ITEM 1.
BUSINESS
Overview
The Fund is a Delaware limited liability company (“LLC”) formed on November 21, 2006 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 3, 2007, selling whole and fractional shares of LLC membership interests (“Shares”), primarily at $150 thousand per whole Share. There is no public market for the Shares and one is not likely to develop. In addition, the Shares are subject to material restrictions on transfer and resale and cannot be transferred or resold except in accordance with the Fund’s limited liability company agreement (the “LLC Agreement”) and applicable federal and state securities laws. The private placement offering was terminated on May 16, 2007. The Fund raised $76.0 million and, after payment of $12.1 million in offering fees, commissions and investment fees, the Fund had $63.9 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, the preparation, review and dissemination of tax and other financial information and the management of the Fund’s investments in projects. In addition, the Manager provides office space, equipment and facilities and other services necessary for Fund operations. The Manager also engages and manages contractual relations with unaffiliated custodians, depositories, accountants, attorneys, corporate fiduciaries, insurers, banks and others as required. Historically, when the Fund sought project investments, 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 Annual Report.
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. During 2015, the Manager waived its management fee for the remaining life of the Fund. The Manager is entitled to receive a 15% interest in cash distributions from operations made by the Fund. The Fund did not pay distributions during the years ended December 31, 2017 and 2016.
In addition to the management fee, the Fund is required to pay all other expenses it may incur, including insurance premiums, expenses of preparing periodic reports for shareholders and the Securities Exchange Commission (“SEC”), taxes, third-party legal, accounting and consulting fees, litigation expenses and other expenses.
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 oil and natural gas projects. The frequency and amount of such distributions are within the Manager’s discretion, subject to available cash flow from operations. The Fund, along with other exploration and production companies, 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. The Fund’s ownership in its projects is recorded with the Bureau of Ocean Energy Management, an agency of the United States Department of Interior (“BOEM”), as a working interest, which is an undivided fractional interest in a lease block that provides the owner with the right to drill, produce and conduct operating activities and share in any resulting oil and natural gas production.
The Fund’s capital has been fully invested in projects. As a result, the Fund will not invest in any new projects and will limit its investment activities, if any, to those projects in which it currently has a working interest, as discussed below under the heading “Properties” in this Item 1. “Business” of this Annual Report.
Investment Committee
Ridgewood Energy maintains an investment committee consisting of five employees of the Manager (the “Investment Committee”). The members of the Investment Committee provide operational, financial, scientific and technical oil and gas expertise to the Fund. 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. The Investment Committee’s current activities with respect to the Fund are principally related to the development and operation of properties in which it already has a working interest.
Participation and Joint Operating Agreements
On behalf of the Fund, and with respect to the Fund’s projects, the Manager negotiated participation and joint operating agreements with the operators of each project. Under each joint operating agreement, proposals and decisions with respect to a project and related activities 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.
Project Information
The Fund’s existing projects are located in the waters of the Gulf of Mexico 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, 7 or 10 years, depending on the water depth of the lease block. 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, and depending on the lease, working interest owners of an offshore oil and natural gas lease under the OCSLA pay a royalty of 12.5%, 16.67% or 18.75% to the U.S. Government through the Office of Natural Resources Revenue (“ONRR”). Other than the ONRR royalties, the Fund does not have material royalty burdens with the exception of the overriding royalty interests (“ORRI”) payable to the lender under and as required by the Fund’s credit agreement applicable to the Beta Project. See Note 3 of “Notes to Financial Statements” - “Credit Agreement - Beta Project Financing” contained in Item 8. “Financial Statements and Supplementary Data” within this Annual Report for more information regarding the credit agreement.
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 Fund does not currently have any projects that are eligible for royalty relief under the Royalty Relief Rule. The Royalty Relief Rule does not extend to deep waters of the Gulf of Mexico off the OCS nor does it apply if the price of natural gas exceeds $11.80 (estimated) per Million British Thermal Units (“mmbtu”), adjusted annually for inflation.
Deepwater Royalty Relief
In addition to the Royalty Relief Rule, the Deep Water Royalty Relief Act of 1995 (the “Deepwater Royalty 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 Royalty 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 two projects, the Beta and Liberty projects, which are eligible for royalty relief under the Deepwater Royalty Relief Act. The Deepwater Royalty Relief Act does not apply to oil if the prices of oil exceed certain thresholds (currently estimated to be between $37.93 per barrel and $49.25 per barrel), adjusted annually for inflation. The Deepwater Royalty Relief Act does not apply to natural gas if the prices of natural gas exceed certain thresholds (currently estimated to be between $4.74 per mmbtu and $8.21 per mmbtu) adjusted annually for inflation.
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, 2017. 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, each of which produces both oil and natural gas, are located in the offshore waters of the Gulf of Mexico and are operated by third-party operators.
Acreage Data
The following table sets forth the Fund’s interests in developed and undeveloped oil and natural gas acreage as of December 31, 2017. 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 natural gas leases that have varying terms. All of the Fund’s oil and natural gas acreage is located in the offshore waters of the Gulf of Mexico.
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. See Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” of this Annual Report under the heading “Liquidity Needs” for information regarding the funding of the Fund’s capital commitments.
Marketing/Customers
The Manager, on behalf of the Fund, markets the Fund’s oil and natural gas to third parties consistent with industry practice. Beta Sales and Transport, LLC (“Beta S&T”), a wholly-owned subsidiary of the Manager, acts as an aggregator to and as an accommodation for the Fund and other funds managed by the Manager to facilitate the transportation and sale of oil and natural gas produced from the Beta Project. During 2016, the Fund entered into a master agreement with Beta S&T pursuant to which Beta S&T is obligated to purchase from the Fund all of its interests in oil and natural gas produced from the Beta Project and sell such volumes to unrelated third-party purchasers. The number of customers purchasing the Fund’s oil and natural gas may vary from time to time. Currently, and during 2017, the Fund had three 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 Fund’s oil and natural gas generally is sold to its customers at prevailing market prices, which fluctuate with demand as a result of related industry variables. 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. See Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” of this Annual Report under the headings “Commodity Price Changes”, “Results of Operations - Overview” and “Results of Operations - Oil and Gas Revenue” for information regarding the impact of prices on the Fund’s oil and gas revenue. In the past, the Fund has entered, and in the future, may 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.
However, notwithstanding the ability of the Fund’s projects to produce year-round, 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 significant damage, shut-ins, or production stoppages due to hurricane activity in 2017.
Operators
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 joint 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 Arena Offshore, LP, LLOG Exploration Offshore, L.L.C. and Walter Oil & Gas Corporation.
Because the Fund does not operate any of the projects in which it has acquired a working interest, shareholders have to rely on the Manager to continue to manage the projects prudently, efficiently and fairly.
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 funds’ 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 practice is 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 its 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 insurable incident, that insurance coverage may not be sufficient to cover all losses. In addition, depending on the extent, nature and payment of any claims during a particular policy period to the Fund or its affiliates, yearly insurance coverage may be exhausted and become insufficient to cover a claim by the Fund in a given year.
Salvage Fund
The Fund deposits cash in a separate interest-bearing account, or salvage fund, to provide for its proportionate share of the cost of dismantling and removal of production platforms and facilities and plugging and abandoning the wells at the end of their useful lives in accordance with applicable federal and state laws and regulations. As of December 31, 2017, the Fund has $2.6 million invested in a salvage fund. On a monthly basis, the Fund expects to contribute to the salvage fund a portion of the operating income from the Beta Project, to fund its asset retirement obligations. Such contributions to the salvage fund will reduce the amount of cash distributions that could otherwise be made to investors by the Fund. Any portion of the salvage fund that remains after the Fund has paid for all of its asset retirement obligations will be distributed to the shareholders and the Manager. There are no restrictions on withdrawals from the salvage fund.
Competition
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 the 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 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 125 Worth Avenue, Suite 318, Palm Beach, Florida, 33480. 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. Federal offshore leases are managed both by the BOEM and the Bureau of Safety and Environmental Enforcement (“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. 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 adopted strict requirements for subsea drilling production equipment and had proposed new requirements to implement equipment reliability improvements, building upon enhanced industry standards for blowout preventers and blowout prevention technologies, and reforms in well design, well control, casing, cementing, real-time well monitoring and subsea containment. In April 2016, BSEE adopted a final rule establishing updated standards for blowout prevention systems and other well controls pertaining to offshore activities (the “Well Control Rule”). The Well Control Rule became effective July 28, 2016, however compliance with certain provisions is deferred until 2018 or thereafter as specified. The Well Control Rule imposes new requirements relating to, among, other things, well design, well control, casing, cementing, real-time well monitoring and subsea containment. The Well Control Rule applies directly to operators as opposed to non-operators. BSEE has also published a policy statement on safety culture with nine characteristics of a robust safety culture. In April 2017, the “Presidential Order Implementing an America-First Offshore Energy Strategy” was issued, which, among other things, directed the BSEE to review the Well Control Rule. Given the fact that compliance with the Well Control Rule is the responsibility of the operators and the exploration and development of each well is different, the future costs associated with compliance that will be incurred by non-operators, such as the Fund, cannot be determined or estimated. 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.
BOEM Notice to Lessees on Supplemental Bonding
On July 14, 2016, the BOEM issued a Notice to Lessees (“NTL”) that discontinued and materially replaced existing policies and procedures regarding financial security (i.e. supplemental bonding) for decommissioning obligations of lessees of federal oil and gas leases and owners of pipeline rights-of-way, rights-of use and easements on the OCS (“Lessees”). Generally, the new NTL (i) ended the practice of excusing Lessees from providing such additional security where co-lessees had sufficient financial strength to meet such decommissioning obligations, (ii) established new criteria for determining financial strength and additional security requirements of such Lessees, (iii) provided acceptable forms of such additional security and (iv) replaced the waiver system with one of self-insurance. The new rule became effective as of September 12, 2016; however on January 6, 2017, the BOEM announced that it was suspending the implementation timeline for six months in certain circumstances. On June 22, 2017, the BOEM announced that the implementation timeline extension will remain in effect pending the completion of its review of the new NTL. The Fund, as well as other industry participants, are working with the BOEM, its operators and working interest partners to determine and agree upon the correct level of decommissioning obligations to which they may be liable and the manner in which such obligations will be secured. The impact of the NTL, if enforced without change or amendment, may require the Fund to fully secure all of its potential abandonment liabilities to the BOEM’s satisfaction using one or more of the enumerated methods for doing so. Potentially this could increase costs to the Fund if the Fund is required to obtain additional supplemental bonding, fund escrow accounts or obtain letters of credit.
Sales and Transportation of Oil and Natural Gas
The Fund, directly or indirectly through affiliated entities, sells its proportionate share of oil and natural gas to the market 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. Generally, depending on certain factors, pipelines can charge rates that are either market-based or cost-of-service-based. 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 to 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, the handling and managing of waste materials, and the protection of aquatic species and habitats. While most of the activities to which these federal, state and local environmental laws and regulations apply are conducted by the operators on the Fund’s behalf, the Fund shares the liability along with its other working interest owners for any environmental damage. The 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:
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, and regulations promulgated thereunder, establishes a liability limit for onshore facilities and deepwater ports of $633.85 million, while the liability limit for a responsible party for offshore facilities, including any offshore pipeline, is equal to all removal costs plus up to $133.65 million in other damages for each incident. 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. A 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. Compliance with the OPA’s financial assurance and other operating requirements has not had, and the Fund believes will not in the future have, a material impact on the Fund’s 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.
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 of 1980, 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; material increases in the costs of production, development or exploration; enforcement actions or other penalties as a result of any non-compliance with any such regulations; or otherwise have a material adverse effect on the Fund’s operating results and cash flows.
Dodd-Frank Act. The Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”), 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.
On February 3, 2017, the “Presidential Executive Order on Core Principles for Regulating the United States Financial System” (the “Order”) was issued to review the Dodd-Frank Act. A series of reports were issued by the U.S. Department of the Treasury in 2017 pursuant to the Order generally recommending the harmonization, balancing and streamlining of rules and regulations relating to, among other things, the over-the-counter derivative market. The Fund cannot predict at this time what regulations or portions of the law, if any, will be changed as a result of the Order.
Currently, under the LLC Agreement, the Fund has the authority to utilize derivative instruments to manage the price risk attributable to its oil and gas production. The Dodd-Frank Act 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 U.S. Commodity Futures Trading Commission (“CFTC”), and derivatives dealers may demand the unilateral ability to increase margin requirements beyond any regulatory or clearinghouse minimums. In addition, as required by the Dodd-Frank Act, the CFTC has set “speculative position limits” (which are 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 the Dodd-Frank Act 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 as a result of the legislation and regulations, the Fund alters any hedging program that may be in effect from time to time, the Fund’s operations may become more volatile and its cash flows may be less predictable, which could adversely affect the Fund’s performance. The Fund is not currently, and has not been during 2017, or at any time since 2012, a party to any derivative instruments or hedging programs.
The Dodd-Frank Act also required the SEC to issue rules requiring resource extraction issuers to disclose annually information relating to certain payments made by the issuer to the U.S. federal government or a foreign government for the purpose of the commercial development of oil, natural gas or minerals. Rules issued by the SEC in 2012 were subsequently vacated in federal court in 2013. On June 27, 2016, the SEC adopted amended resource extraction disclosure rules pursuant to Section 1504 of the Dodd-Frank Act. However, on February 14, 2017, a bill was passed by the United States Congress eliminating the SEC resource extraction disclosure rules. The SEC had one year to issue replacement rules to implement Section 1504 of the Dodd-Frank Act. The Fund cannot predict whether the SEC will issue replacement rules or, if it does, whether such rules will remain in effect.
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 during the years ended December 31, 2017 and 2016. 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, which produce both oil and natural gas, 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 the well in-progress as of December 31, 2017.
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. Such control procedures 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 thirty 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 as of December 31, 2017 and 2016 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 Reserves. 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 proved reserves expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped oil and gas reserves are proved reserves expected to be recovered through new wells on undrilled acreage, or through existing wells where a relatively major expenditure is required for recompletion. 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. As of December 31, 2017, the Fund had proved undeveloped reserves related to the Beta Project totaling 0.1 million barrels of oil, 7 thousand barrels of natural gas liquid (“NGL”) and 45 thousand mcf of natural gas. As of December 31, 2016, the Fund had proved undeveloped reserves related to the Beta Project totaling 27 thousand barrels of oil and 16 thousand mcf of natural gas. The Beta Project was determined to be a discovery in 2012 and commenced production in third quarter 2016.
During the year ended December 31, 2017, the Fund incurred costs to advance the development of its proved undeveloped reserves of approximately $3.8 million, related to the Beta Project. Information regarding estimated future development costs relating to the Beta Project 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 during the years ended December 31, 2017 and 2016 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, 2017, 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 January 31, 2018, there were 929 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 Beta Project, distributions have been impacted, and may be impacted in the future by amounts reserved to provide for its ongoing development costs, debt service costs and funding of its 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. The Fund did not pay distributions during the years ended December 31, 2017 and 2016.
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 oil and natural gas projects. Distributions to shareholders are made in accordance with the Fund’s LLC Agreement. The frequency and amount of such distributions are within the Manager’s discretion, subject to available cash flow from operations. The Fund’s remaining capital has been fully allocated to its projects. As a result, the Fund will not invest in any new projects.
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 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.
Commodity Price Changes
Changes in commodity prices may significantly affect liquidity and expected operating results. Declines 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.
Oil and natural gas commodity prices have been subject to significant fluctuations during the past several years. The Fund anticipates price cyclicality in its planning and believes it is well positioned to withstand price volatility. Despite operating in a volatile commodity price environment, the Fund continued to advance the development of the Beta Project, which commenced production during the second half of 2016. The Fund has suspended distributions and continues to conserve cash to provide for the continued development of the Beta Project. See “Results of Operations” under this Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” for more information on the average oil and natural gas prices received by the Fund during the years ended December 31, 2017 and 2016. If oil and natural gas prices decline, even if only for a short period of time, the Fund’s results of operations and liquidity will be adversely impacted.
Market pricing for oil and natural gas is 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 supply and price of foreign 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 price and availability of alternate fuel sources.
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 accordance 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. The following is a discussion of the accounting policies and estimates the Fund believes are most significant.
Accounting for Acquisition, Exploration and Development Costs
Acquisition, exploration and development 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.
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 engineering firm 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, ongoing discussions with the wells’ operators and, at times, with information provided by third-party abandonment consultants specializing in the oil and gas industry. 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 such as the timing of settlements, the credit-adjusted risk-free rates used and inflation rates, 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 carrying value of its oil and gas properties annually and when management determines that events and circumstances indicate that the recorded carrying value of properties may not be recoverable. Impairments are determined by comparing estimated future net undiscounted cash flows to the carrying value at the time of the review. If the carrying value exceeds the estimated future net undiscounted cash flows, the carrying value of the asset is written down to fair value, which is determined using estimated future net discounted cash flows from the asset. 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 future net discounted cash flows from proved oil and natural gas reserves could change in the near term.
Results of Operations
The following table summarizes the Fund’s results of operations during the years ended December 31, 2017 and 2016, 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, 2017 and 2016. NGL sales are included within gas sales.
The increases in the above table were primarily related to the commencement of production of the Beta Project. See Item 1. “Business” of this Annual Report under the heading “Properties” for more information.
Oil and Gas Revenue. Generally, the Fund sells oil, gas and NGLs under two types of agreements, which are common in the oil and gas industry. In the first type of agreement, or a netback agreement, the Fund receives a price, net of transportation expense incurred by the purchaser, and the Fund records revenue at the net price received. In the second type of agreement, the Fund pays transportation expense directly, and transportation expense is included within operating expenses in the statements of operations.
Oil and gas revenue during the year ended December 31, 2017 was $6.5 million, an increase of $4.8 million from the year ended December 31, 2016. The increase was attributable to increased sales volume totaling $3.9 million coupled with increased oil and gas prices totaling $0.9 million.
See “Overview” above for factors that impact the oil and gas revenue volume and rate variances.
Depletion and Amortization. Depletion and amortization during the year ended December 31, 2017 was $5.4 million, an increase of $4.1 million from the year ended December 31, 2016. The increase was attributable to an increase in production volumes totaling $2.9 million coupled with an increase in the average depletion rate totaling $1.2 million. The increase in the average depletion rate was primarily attributable to the onset of production of the Beta Project. Depletion and amortization rates were also impacted by changes in reserve estimates provided annually by the Fund’s independent petroleum engineers.
See “Overview” above for certain factors that impact the depletion and amortization volume and rate variances.
Impairment of Oil and Gas Properties. The Fund did not record any impairments of oil and gas properties during the year ended December 31, 2017. During the year ended December 31, 2016, the Fund recorded impairments of oil and gas properties of $56 thousand, related to Eugene Island 346/347, which were primarily attributable to declines in future oil and gas prices.
Operating Expenses. Operating expenses represent costs specifically identifiable or allocable to the Fund’s wells, as detailed in the following table.
Lease operating expense and transportation and processing expense relates to the Fund’s producing properties. Insurance expense represents premiums related to the Fund’s properties, which vary depending upon the number of wells producing or drilling. Accretion expense relates to the asset retirement obligations established for the Fund’s proved properties. Workover expense represents costs to restore or stimulate production of existing reserves.
The average production cost, which includes lease operating expense, transportation and processing expense and insurance expense, was $6.56 per barrel of oil equivalent (“BOE”) during the year ended December 31, 2017, compared to $11.72 per BOE during the year ended December 31, 2016. The decrease was primarily attributable to the Beta Project, which had lower cost per BOE in 2017. The Beta Project, which commenced production in third quarter 2016, has lower cost per BOE as compared to other projects due to the processing of production through its standalone facility. The production costs per BOE may decline over time as throughput increases from the project or other projects expected to tie-in to the facility.
General and Administrative Expenses. General and administrative expenses represent costs specifically identifiable or allocable to the Fund, such as accounting and professional fees and insurance expenses.
Interest Expense, Net. Interest expense, net is comprised of interest expense and amortization of debt discounts and deferred financing costs related to the Fund’s long-term borrowings (see “Liquidity Needs” below for additional information), and interest income earned on cash and cash equivalents and salvage fund.
Capital Resources and Liquidity
Operating Cash Flows
Cash flows provided by operating activities during the year ended December 31, 2017 were $4.1 million, primarily related to revenue received of $6.2 million, partially offset by operating expenses of $1.8 million and general and administrative expenses of $0.3 million.
Cash flows provided by operating activities during the year ended December 31, 2016 were $0.3 million, primarily related to revenue received of $1.2 million, partially offset by operating expenses of $0.7 million and general and administrative expenses of $0.2 million.
Investing Cash Flows
Cash flows used in investing activities during the year ended December 31, 2017 were $4.7 million, related to capital expenditures for oil and gas properties of $4.7 million and investments in salvage fund of $0.1 million.
Cash flows used in investing activities during the year ended December 31, 2016 were $3.3 million, primarily related to capital expenditures for oil and gas properties.
Financing Cash Flows
There were no cash flows from financing activities during the year ended December 31, 2017.
Cash flows provided by financing activities during the year ended December 31, 2016 were $0.7 million, related to proceeds from long-term borrowings.
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. See Item 1. “Business” of this Annual Report under the heading “Properties” and “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, and in certain circumstances, through debt financing. The Fund’s remaining capital has been fully allocated to its projects. As a result, the Fund will not invest in any new projects and will limit its investment activities, if any, to those projects in which it currently has a working interest.
Liquidity Needs
The Fund’s primary short-term liquidity needs are to fund its operations, capital expenditures for its oil and gas properties and borrowing repayments. Such needs are funded utilizing operating income and existing cash on-hand.
As of December 31, 2017, the Fund’s estimated capital commitments related to its oil and gas properties were $5.5 million (which include asset retirement obligations for the Fund’s projects of $3.6 million), of which $1.8 million is expected to be spent during the year ending December 31, 2018, related to the settlement of asset retirement obligations for certain of the Fund’s projects and the continued development of the Beta Project. As a result of continued development of the Beta Project, the Fund has experienced negative cash flows for the year ended December 31, 2017. Additionally, current liabilities exceed current assets as of December 31, 2017. Future results of operations and cash flows are dependent on the continued successful development and the related production of oil and gas revenues from the Beta Project. 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, borrowing repayments and 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. However, if cash flow from operations is not sufficient to meet the Fund’s commitments, the Manager will provide short-term financing to accommodate the Fund’s short-term commitments if needed.
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 Beta Project, distributions have been impacted, and may be impacted in the future, by amounts reserved to provide for its ongoing development costs, debt service costs and funding its estimated asset retirement obligations.
Credit Agreement
In November 2012, the Fund entered into a credit agreement (as amended on September 30, 2016 and September 15, 2017, the “Credit Agreement”) with Rahr Energy Investments LLC, as administrative agent and lender (and any other banks or financial institutions that may in the future become a party thereto, collectively “Lenders”), that provided for an aggregate loan commitment to the Fund of approximately $13.6 million to provide capital toward the funding of the Fund’s share of development costs on the Beta Project. As of December 31, 2017 and 2016, the Fund had borrowed $13.6 million under the Credit Agreement. As of December 31, 2016, in accordance with the terms of the Credit Agreement, there were no additional borrowings available to the Fund.
The loan bears interest at 8% compounded annually. Monthly principal and interest payments are the lesser of the monthly fixed amount of approximately $0.6 million or the Debt Service Cap amount, as defined in the Credit Agreement, until the loan is repaid in full, in no event later than December 31, 2020. The Fund expects operating income from the Beta Project to be sufficient to cover the principal and interest payments required under the Credit Agreement. The loan may be prepaid by the Fund without premium or penalty.
As additional consideration to the Lenders, the Fund has agreed to convey an overriding royalty interest (“ORRI”) in its working interest in the Beta Project to the Lenders. The Fund’s share of the Lenders’ aggregate ORRI is directly proportionate to its level of borrowing as a percentage of total borrowings of all the other participating funds managed by the Manager. Such ORRI will not become payable to the Lenders until after the Loan is repaid in full.
The Credit Agreement contains customary negative covenants including covenants that limit the Fund’s ability to, among other things, grant liens, change the nature of its business, or merge into or consolidate with other persons. The events which constitute events of default are also customary for credit facilities of this nature and include payment defaults, breaches of representations, warrants and covenants, insolvency and change of control. Upon the occurrence of a default, in some cases following a notice and cure period, the Lenders under the Credit Agreement may accelerate the maturity of the loan and require full and immediate repayment of all borrowings under the Credit Agreement. The Fund believes it is in compliance with all covenants under the Credit Agreement as of December 31, 2017 and 2016.
See Note 3 of “Notes to Financial Statements” - “Credit Agreement - Beta Project Financing” contained in Item 8. “Financial Statements and Supplementary Data” within this Annual Report for more information regarding the Credit Agreement.
Off-Balance Sheet Arrangements
The Fund had no off-balance sheet arrangements as of December 31, 2017 and 2016 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 as of December 31, 2017 and 2016, other than those discussed in “Estimated Capital Expenditures” and “Liquidity Needs - Credit Agreement” above.
Recent Accounting Pronouncements
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 recent accounting pronouncements.
ITEM 7A.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Not required.
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
All financial statements meeting the requirements of Regulation S-X and the supplementary financial information required by Item 302 of Regulation S-K are included in the financial statements listed in Item 15. “Exhibits and 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) and 15d-15(e) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”) as of December 31, 2017. 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) and 15d-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, 2017. 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, 2017, 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, 2017 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 as of December 31, 2017 are as follows:
The officers in the above table have been officers of the Fund since November 21, 2006, 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, Ridgewood Private Equity Partners, LLC, Ridgewood Infrastructure, LLC and 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 from Kean University.
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 in that capacity for Ridgewood Energy since 2003. Mr. Gulino also serves as Senior Vice President of Legal Affairs of Ridgewood Capital Management, LLC, Ridgewood Private Equity Partners, LLC and Ridgewood Infrastructure, 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 513.1226 shares outstanding as of January 31, 2018. The following table sets forth information with respect to beneficial ownership of the Shares as of January 31, 2018 (no person owns more than 5% of the Shares). Except as indicated by footnote, and subject to applicable community property laws, the persons named in the table below have sole voting and investment power with respect to all shares shown as beneficially owned by them. Other than as indicated below, no officer of the Manager or the Fund owns any of the Shares.
* Represents less than one percent.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
Pursuant to the terms of the LLC Agreement, the Manager is entitled to an annual management fee, equal to 2.5% of total shareholder contributions. During 2015, the Manager elected to waive its management fee for the remaining life of the Fund. Upon waiver of the management fee, the Fund began recording costs related to services provided by the Manager for accounting and investor relations. Such costs, totaling $80 thousand for each of the years ended December 31, 2017 and 2016, were included within general and administrative expenses.
The Manager is also entitled to receive a 15% interest in cash distributions from operations made by the Fund. The Fund did not pay distributions during the years ended December 31, 2017 and 2016.
Beta S&T, a wholly-owned subsidiary of the Manager, acts as an aggregator to and as an accommodation for the Fund and other funds managed by the Manager to facilitate the transportation and sale of oil and natural gas produced from the Beta Project. During 2016, the Fund entered into a master agreement with Beta S&T pursuant to which Beta S&T is obligated to purchase from the Fund all of its interests in oil and natural gas produced from the Beta Project and sell such volumes to unrelated third party purchasers. Pursuant to the master agreement, Beta S&T is a pass-through entity such that it receives no benefit or compensation for the services provided under the master agreement or under any other agreements it enters into with regards to the oil and natural gas purchased from the Fund. The Fund and other funds managed by the Manager have agreed to indemnify, defend and hold harmless Beta S&T from and against all claims, liabilities, losses, causes of action, costs and expenses asserted against it as a result of or arising from any act or omission, breach and claims for losses or damages arising out of its dealing with third parties with respect to the transportation, processing or sale of oil and natural gas from the Beta Project. The revenues and expenses from the sale of oil and natural gas to third party purchasers are recorded as oil and gas revenue and operating expenses in the Fund’s statements of operations, and are allocable to the Fund based on the Fund’s working interest ownership in the Beta Project.
At times, short-term payables and receivables, which do not bear interest, arise from transactions with affiliates in the ordinary course of business.
The Fund has working interest ownership in certain projects to develop oil and gas projects, which are also owned by 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 during the years ended December 31, 2017 and 2016.
(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 AND 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
March 9, 2018
/s/ ROBERT E. SWANSON
Chief Executive Officer
(Principal Executive Officer)
Robert E. Swanson
/s/ KATHLEEN P. MCSHERRY
Executive Vice President and Chief Financial Officer
(Principal Financial and Accounting Officer)
March 9, 2018
Kathleen P. McSherry
RIDGEWOOD ENERGY CORPORATION
BY: /s/ ROBERT E. SWANSON
Chief Executive Officer of the Manager
March 9, 2018
Robert E. Swanson
PAGE
Report of Independent Registered Public Accounting Firm
Balance Sheets as of December 31, 2017 and 2016
Statements of Operations for the years ended December 31, 2017 and 2016
Statements of Changes in Members' Capital for the years ended December 31, 2017 and 2016
Statements of Cash Flows for the years ended December 31, 2017 and 2016
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 V Fund, LLC:
Opinion on the Financial Statements
We have audited the accompanying balance sheets of Ridgewood Energy V Fund, LLC (the "Fund") as of December 31, 2017 and 2016, the related statements of operations, changes in members’ capital, and cash flows, for each of the two years in the period ended December 31, 2017, and the related notes (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Fund as of December 31, 2017 and 2016, and the results of its operations and its cash flows for each of the two years in the period ended December 31, 2017, in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These financial statements are the responsibility of the Fund's management. Our responsibility is to express an opinion on the Fund's financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (Untied States) (PCAOB) and are required to be independent with respect to the Fund in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Fund is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting 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.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
/s/ Deloitte & Touche LLP
Parsippany, New Jersey
March 9, 2018
We have served as the Fund's auditor since 2007.
RIDGEWOOD ENERGY V FUND, LLC
BALANCE SHEETS
(in thousands, except share data)
The accompanying notes are an integral part of these financial statements.
RIDGEWOOD ENERGY V FUND, LLC
STATEMENTS OF OPERATIONS
(in thousands, except per share data)
The accompanying notes are an integral part of these financial statements.
RIDGEWOOD ENERGY V 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 V FUND, LLC
STATEMENTS OF CASH FLOWS
(in thousands)
The accompanying notes are an integral part of these financial statements.
RIDGEWOOD ENERGY V FUND, LLC
NOTES TO FINANCIAL STATEMENTS
1. Organization and Summary of Significant Accounting Policies
Organization
The Ridgewood Energy V Fund, LLC (the “Fund”), a Delaware limited liability company, was formed on November 21, 2006 and operates pursuant to a limited liability company agreement (the “LLC Agreement”) dated as of January 3, 2007 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. 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, the preparation, review and dissemination of tax and other financial information and the management of the Fund’s investments in projects. In addition, the Manager provides office space, equipment and facilities and other services necessary for Fund operations. The Manager also engages and manages contractual relations with unaffiliated custodians, depositories, accountants, attorneys, corporate fiduciaries, insurers, banks and others as required. See Notes 2, 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, depletion and amortization, determination of proved reserves, impairment of long-lived assets 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 consist of unadjusted quoted prices for identical instruments in active markets. Level 2 inputs consist of quoted prices for similar instruments. Level 3 inputs are unobservable inputs and include situations where there is little, if any, market activity for the instrument; hence, these inputs have the lowest priority.
Cash and Cash Equivalents
All highly liquid investments with maturities, when purchased, of three months or less, are considered cash equivalents. These balances, as well as cash on hand, are included in “Cash and cash equivalents” on the balance sheet. As of December 31, 2017, the Fund had no cash equivalents. At times, deposits may be in excess of federally insured limits, which are $250 thousand per insured financial institution. As of December 31, 2017, the Fund’s bank balances were maintained in uninsured bank accounts at Wells Fargo Bank, N.A.
Salvage Fund
The Fund deposits cash in a separate interest-bearing account, or salvage fund, 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.
Debt Discounts and Deferred Financing Costs
Debt discounts and deferred financing costs include lender fees and other costs of acquiring debt such as the conveyance of override royalty interests related to the Beta Project. These costs are deferred and amortized over the term of the debt period or until the redemption of the debt. Unamortized debt discounts and deferred financing costs are presented as a reduction of “Long-term borrowings” on the balance sheets. During the period of asset construction, amortization expense, as a component of interest, is capitalized and included on the balance sheet within “Oil and gas properties”. See Note 3. “Credit Agreement - Beta Project Financing” for additional information.
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.
Acquisition, exploration and development 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. The costs of exploratory wells are capitalized pending determination of whether proved reserves have been found. If proved commercial reserves are not found, exploratory well 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. Interest costs related to the Credit Agreement (see Note 3. “Credit Agreement - Beta Project Financing”) are capitalized during the period of asset construction. Annual lease rentals and exploration expenses are expensed as incurred. All costs related to production activity, transportation expense and workover efforts are expensed as incurred.
Once a property has been determined to be fully depleted or upon the sale, retirement or abandonment of a property, the cost and related accumulated depletion and amortization, if any, is eliminated from the property accounts, and the resultant gain or loss is recognized.
The Fund may be required to advance its share of the estimated succeeding month’s expenditures to the operator for its oil and gas properties. As the costs are incurred, the advances are reclassified to proved properties.
Asset Retirement Obligations
For oil and gas properties, there are obligations to perform removal and remediation activities when the properties are retired. Upon the determination that a property is either proved or dry, a retirement obligation is incurred. The Fund recognizes the fair value of a liability for an asset retirement obligation in the period incurred. Plug and abandonment costs associated with unsuccessful projects are expensed as dry-hole costs. Bi-annually, or more frequently if an event occurs that would dictate a change in assumptions or estimates underlying the obligations, the Fund reassesses its asset retirement obligations to determine whether any revisions to the obligations are necessary. The following table presents changes in asset retirement obligations during the years ended December 31, 2017 and 2016.
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, delivery has occurred and title has transferred, and collectability of the revenue is reasonably assured. 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 carrying value of its oil and gas properties annually and when management determines that events and circumstances indicate that the recorded carrying value of properties may not be recoverable. Impairments are determined by comparing estimated future net undiscounted cash flows to the carrying value at the time of the review. If the carrying value exceeds the estimated future net undiscounted cash flows, the carrying value of the asset is written down to fair value, which is determined using estimated future net discounted cash flows from the asset. 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 future net discounted cash flows from proved oil and natural gas reserves could change in the near term.
Fluctuations in oil and natural gas prices may impact the fair value of the Fund’s oil and gas properties. There were no impairments of oil and gas properties during the year ended December 31, 2017. During the year ended December 31, 2016, the Fund recorded impairments of oil and gas properties of $56 thousand, which represented the carrying value of Eugene Island 346/347. The impairment was primarily attributable to declines in future oil and natural gas prices. If oil and natural gas prices decline, even if only for a short period of time, it is possible that additional impairments of oil and gas properties will occur.
Depletion and Amortization
Depletion and amortization of the cost of proved oil and gas properties are calculated using the units-of-production method. Proved developed reserves are used as the base for depleting capitalized costs associated with successful exploratory well costs, development costs and related facilities, other than offshore platforms. The sum of proved developed and proved undeveloped reserves is used as the base for depleting or amortizing leasehold acquisition costs and costs to construct offshore platform and associated asset retirement costs.
Income Taxes
No provision is made for income taxes in the financial statements. The Fund is a limited liability company, and as such, the Fund’s income or loss is passed through and included in the tax returns of the Fund’s shareholders. The Fund files U.S. Federal and State tax returns and the 2014 through 2016 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
In May 2014, the Financial Accounting Standards Board (“FASB”) issued accounting guidance on revenue recognition, which provides for a single five-step model to be applied to all revenue contracts with customers. In July 2015, the FASB issued a deferral of the effective date of the guidance to 2018, with early adoption permitted in 2017. In March 2016, the FASB issued accounting guidance, which clarifies the implementation guidance on principal versus agent considerations in the new revenue recognition standard. In April 2016, the FASB issued guidance on identifying performance obligations and licensing and in May 2016, the FASB issued final amendments which provided narrow scope improvements and practical expedients related to the implementation of the guidance. The accounting guidance may be applied either retrospectively or through the use of a modified-retrospective method. Under the new accounting guidance, the revenue associated with the Fund’s existing contracts will be recognized in the period that control of the related commodity is transferred to the customer, which is generally consistent with its current revenue recognition model. The Fund adopted the new accounting guidance using the modified retrospective method on January 1, 2018. Although the Fund did not identify changes to its revenue recognition that resulted in a material cumulative adjustment to retained earnings on January 1, 2018, the adoption of the accounting guidance will result in enhanced disclosures related to revenue recognition policies, the Fund’s performance obligations and significant judgments used in applying the new revenue recognition accounting guidance.
2. 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 entitled to 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. During 2015, the Manager waived its management fee for the remaining life of the Fund. Upon the waiver of the management fee, the Fund began recording costs, totaling $20 thousand per quarter, representing reimbursements to the Manager, related to services provided by the Manager for accounting and investor relations. Such costs are included within general and administrative expenses. Management reimbursement costs during each of the years ended December 31, 2017 and 2016 were $80 thousand.
The Manager is also entitled to receive a 15% interest in cash distributions from operations made by the Fund. The Fund did not pay distributions during the years ended December 31, 2017 and 2016.
Beta Sales and Transport, LLC (“Beta S&T”), a wholly-owned subsidiary of the Manager, acts as an aggregator to and as an accommodation for the Fund and other funds managed by the Manager to facilitate the transportation and sale of oil and natural gas produced from the Beta Project. In 2016, the Fund entered into a master agreement with Beta S&T pursuant to which Beta S&T is obligated to purchase from the Fund all of its interests in oil and natural gas produced from the Beta Project and sell such volumes to unrelated third party purchasers. Pursuant to the master agreement, Beta S&T is a pass-through entity such that it receives no benefit or compensation for the services provided under the master agreement or under any other agreements it enters into with regard to the oil and natural gas purchased from the Fund. The Fund and other funds managed by the Manager have agreed to indemnify, defend and hold harmless Beta S&T from and against all claims, liabilities, losses, causes of action, costs and expenses asserted against it as a result of or arising from any act or omission, breach and claims for losses or damages arising out of its dealing with third parties with respect to the transportation, processing or sale of oil and natural gas from the Beta Project. The revenues and expenses from the sale of oil and natural gas to third party purchasers are recorded as oil and gas revenue and operating expenses in the Fund’s statements of operations, and are allocable to the Fund based on the Fund’s working interest ownership in the Beta Project.
At times, short-term payables and receivables, which do not bear interest, arise from transactions with affiliates in the ordinary course of business.
The Fund has working interest ownership in certain projects to develop oil and gas projects, which are also owned by other entities that are likewise managed by the Manager.
3. Credit Agreement - Beta Project Financing
In November 2012, the Fund entered into a credit agreement (as amended on September 30, 2016 and September 15, 2017, the “Credit Agreement”) with Rahr Energy Investments LLC, as Administrative Agent and Lender (and any other banks or financial institutions that may in the future become a party thereto, collectively “Lenders”) that provided for an aggregate loan commitment to the Fund of approximately $13.6 million (“Loan”), to provide capital toward the funding of the Fund’s share of development costs on the Beta Project. Certain other funds managed by the Manager (“Ridgewood Funds”, and when used with the Fund the “Ridgewood Participating Funds”) have also executed the Credit Agreement. Pursuant to the Credit Agreement, each Ridgewood Participating Fund has a separate loan commitment from the Lenders and amounts borrowed are not joint and several obligations. Each of the Ridgewood Participating Funds’ borrowings is secured solely by its separate interest in the Beta Project. Except in cases of fraud and breach of certain representations, the Loan is non-recourse to the Fund’s other assets and secured solely by the Fund’s interests in the Beta Project. Therefore, the Fund is liable for the repayment of its Loan and is not liable to the Lenders to repay any loan made to any other Ridgewood Funds. As of December 31, 2016, in accordance with the terms of the Credit Agreement, there were no additional borrowings available to the Ridgewood Participating Funds.
As of December 31, 2017 and 2016, the Fund had borrowings of $13.6 million under the Credit Agreement. The Loan bears interest at 8% compounded annually. Principal and interest are repaid at the lesser of the monthly fixed amount of approximately $0.6 million or the Debt Service Cap amount as defined in the Credit Agreement, in no event later than December 31, 2020. The Loan may be prepaid by the Fund without premium or penalty. On September 15, 2017, the Ridgewood Participating Funds entered into the second amendment to the Credit Agreement, which principally amended the definition of the net revenues, which is the basis for the calculation of the Debt Service Cap amount.
There were no unamortized debt discounts and deferred financing costs as of December 31, 2017. Unamortized debt discounts and deferred financing costs of $0.2 million as of December 31, 2016 are presented as a reduction of “Long-term borrowings” on the balance sheet. Amortization expense during the years ended December 31, 2017 and 2016 of $0.2 million and $0.1 million, respectively, were expensed and included on the statements of operations within “Interest expense, net”. Amortization expense during the year ended December 31, 2016 of $0.1 million was capitalized and included on the balance sheet within “Oil and gas properties”.
As of December 31, 2017 and 2016, accrued interest costs of $0.9 million and $1.6 million, respectively, were included on the balance sheets within “Accrued expenses”. Interest costs incurred during the years ended December 31, 2017 and 2016 of $1.2 million and $0.6 million, respectively, were expensed and included on the statements of operations within “Interest expense, net”. Interest costs incurred during the year ended December 31, 2016 of $0.5 million were capitalized and included on the balance sheet within “Oil and gas properties”. During the years ended December 31, 2017 and 2016, the Fund made payments on the loan of $1.0 million and $0.2 million, respectively, which related to capitalized interest costs.
As additional consideration to the Lenders, the Fund has agreed to convey an overriding royalty interest (“ORRI”) in its working interest in the Beta Project to the Lenders. The Fund’s share of the Lenders’ aggregate ORRI is directly proportionate to its level of borrowing as a percentage of total borrowings of all Ridgewood Participating Funds. Such ORRI will not become payable to the Lenders until after the Loan is repaid in full. The Credit Agreement contains customary covenants, with which the Fund was in compliance as of December 31, 2017 and 2016.
4. Commitments and Contingencies
Capital Commitments
As of December 31, 2017, the Fund’s estimated capital commitments related to its oil and gas properties were $5.5 million (which include asset retirement obligations for the Fund’s projects of $3.6 million), of which $1.8 million is expected to be spent during the year ending December 31, 2018, related to the settlement of asset retirement obligations for certain of the Fund’s projects and the continued development of the Beta Project. As a result of continued development of the Beta Project, the Fund has experienced negative cash flows for the year ended December 31, 2017. Additionally, current liabilities exceed current assets as of December 31, 2017. Future results of operations and cash flows are dependent on the continued successful development and the related production of oil and gas revenues from the Beta Project.
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, borrowing repayments and 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. However, if cash flow from operations is not sufficient to meet the Fund’s commitments, the Manager will provide short-term financing to accommodate the Fund’s short-term commitments if needed.
Environmental and Governmental Regulations
Many aspects of the oil and gas industry are subject to federal, state and local environmental laws and regulations. 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. However, due to the significant public and governmental interest in environmental matters related to those activities, the Manager cannot predict the effects of possible future legislation, rule changes, or governmental or private claims. As of December 31, 2017 and 2016, there were no known environmental contingencies that required adjustment to, or disclosure in, the Fund’s financial statements.
Oil and gas industry legislation and administrative regulations are periodically changed for a variety of political, economic, and other reasons. 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. 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.
BOEM Notice to Lessees on Supplemental Bonding
On July 14, 2016, the Bureau of Ocean Energy Management (“BOEM”) issued a Notice to Lessees (“NTL”) that discontinued and materially replaced existing policies and procedures regarding financial security (i.e. supplemental bonding) for decommissioning obligations of lessees of federal oil and gas leases and owners of pipeline rights-of-way, rights-of use and easements on the Outer Continental Shelf (“Lessees”). Generally, the new NTL (i) ended the practice of excusing Lessees from providing such additional security where co-lessees had sufficient financial strength to meet such decommissioning obligations, (ii) established new criteria for determining financial strength and additional security requirements of such Lessees, (iii) provided acceptable forms of such additional security and (iv) replaced the waiver system with one of self-insurance. The new rule became effective as of September 12, 2016; however on January 6, 2017, the BOEM announced that it was suspending the implementation timeline for six months in certain circumstances. On June 22, 2017, the BOEM announced that the implementation timeline extension will remain in effect pending the completion of its review of the new NTL. The Fund, as well as other industry participants, are working with the BOEM, its operators and working interest partners to determine and agree upon the correct level of decommissioning obligations to which they may be liable and the manner in which such obligations will be secured. The impact of the NTL, if enforced without change or amendment, may require the Fund to fully secure all of its potential abandonment liabilities to the BOEM’s satisfaction using one or more of the enumerated methods for doing so. Potentially this could increase costs to the Fund if the Fund is required to obtain additional supplemental bonding, fund escrow accounts or obtain letters of credit.
Insurance Coverage
The Fund is subject to all risks inherent in the oil and natural gas business. 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. Depending on the extent, nature and payment of claims made by the Fund or other funds managed by the Manager, yearly insurance coverage may be exhausted and become insufficient to cover a claim by the Fund in a given year.
Ridgewood Energy V Fund, LLC
Supplementary Financial Information
Information about Oil and Gas Producing Activities - Unaudited
In accordance with the FASB 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 the Gulf of Mexico.
Table I - Capitalized Costs Relating to Oil and Gas Producing Activities
Table II - Costs Incurred in Oil and Gas Property Acquisition, Exploration, and Development
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, 2017 and 2016. 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) BOE refers to barrel of oil equivalent. Barrel of oil equivalent is based on six MCF of natural gas to one barrel of oil or one barrel of NGL, which reflects an energy content equivalency and not a price or revenue equivalency.
(b) Extensions and discoveries were attributable to extensions for the Beta Project.
(c) Revisions of previous estimates were attributable to well performance.
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.
Table V - Changes in the Standardized Measure for Discounted Cash Flows
The changes in present values between years, which can be significant, reflect changes in estimated proved reserve quantities and prices and assumptions used in forecasting production volumes and costs.
It is necessary to emphasize that the data presented should not be viewed as representing the expected cash flow from, or current value of, existing proved reserves as the computations are based on a number of estimates. Reserve quantities cannot be measured with precision and their estimation requires many judgmental determinations and frequent revisions. The required projection of production and related expenditures over time requires further estimates with respect to pipeline availability, rates and governmental control. Actual future prices and costs are likely to be substantially different from the current price and cost estimates utilized in the computation of reported amounts. Any analysis or evaluation of the reported amounts should give specific recognition to the computational methods utilized and the limitation inherent therein.