributions, net of cumulative dry-hole and related well costs incurred by the Fund. Management fees for each of the years ended December 31, 2014 and 2013 were $1.3 million.
The Manager is entitled to receive a 15% interest in cash distributions from operations made by the Fund. Distributions paid to the Manager for the years ended December 31, 2014 and 2013 were $0.4 million and $0.8 million, respectively.
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 amounts paid to the Manager have 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, 2014 and 2013.
(1)
Fees for audit of annual financial statements, reviews of the related quarterly financial statements, and reviews of documents filed with the SEC.
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
February 26, 2015
Robert E. Swanson
(Principal Executive Officer)
/s/ KATHLEEN P. MCSHERRY
Executive Vice President and Chief Financial Officer
February 26, 2015
Kathleen P. McSherry
(Principal Financial and Accounting Officer)
RIDGEWOOD ENERGY CORPORATION
BY: /s/ ROBERT E. SWANSON
Chief Executive Officer of the Manager
February 26, 2015
Robert E. Swanson
PAGE
Report of Independent Registered Public Accounting Firm
Balance Sheets as of December 31, 2014 and 2013
Statements of Operations for the years ended December 31, 2014 and 2013
Statements of Changes in Members' Capital for the years ended December 31, 2014 and 2013
Statements of Cash Flows for the years ended December 31, 2014 and 2013
Notes to Financial Statements
Supplementary Financial Information - Information about Oil and Gas Producing Activities - Unaudited
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Shareholders and Manager of Ridgewood Energy X Fund, LLC:
We have audited the accompanying balance sheets of Ridgewood Energy X Fund, LLC (the “Fund”) as of December 31, 2014 and 2013, and the related statements of operations, changes in members’ capital, and cash flows for the years then ended. 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 X Fund, LLC as of December 31, 2014 and 2013, and the results of its operations and its cash flows for the years then ended, in conformity with accounting principles generally accepted in the United States of America.
/s/ Deloitte & Touche LLP
Parsippany, New Jersey
February 26, 2015
RIDGEWOOD ENERGY X FUND, LLC
BALANCE SHEETS
(in thousands, except share data)
The accompanying notes are an integral part of these financial statements.
RIDGEWOOD ENERGY X FUND, LLC
STATEMENTS OF OPERATIONS
(in thousands, except per share data)
The accompanying notes are an integral part of these financial statements.
RIDGEWOOD ENERGY X FUND, LLC
STATEMENTS OF CHANGES IN MEMBERS' CAPITAL
(in thousands, except share data)
The accompanying notes are an integral part of these financial statements.
RIDGEWOOD ENERGY X FUND, LLC
STATEMENTS OF CASH FLOWS
(in thousands)
The accompanying notes are an integral part of these financial statements.
RIDGEWOOD ENERGY X FUND, LLC
NOTES TO FINANCIAL STATEMENTS
1. Organization and Summary of Significant Accounting Policies
Organization
The Ridgewood Energy X Fund, LLC (the “Fund”), a Delaware limited liability company, was formed on August 30, 2007 and operates pursuant to a limited liability company agreement (the “LLC Agreement”) dated as of January 2, 2008 by and among Ridgewood Energy Corporation (the “Manager”) and the shareholders of the Fund, which addresses matters such as the authority and voting rights of the Manager and shareholders, capitalization, transferability of membership interests, participation in costs and revenues, distribution of assets and dissolution and winding up. 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 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 3 and 4.
Use of Estimates
The preparation of financial statements in accordance 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 the fair value of financial instruments, property balances, determination of proved reserves, impairments and asset retirement obligations. Actual results may differ from those estimates.
Fair Value Measurements
The fair value measurement guidance provides a hierarchy that prioritizes and defines the types of inputs used to measure fair value. The fair value hierarchy gives the highest priority to Level 1 inputs, which consists of unadjusted quoted prices for identical instruments in active markets. Level 2 inputs consist of quoted prices for similar instruments. Level 3 valuations are derived from inputs that are significant and unobservable; hence, these valuations have the lowest priority. Cash and cash equivalents approximate fair value based on Level 1 inputs.
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, which are $250 thousand per insured financial institution. At December 31, 2014, the Fund’s bank balances were maintained in uninsured bank accounts at Wells Fargo Bank, N.A.
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. 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.
Exploration, development and acquisition costs 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. Costs of drilling and equipping productive wells and related production facilities are capitalized. Costs of developing production facilities and pipelines that service multiple oil and gas properties are segregated as “Equipment and facilities - in progress.” Exploratory costs are capitalized pending determination of whether proved reserves have been found. If proved commercial reserves are not found, exploratory costs are expensed as dry-hole costs. At times, the Fund receives adjustments to certain wells from their respective operators upon review and audit of the wells’ costs. Annual lease rentals and exploration expenses are expensed as incurred. All costs related to production activity and workover efforts are expensed as incurred.
Once a well has been determined to be fully depleted or upon the sale, retirement or abandonment of a property, the cost and related accumulated depletion, depreciation and amortization, if any, is eliminated from the property accounts, and the resultant gain or loss is recognized.
At December 31, 2014 and 2013, amounts recorded in due to operators totaling $0.2 million 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 an oil and gas property 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, 2014 and 2013.
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 collectability 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 proved 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 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 January 2015, the Carrera Project was shut-in due to ongoing mechanical issues related to a blockage in the flowline. Upon evaluation, it was determined that estimated costs to bring the well back on production were not economic relative to the remaining reserves and the well was fully impaired. Accordingly, during the year ended December 31, 2014, the Fund recorded an impairment of oil and gas properties of $1.6 million, representing the remaining net book value of the well at the date of impairment. There were no impairments of oil and gas properties during the year ended December 31, 2013.
Depletion, Depreciation and Amortization
Depletion, depreciation 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, development costs and related facilities. The sum of proved developed and proved undeveloped reserves is used as the base for depleting or amortizing leasehold acquisition costs. In certain circumstances, equipment and facilities costs are depreciated over the estimated useful life of the asset.
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. The Fund files U.S. Federal and State tax returns and the 2010 through 2013 tax returns remain open for examination by tax authorities.
Income and Expense Allocation
Profits and losses are allocated to shareholders and the Manager in accordance with the LLC Agreement.
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.
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.
Recent Accounting Pronouncements
The Fund has considered recent accounting pronouncements and believes that these recent pronouncements will not have a material effect on the Fund’s financial statements.
2. Oil and Gas 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 adjustments to certain wells from their respective operators upon review and audit of the wells’ costs. During the year ended December 31, 2014, dry-hole costs were $36 thousand. During the year ended December 31, 2013, dry-hole costs were $1.9 million, which principally related to the Staurolite Project.
Workover expense of $0.4 million during the year ended December 31, 2014 related to the Carrera Project. Workover expense of $0.6 million during the year ended December 31, 2013 related to the Carrera and Liberty projects.
3. Related Parties
Pursuant to the terms of the LLC Agreement, the Manager renders management, administrative and advisory services to the Fund. For such services, the Manager is paid an annual management fee, payable monthly, of 2.5% of total capital contributions, net of cumulative dry-hole and related well costs incurred by the Fund. Management fees for each of the years ended December 31, 2014 and 2013 were $1.3 million.
The Manager is entitled to receive a 15% interest in cash distributions from operations made by the Fund. Distributions paid to the Manager for the years ended December 31, 2014 and 2013 were $0.4 million and $0.8 million, respectively.
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 amounts paid to the Manager have 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.
4. Commitments and Contingencies
Capital Commitments
The Fund has entered into multiple agreements for the acquisition, drilling and development of its oil and gas properties. The estimated capital expenditures associated with these agreements vary depending on the stage of development on a property-by-property basis. Currently, the Fund has two non-producing properties, the Diller and Marmalard projects, for which additional development costs must be incurred in order to commence production. The Fund currently anticipates such development will include eight wells, with related platform and pipeline infrastructure.
As of December 31, 2014, the Fund’s estimated capital commitments related to its oil and gas properties were $7.8 million (which include asset retirement obligations for the Fund’s projects of $2.3 million), of which $3.2 million is expected to be spent during the year ending December 31, 2015.
Based upon its current cash position and its current reserve estimates, the Fund expects cash flow from operations to be sufficient to cover its commitments, as well as ongoing operations. Reserve estimates are projections based on engineering data that cannot be measured with precision, require substantial judgment, and are subject to frequent revision.
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, 2014 and 2013, there were no known environmental contingencies that required the Fund to record a liability.
During the past several years, the United States Congress, as well as certain regulatory agencies with jurisdiction over the Fund’s business, have considered or proposed legislation or regulation relating to the upstream oil and gas industry both onshore and offshore. If any such proposals were to be enacted or adopted they could potentially materially impact the Fund’s operations. It is not possible at this time to predict whether such legislation or regulation, if proposed, will be adopted as initially written, if at all, or how legislation or new regulation that may be adopted would impact the Fund’s 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 a material 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.
Ridgewood Energy X 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 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 independent petroleum engineers, Netherland, Sewell & Associates, Inc. at December 31, 2014 and 2013. 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.
(a)
Revisions of previous estimates were attributable to well performance.
(b)
During January 2015, the Carrera Project was shut-in due to ongoing mechanical issues related to a blockage in the flowline. Upon evaluation, it was determined that estimated costs to bring the well back on production were not economic relative to the remaining reserves. As a result, approximately 37 thousand barrels of oil, 3 thousand barrels of NGL’s, and 44 thousand mcf's of gas, related to the Carrera Project, which are included in the above table, are not expected to be recovered.
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. Future cash inflows were determined based on average first-of-the-month pricing for the prior twelve-month period. Future production and development costs are derived based on current costs assuming continuation of existing economic conditions.
(a)
During January 2015, the Carrera Project was shut-in due to ongoing mechanical issues related to a blockage in the flowline. Upon evaluation, it was determined that estimated costs to bring the well back on production were not economic relative to the remaining reserves. As a result, undiscounted and discounted cash flows at December 31, 2014 of approximately $1.6 million and $1.7 million, respectively, related to the Carrera Project are not expected to be realized.
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.
(a)
During January 2015, the Carrera Project was shut-in due to ongoing mechanical issues related to a blockage in the flowline. Upon evaluation, it was determined that estimated costs to bring the well back on production were not economic relative to the remaining reserves. See additional information in Tables III and IV.
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.