ITEM 1.BUSINESS
Overview
The Fund is a Delaware limited liability company (“LLC”) formed on May 17, 2007 to primarily acquire interests in oil and natural gas properties located in the United States offshore waters of Texas, Louisiana and Alabama in the Gulf of Mexico.
The Fund initiated its private placement offering on June 15, 2007, selling whole and fractional shares of membership interests (“Shares”), consisting of Limited Liability Shares of Membership Interests (“Limited Liability Shares”) and Investor GP Shares of Membership Interests (“Investor GP Shares”), primarily at $200 thousand per whole Share. The Limited Liability Shares and the Investor GP Shares constitute a single class of securities as defined in Section 12(g) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). In 2011, pursuant to the limited liability company agreement (the “LLC Agreement”), Ridgewood Energy Corporation, as manager of the Fund, converted all then outstanding Investor GP Shares to Limited Liability Shares. There is no public market for the Shares and one is not likely to develop. In addition, the Shares are subject to material restrictions on transfer and resale and cannot be transferred or resold except in accordance with the Fund’s LLC Agreement and applicable federal and state securities laws. The private placement offering was terminated on December 17, 2007. The Fund raised $66.0 million and, after payment of $10.8 million in offering fees, commissions and investment fees, the Fund had $55.2 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 the Fund’s 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 the Fund’s 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 receive an annual management fee, payable monthly, equal to 2.5% of the total capital contributions made by the Fund’s shareholders, net of cumulative dry-hole and related well costs incurred by the Fund. The Manager is entitled to receive the management fee from the Fund regardless of the Fund’s profitability in that year. Management fees during each of the years ended December 31, 2018 and 2017 were $0.9 million. Additionally, the Manager is entitled to receive 15% of the cash distributions from operations made by the Fund. Distributions paid to the Manager during the year ended December 31, 2018 were $0.2 million. The Fund did not pay distributions during the year ended December 31, 2017.
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 six 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 four 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 4 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 $12.08 (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 $38.85 per barrel and $50.44 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 $4.86 per mmbtu and $8.41 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 a working interest as of December 31, 2018. 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 working interests in developed and undeveloped oil and natural gas acreage as of December 31, 2018. 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.
Beta Project - Partial Sale of Working Interest
On August 10, 2018, the Fund entered into a purchase and sale agreement (“PSA”) to sell a portion of the Fund’s working interest in the Beta Project to Walter Oil & Gas Corporation and Gordy Oil Company (collectively, the “Buyers”) with an effective date of January 1, 2018. Certain other funds managed by the Manager were also parties to the PSA. The Fund had a 3.0% working interest in the Beta Project and sold a 0.11% working interest to the Buyers for a total purchase price of $1.0 million, subject to purchase price and customary post-closing adjustments. The transaction closed on August 10, 2018 and the Fund received $0.9 million in cash, which included preliminary purchase price adjustments primarily related to the net cash flows from the effective date to the closing date. During fourth quarter 2018, the Fund recognized a post-closing adjustment in the amount of $10 thousand, which was recorded as an adjustment to the purchase price.
The net carrying value of the working interest sold as of the closing date was $0.7 million and the related asset retirement obligation was $12 thousand. A gain to the Fund of $0.3 million was recognized during the year ended December 31, 2018, including post-closing adjustments. The proceeds from the sale were utilized to repay a portion of the long-term debt outstanding under the Fund’s credit agreement. See Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” of this Annual Report under the heading “Liquidity Needs - Credit Agreement” for information regarding the Fund’s credit agreement.
Marketing/Customers
The Manager, on behalf of the Fund, markets the Fund’s oil and natural gas to third parties consistent with industry practice. The Fund utilizes Beta Sales and Transport, LLC (“Beta S&T”), a wholly-owned subsidiary of the Manager, as 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. The number of customers purchasing the Fund’s oil and natural gas may vary from time to time. Currently, the Fund has two major customers in the public market. Because a ready market exists for oil and natural gas, the Fund does not believe that the loss of any individual customer would have a material adverse effect on its financial position or results of operations. The Fund’s current producing projects are near existing transportation infrastructure and pipelines.
The 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 2018.
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 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 entities 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, 2018, the Fund had $2.7 million invested in a salvage fund. On a monthly basis, the Fund contributes 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. BSEE has also published a policy statement on safety culture with nine characteristics of a robust safety culture. 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 was 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. 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. On April 27, 2018, BSEE proposed significant revisions to the existing regulations for well control and blowout preventer systems contained in the Well Control Rule. The proposed rulemaking was published in the Federal Register on May 11, 2018, and the public comment period closed on August 6, 2018. On September 28, 2018, the BSEE published a final rule revising regulations relating to oil and natural gas production safety systems, subsurface safety devices and safety device testing (referred to as “Subpart H”); the rule was effective December 27, 2018. Given the fact that compliance with the Well Control Rule and Subpart H 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 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 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 NTL. However, as of December 31, 2018, the BOEM has not completed its review nor has the NTL been enforced. 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 environmental damage attributable to the Fund’s operations. 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 defines 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 $137.66 million (effective as of February 20, 2018) 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, as well as analogous state requirements, 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 delegated state agency. Regulations governing water discharges also impose other requirements, such as the obligation to prepare spill response plans. On December 11, 2018, the Environmental Protection Agency and Department of the Army proposed a revised definition of “waters of the United States”, clarifying the limits of federal authority under the Clean Water Act. The scope of this authority, as defined under a 2015 rule, was challenged in several federal district court actions. The proposed revision will be the subject of a 60-day public comment period, once published in the Federal Register. 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”), as well as analogous state requirements, 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 and comparable state requirements.
Climate Change. The oil and gas industry is subject to federal and state greenhouse gas monitoring, reporting and emissions control requirements. The current state of international climate initiatives and federal and state actions presents challenges to assessing the impact to the Fund’s operations in relation to future international agreements, federal and state legislation, and other new requirements. Future restrictions on emissions of greenhouse gases could have an impact on future operations.
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 Fund’s operations may be subject to analogous and comparable state laws and regulations, in addition to these federal statutes and regulations.
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 laws 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 derivatives 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 2018, 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. No replacement rules have been proposed or issued by the SEC.
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, 2018 and 2017. Gross wells are the total number of wells in which the Fund has a working 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. During the years ended December 31, 2018 and 2017, the Fund had no drilling activity for exploratory wells. See Item 1. “Business” of this Annual Report under the heading “Properties” for more information about the well in-progress as of December 31, 2018.
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, 2018 and 2017 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, 2018, the Fund did not have 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. The Beta Project was determined to be a discovery in 2012, which commenced production in 2016. During the year ended December 31, 2018, the Fund incurred costs to advance the development of its proved undeveloped reserves of approximately $0.9 million, related to the Beta Project.
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, 2018 and 2017 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, 2018, 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, 2019, there were 852 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, borrowing repayments 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. During the year ended December 31, 2018, the Fund paid distributions totaling $1.3 million. The Fund did not pay distributions during the year ended December 31, 2017.
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 natural 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 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.
The Manager performs, or arranges for the performance of, the management, advisory and administrative services required for the Fund’s 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 oil and natural gas commodity prices may significantly affect liquidity and expected operating results. Declines in oil and natural gas commodity prices not only reduce revenues and profits, but could also reduce the quantities of reserves that are commercially recoverable and 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 oil and natural gas commodity price environment, the Fund continued to advance the development of the Beta Project, which commenced production in 2016. The Fund continues to conserve cash to complete the final phase of the Beta Project as budgeted. 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, 2018 and 2017 and the effect of such average prices on the Fund’s results of operations. If oil and natural gas commodity 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, oil and natural gas commodity prices and future development costs will change from period to period, causing estimates of proved reserves and future net revenues to change.
Asset Retirement Obligations
Asset retirement obligations include costs to plug and abandon the Fund’s wells and to dismantle and relocate or dispose of the Fund’s production platforms and related structures and restoration costs of land and seabed. The Fund develops estimates of these costs based upon the type of production structure, water depth, reservoir depth and characteristics and ongoing discussions with the wells’ operators. Because these costs typically extend many years into the future, estimating these future costs is difficult and requires significant judgment that is subject to future revisions based upon numerous factors 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 annually, 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 whenever events and circumstances indicate that the recorded carrying value of the assets may not be recoverable. Impairments are determined by comparing estimated future net undiscounted cash flows to the carrying value of the assets 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 a valuation technique that considers both market and income approaches and uses Level 3 inputs. 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.
Results of Operations
The following table summarizes the Fund’s results of operations during the years ended December 31, 2018 and 2017, 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, 2018 and 2017. NGL sales are included within gas sales.
The increases in the number of wells producing and production days primarily related to the commencement of production of two wells in the Beta Project during 2018. The increases in sales volume primarily related to the Liberty Project, which experienced increased production as a result of recompletion work in third quarter 2017. See Item 1. “Business” of this Annual Report under the heading “Properties” for more information.
Oil and Gas Revenue. Oil and gas revenue during the year ended December 31, 2018 was $12.0 million, an increase of $4.0 million from the year ended December 31, 2017. The increase was attributable to increased oil and gas prices totaling $2.9 million coupled with increased sales volume totaling $1.1 million.
See “Overview” above for factors that impact the oil and gas revenue volume and rate variances.
Other Revenue from Affiliate. Other revenue from affiliate is generated from the Fund’s production handling, gathering and operating services agreement with an affiliated entity. See Note 3 of “Notes to Financial Statements” - “Related Parties” contained in Item 8. “Financial Statements and Supplementary Data” within this Annual Report for more information. There were no such amounts recorded during the year ended December 31, 2017.
Depletion and Amortization. Depletion and amortization during the year ended December 31, 2018 was $5.2 million, a decrease of $0.5 million from the year ended December 31, 2017. The decrease was attributable to a decrease in the average depletion rate totaling $1.4 million, partially offset by an increase in production volumes totaling $1.0 million. The decrease in the average depletion rate was primarily attributable to lower cost of reserves from 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.
Management Fees to Affiliate. An annual management fee, totaling 2.5% of total capital contributions, net of cumulative dry-hole and related well costs incurred by the Fund, is paid monthly to the Manager. Such fee may be temporarily waived by the Manager to accommodate the Fund’s short-term commitments.
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 relate to the Fund’s producing projects. Insurance expense represents premiums related to the Fund’s projects, which vary depending upon the number of wells producing or drilling. Accretion expense relates to the asset retirement obligations established for the Fund’s oil and gas properties. Workover expense represents costs to restore or stimulate production of existing reserves.
Production costs, which include lease operating expense, transportation and processing expense and insurance expense, was $1.4 million ($6.14 per barrel of oil equivalent or “BOE”) during the year ended December 31, 2018, compared to $1.2 million ($6.28 per BOE) during the year ended December 31, 2017. The increase in production costs was primarily related to the Liberty Project, which experienced increased production during 2018. See “Overview” above for factors that impact oil and natural gas production.
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.
Gain on Sale of Oil and Gas Properties. During the year ended December 31, 2018, the Fund recorded a gain on sale of oil and gas properties of $0.3 million related to the sale of a portion of the Fund’s working interest in the Beta Project. See Item 1. “Business” of this Annual Report under the heading “Beta Project - Partial Sale of Working Interest” for additional information regarding the sale. There was no such amount recorded during the year ended December 31, 2017.
Gain on Debt Extinguishment. During the year ended December 31, 2018, the Fund recorded a gain on debt extinguishment of $2.3 million related to accounting for the third amendment to the credit agreement. See Note 4 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 Fund’s credit agreement. There was no such amount recorded during the year ended December 31, 2017.
Other Income. During the year ended December 31, 2018, the Fund recorded other income of $0.1 million related to a fee received upon execution of the Fund’s production handling, gathering and operating services agreement with an affiliated entity. There were no such amounts recorded during the year ended December 31, 2017.
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, and interest income earned on cash and cash equivalents and salvage fund. See Note 4 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 Fund’s credit agreement.
Capital Resources and Liquidity
Operating Cash Flows
Cash flows provided by operating activities during the year ended December 31, 2018 were $9.3 million, primarily related to revenue received of $12.3 million, partially offset by operating expenses of $1.4 million, management fees of $0.9 million, interest payments of $0.6 million and general and administrative expenses of $0.2 million.
Cash flows provided by operating activities during the year ended December 31, 2017 were $4.2 million, primarily related to revenue received of $7.5 million, partially offset by interest payments of $1.1 million, operating expenses of $1.1 million, management fees of $0.9 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, 2018 were $3.0 million, related to capital expenditures for oil and gas properties of $3.5 million and investments in salvage fund of $0.4 million, partially offset by proceeds from sale of oil and gas properties of $0.9 million.
Cash flows used in investing activities during the year ended December 31, 2017 were $4.0 million, related to capital expenditures for oil and gas properties of $3.9 million and investments in salvage fund of $0.1 million.
Financing Cash Flows
Cash flows used in financing activities during the year ended December 31, 2018 were $4.1 million, related to the repayments of long-term borrowings of $2.8 million and manager and shareholder distributions of $1.3 million.
Cash flows used in financing activities during the year ended December 31, 2017 were $0.9 million, related to the repayment of 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 through debt financing. The Fund’s 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, 2018, the Fund’s estimated capital commitments related to its oil and gas properties were $4.8 million (which include asset retirement obligations for the Fund’s projects of $3.0 million), of which $0.6 million is expected to be spent during the year ending December 31, 2019. 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 temporarily waive all or a portion of the management fee as well as provide short-term financing to accommodate the Fund’s short-term commitments if needed.
The Manager is entitled to receive an annual management fee from the Fund regardless of the Fund’s profitability in that year. However, pursuant to the terms of the LLC Agreement, the Manager is also permitted to waive the management fee at its own discretion.
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, borrowing repayments and funding its estimated asset retirement obligations.
Credit Agreement
On June 1, 2018, the Fund and other participating funds managed by the Manager, and Rahr Energy Investments LLC, as administrative agent and lender (and other lenders that may become a party thereto, collectively “Lenders”), entered into a third amendment (the “Third Amendment”) effective as of September 1, 2018 to the credit agreement, dated as of November 27, 2012 (as amended by the first amendment to credit agreement, dated September 30, 2016, and the second amendment to credit agreement and reaffirmation of waiver, dated September 15, 2017, and as amended by the Third Amendment, the “Credit Agreement”). Subsequently, in conjunction with the sale of a portion of the Beta Project working interest and the repayment of a portion of the amounts outstanding under the Credit Agreement, on August 10, 2018, the Fund and other participating funds managed by the Manager and the Lenders entered into a fourth amendment (the “Fourth Amendment”) to the Credit Agreement effective as of September 1, 2018. As of December 31, 2018 and 2017, the Fund had borrowings of $5.7 million and $8.5 million, respectively, under the Credit Agreement.
The Third Amendment extended the loan maturity from December 31, 2020 to December 31, 2022, revised the interest rate and required a monthly payment amount based on a fixed percentage of the Fund’s Net Revenue (as defined in the Credit Agreement) derived from the Beta Project. Previously, the annual interest rate of the loan was 8% compounded annually and the monthly principal and interest payments were based on the lesser of the monthly fixed amount of approximately $0.3 million or the Debt Service Cap amount, as defined in the old credit agreement. The Third Amendment also changed the overriding royalty interest (“ORRI”) in its working interest in the Beta Project conveyed to the Lenders to a fixed percentage of 8.16% from a tiered structure, and deferred the payment of such ORRI, which will not become payable to the Lenders until January 1, 2023. The Credit Agreement also required mandatory prepayment of excess cash flows received by the Fund from certain insurance reimbursements, platform related revenues, production handling fees and any additional revenues received with respect to the use of the Beta Project other than any revenues included in the calculation of Net Revenue, as well as proceeds from a sale or transfer of any interest in the Beta Project as permitted under the Credit Agreement.
In August 2018, the proceeds from the sale of a portion of the working interest in the Beta Project were used to reduce the outstanding debt under the Credit Agreement. As a result, the Fourth Amendment principally reduced the fixed percentage for the calculation of the monthly payments and amended the interest calculation. Beginning on September 1, 2018 up to and including March 31, 2019, the Fund’s fixed percentage is 30%, which was based on the Fund’s ratio of outstanding debt to working interest ownership in the Beta Project determined on September 1, 2018, as scheduled in the Credit Agreement. Beginning on April 1, 2019 and each April 1st thereafter, the Fund’s fixed percentage will be the greater of (i) 30% or (ii) the Fixed Reassessment Percentage, as defined in the Credit Agreement. The Fixed Reassessment Percentage is determined annually and will be based on the Fund’s ratio of its outstanding debt as of the reassessment date relative to 80% of third-party reserve engineers’ proved plus probable future undiscounted cash flows attributable to the Beta Project through the maturity of the loan. Beginning on September 1, 2018 and thereafter until the loan is repaid in full, in no event later than December 31, 2022, the loan bears interest at a rate equal to 8.75% compounded monthly. The loan may be prepaid by the Fund without premium or penalty.
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 was in compliance with all covenants under the Credit Agreement as of December 31, 2018 and 2017.
See Note 4 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, 2018 and 2017 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, 2018 and 2017, 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 recent accounting pronouncements applicable to the Fund’s financial statements.
ITEM 7A.
ITEM 7A.QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Not required.
ITEM 8.
ITEM 8.FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
All financial statements meeting the requirements of Regulation S-X and the supplementary financial information required by Item 302 of Regulation S-K are included in the financial statements listed in Item 15. “Exhibits 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, 2018. 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, 2018. 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, 2018, 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, 2018 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, 2018 are as follows:
The officers in the above table have been officers of the Fund since May 17, 2007, the date of inception of the Fund, with the exception of Mr. Lang, who has been an officer of the Fund since June 2009. The officers are employed by and paid exclusively by the Manager. Set forth below is certain biographical information regarding the executive officers of Ridgewood Energy and the Fund:
Robert E. Swanson has served as the Chairman, Chief Executive Officer, and controlling shareholder of Ridgewood Energy since its inception and is the Chairman of the Investment Committee. Mr. Swanson is also the Chairman of Ridgewood Capital Management, LLC, 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 332.2918 shares outstanding as of January 31, 2019. No officer of the Manager or the Fund owns any of the Shares and no person owns more than 5% of the Shares.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
Pursuant to the terms of the LLC Agreement, the Manager renders management, advisory and administrative services to the Fund. For such services, the Manager is entitled to receive an annual management fee, payable monthly, of 2.5% of total capital contributions, net of cumulative dry-hole and related well costs incurred by the Fund. Management fees during each of the years ended December 31, 2018 and 2017 were $0.9 million.
The Manager is also entitled to receive 15% of the cash distributions from operations made by the Fund. Distributions paid to the Manager during the year ended December 31, 2018 were $0.2 million. The Fund did not pay distributions during the year ended December 31, 2017.
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.
On December 12, 2016, the Fund and other third party working interest owners in the Beta Project (collectively, the “Beta Project Owners”) entered into a production handling, gathering and operating services agreement (“PHA”) with Ridgewood Claiborne, LLC, a wholly-owned entity of Ridgewood Energy Oil & Gas Fund II, L.P. (“Institutional Fund II”) and other third party working interest owners in the Claiborne Project (collectively, the “Producers”), whereby the Beta Project Owners will provide services related to the production handling and delivery of oil and natural gas production from the Claiborne Project via their owned Beta Project production facility. Institutional Fund II is an entity that is managed by the Fund’s Manager. Under the terms of the PHA, the Producers have agreed to pay the Beta Project Owners a fixed production handling fee for each barrel of oil and mcf of natural gas produced through the Beta Project production facility. The PHA was effective on December 12, 2016 and will continue in effect unless terminated by default, the Beta Project Owners or the Producers pursuant to the terms of the PHA (as amended on February 10, 2017, March 9, 2017, September 19, 2018 and November 30, 2018). See Note 3 of “Notes to Financial Statements” - “Related Parties” contained in Item 8. “Financial Statements and Supplementary Data” within this Annual Report for more information regarding the PHA.
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 oil and natural 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, 2018 and 2017.
(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.
RIDGEWOOD ENERGY W FUND, LLC
Date: March 1, 2019 By:
/s/ ROBERT E. SWANSON
Robert E. Swanson
Chief Executive Officer
(Principal Executive Officer)
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
Signature Capacity Date
/s/ ROBERT E. SWANSON Chief Executive Officer March 1, 2019
Robert E. Swanson (Principal Executive Officer)
/s/ KATHLEEN P. MCSHERRY Executive Vice President and Chief Financial Officer March 1, 2019
Kathleen P. McSherry (Principal Financial and Accounting Officer)
RIDGEWOOD ENERGY CORPORATION
BY: /s/ ROBERT E. SWANSON Chief Executive Officer of the Manager March 1, 2019
Robert E. Swanson
PAGE
Report of Independent Registered Public Accounting Firm
Balance Sheets as of December 31, 2018 and 2017
Statements of Operations for the years ended December 31, 2018 and 2017
Statements of Changes in Members' Capital for the years ended December 31, 2018 and 2017
Statements of Cash Flows for the years ended December 31, 2018 and 2017
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 the Manager of Ridgewood Energy W Fund, LLC
Opinion on the Financial Statements
We have audited the accompanying balance sheets of Ridgewood Energy W Fund, LLC (the "Fund") as of December 31, 2018 and 2017, the related statements of operations, changes in members’ capital, and cash flows, for each of the two years in the period ended December 31, 2018, 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, 2018 and 2017, and the results of its operations and its cash flows for each of the two years in the period ended December 31, 2018, 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 1, 2019
We have served as the Fund's auditor since 2007.
RIDGEWOOD ENERGY W FUND, LLC
BALANCE SHEETS
(in thousands, except share data)
The accompanying notes are an integral part of these financial statements.
RIDGEWOOD ENERGY W FUND, LLC
STATEMENTS OF OPERATIONS
(in thousands, except per share data)
The accompanying notes are an integral part of these financial statements.
RIDGEWOOD ENERGY W 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 W FUND, LLC
STATEMENTS OF CASH FLOWS
(in thousands)
The accompanying notes are an integral part of these financial statements.
RIDGEWOOD ENERGY W FUND, LLC
NOTES TO FINANCIAL STATEMENTS
1. Organization and Summary of Significant Accounting Policies
Organization
The Ridgewood Energy W Fund, LLC (the “Fund”), a Delaware limited liability company, was formed on May 17, 2007 and operates pursuant to a limited liability company agreement (the “LLC Agreement”) dated as of June 15, 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 the Fund’s 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 the Fund’s 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 3, 4 and 5.
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 Fund follows the accounting guidance for fair value measurement for measuring fair value of assets and liabilities in its financial statements. 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.
The Fund’s financial instruments consist of cash and cash equivalents, salvage fund, production receivable, due from affiliate, other current assets, due to operators, accrued expenses, other current liabilities and long-term debt. Except for long-term debt, the carrying amounts of these instruments approximate fair value due to their short-term nature. The Fund’s long-term debt is valued using an income approach and is classified as Level 3 in the fair value hierarchy. The fair value of the long-term debt is estimated by discounting future cash payments of principal and interest to a present value amount using a market yield for debt instruments with similar terms, maturities and credit ratings. The Fund also applies the provisions of the fair value measurement accounting guidance to its non-financial assets and liabilities, such as oil and gas properties and asset retirement obligations, on a non-recurring basis.
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, 2018, 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, 2018, 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.
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. 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. 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 Fund maintains a salvage fund to provide for the funding of future asset retirement obligations. The following table presents changes in asset retirement obligations during the years ended December 31, 2018 and 2017:
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
The Fund adopted the new revenue standard on January 1, 2018 using the modified retrospective method for all new contracts entered into after January 1, 2018 and all existing contracts for which revenues have not been recognized under the previous revenue guidance as of December 31, 2017. Although the Fund did not identify changes to its revenue recognition that resulted in a cumulative adjustment to retained earnings on January 1, 2018, the adoption of the accounting guidance resulted in enhanced disclosures related to revenue recognition policies, the Fund’s performance obligations and significant judgments used in applying the new revenue standard as described below.
Revenue from Contracts with Customers
Oil and gas revenues are recognized at the point when control of oil and natural gas is transferred to the customers. Natural gas liquid (“NGL”) sales are included within gas sales. The Fund’s oil and natural gas generally is sold to its customers at prevailing market prices based on an index in which the prices are published, adjusted for pricing differentials, quality of the oil and pipeline allowances.
Oil and Gas Revenue
Generally, the Fund sells oil and natural gas under two types of agreements, which are common in the oil and gas industry. In the first type of agreement, a netback agreement, the Fund receives a price, net of pricing differentials as well as transportation expense incurred by the customer, and the Fund records revenue at the wellhead at the net price received where control transfers to the customer. In the second type of agreement, the Fund delivers oil and natural gas to the customer at a contractually agreed-upon delivery point where the customer takes control. The Fund pays a third-party to transport the oil and natural gas and receives a specific market price from the customer net of pricing adjustments. The Fund records the transportation expense within operating expenses in the statements of operations.
Under the Fund’s natural gas processing contracts, the Fund delivers natural gas to a midstream processing company at the inlet of the midstream processing company’s facility. The midstream processing company gathers and processes the natural gas and remits the proceeds to the Fund for the sale of NGLs. In this type of arrangement, the Fund evaluates whether it is the principal or agent in the transaction. The Fund concluded that it is the principal and the ultimate third-party purchaser is the customer; therefore, the Fund recognizes revenue on a gross basis, with transportation, gathering and processing fees recorded as an expense within operating expenses in the statements of operations.
In certain instances, the Fund may elect to take its residue gas and NGLs in-kind at the tailgate of the midstream company’s processing plant and subsequently market such volumes. Through its marketing process, the Fund delivers the residue gas and NGLs to the ultimate third-party customer at a contractually agreed-upon delivery point and receives a specified market price from the customer. In this arrangement, the Fund recognizes revenue when control transfers to the customer at the delivery point based on the market price received from the customer. The transportation, gathering and processing fees are recorded as expense within operating expenses in the statements of operations.
The Fund assesses the performance obligations promised in its oil and natural gas contracts based on each unit of oil and natural gas that will be transferred to its customer because each unit is capable of being distinct. The Fund satisfies its performance obligation when control transfers at a point in time when its customer is able to direct the use of, and obtain substantially all of the benefits from, the oil and natural gas delivered. Under each of the Fund’s oil and natural gas contracts, contract prices are variable and based on an index in which the prices are published, which fluctuate as a result of related industry variables, adjusted for pricing differentials, quality of the oil and pipeline allowances. The use of index-based pricing with predictable differentials reduces the level of uncertainty related to oil and gas prices. Additionally, any variable consideration is not constrained. Payments are received in the month following the oil and natural gas production month. Adjustments that occur after delivery, such as quality bank adjustments, are reflected in revenue in the month payments are received.
Transaction Price Allocated to Remaining Performance Obligations
Under the Fund’s oil and natural gas contracts, each unit of oil and natural gas represents a separate performance obligation; therefore, future volumes are wholly unsatisfied and the transaction price related to the remaining performance obligations is the variable index-based price attributable to each unit of oil and natural gas that is transferred to the customer.
Contract Balances
The Fund invoices customers once its performance obligations have been satisfied, at which point the payment is unconditional. Accordingly, the Fund’s oil and natural gas contracts do not give rise to contract assets or liabilities under the new revenue standard. The receivables related to the Fund’s oil and gas revenue are included within “Production receivable” on the balance sheets.
Prior Period Performance Obligations
The Fund records oil and gas revenue in the month production is delivered to its customers. However, settlement statements for residue gas and NGLs sales may not be received for 30 to 60 days after the date production is delivered. As a result, the Fund is required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the residue gas and NGLs. The Fund records the differences between its estimates and the actual amounts received in the month that the payment is received from the customer. The Fund has an estimation process for revenue and related accruals, and any identified difference between its revenue estimates and actual revenue historically have not been significant. There was no material revenue recognized in the current period from performance obligations satisfied in previous periods.
Other Revenue from Affiliate
Other revenue is generated from the Fund’s production handling, gathering and operating services agreement with an affiliated entity. The Fund simply earns a fee for its services and recognizes these fees as revenue at the time its performance obligations are satisfied as the control of oil and natural gas is never transferred to the Fund.
Impairment of Long-Lived Assets
The Fund reviews the carrying value of its oil and gas properties for impairment whenever events and circumstances indicate that the recorded carrying value of its oil and gas properties may not be recoverable. Impairments are determined by comparing estimated future net undiscounted cash flows to the carrying value of the assets 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 a valuation technique that considers both market and income approaches and uses Level 3 inputs. 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.
There were no impairments of oil and gas properties during the years ended December 31, 2018 and 2017. Fluctuations in oil and natural gas commodity prices may impact the fair value of the Fund’s oil and gas properties. If oil and natural gas commodity prices decline, even if only for a short period of time, it is possible that 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 2015 through 2017 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 August 2018, the Financial Accounting Standards Board (“FASB”) issued accounting guidance on fair value measurement, which adds, among other things, disclosure requirements for the range and weighted average of significant unobservable inputs used to develop Level 3 fair value measurements. This accounting guidance is effective for the Fund in the first quarter 2020 with early adoption permitted. The Fund does not expect this accounting guidance will have a material impact on its financial statements upon adoption.
In February 2016, the FASB issued accounting guidance on leases as amended on January 2018 and July 2018, which requires an entity to recognize all lease assets and liabilities with a term greater than one year on the balance sheet, disclose key quantitative and qualitative information about leasing arrangements, and permits an entity not to evaluate existing or expired land easements that were not previously assessed under the existing lease guidance. The accounting guidance does not apply to leases of mineral rights to explore for or use of oil and natural gas. The accounting guidance is effective for the Fund beginning January 1, 2019 with early adoption permitted. Although the Fund, as a non-operator, does not enter into lease agreements to support its operations, the Fund completed its evaluation of existing contracts that may have a lease impact and embedded lease features to determine the contracts to which the new guidance applies. Based on this evaluation, the Fund determined its existing contracts did not meet the definition of leases under the new accounting guidance and therefore, did not qualify for lease accounting.
In May 2014, the FASB issued accounting guidance on revenue recognition (“New Revenue Standard”), 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 New Revenue Standard 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 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 New Revenue Standard. The New Revenue Standard may be applied either retrospectively or through the use of a modified-retrospective method. Under the New Revenue Standard, 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 the Fund’s previous revenue recognition model. The Fund adopted the New Revenue Standard using the modified retrospective method on January 1, 2018. See “Revenue Recognition” above for the required disclosures related to the impact of adopting this guidance and a discussion of the Fund’s updated policies related to revenue recognition for revenue from contracts with customers.
2. Oil and Gas Properties
On August 10, 2018, the Fund entered into a purchase and sale agreement (“PSA”) to sell a portion of the Fund’s working interest in the Beta Project to Walter Oil & Gas Corporation and Gordy Oil Company (collectively, the “Buyers”) with an effective date of January 1, 2018. Certain other funds managed by the Manager were also parties to the PSA. The Fund had a 3.0% working interest in the Beta Project and sold a 0.11% working interest to the Buyers for a total purchase price of $1.0 million, subject to purchase price and customary post-closing adjustments. The transaction closed on August 10, 2018 and the Fund received $0.9 million in cash, which included preliminary purchase price adjustments primarily related to the net cash flows from the effective date to the closing date. During fourth quarter 2018, the Fund recognized a post-closing adjustment in the amount of $10 thousand, which was recorded as an adjustment to the purchase price and included within “Gain on sale of oil and gas properties” on its statements of operations.
The net carrying value of the working interest sold as of the closing date was $0.7 million and the related asset retirement obligation was $12 thousand. A gain to the Fund of $0.3 million was recognized during the year ended December 31, 2018, including post-closing adjustments. The proceeds from the sale were utilized to repay a portion of the long-term debt outstanding under the credit agreement.
3. Related Parties
Pursuant to the terms of the LLC Agreement, the Manager is entitled to receive 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, however, the Manager is permitted to waive the management fee at its own discretion. Therefore, the management fee may be temporarily waived to accommodate the Fund’s short-term commitments. Management fees during each of the years ended December 31, 2018 and 2017 were $0.9 million.
The Manager is also entitled to receive 15% of the cash distributions from operations made by the Fund. Distributions paid to the Manager during the year ended December 31, 2018 were $0.2 million. The Fund did not pay distributions during the year ended December 31, 2017.
Beta Sales and Transport, LLC
The Fund utilizes Beta Sales and Transport, LLC (“Beta S&T”), a wholly-owned subsidiary of the Manager, as 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.
Production Handling, Gathering and Operating Services Agreement
On December 12, 2016, the Fund and other third party working interest owners in the Beta Project (collectively, the “Beta Project Owners”) entered into a production handling, gathering and operating services agreement (“PHA”) with Ridgewood Claiborne, LLC, a wholly-owned entity of Ridgewood Energy Oil & Gas Fund II, L.P. (“Institutional Fund II”) and other third party working interest owners in the Claiborne Project (collectively, the “Producers”), whereby the Beta Project Owners will provide services related to the production handling and delivery of oil and natural gas production from the Claiborne Project via their owned Beta Project production facility. Institutional Fund II is an entity that is managed by the Fund’s Manager. The PHA was effective on December 12, 2016 and will continue in effect unless terminated by default, the Beta Project Owners or the Producers pursuant to the terms of the PHA (as amended on February 10, 2017, March 9, 2017, September 19, 2018 and November 30, 2018).
Under the terms of the PHA, the Producers have agreed to pay the Beta Project Owners a fixed production handling fee for each barrel of oil and mcf of natural gas processed through the Beta Project production facility. Beginning in fourth quarter 2018, the Beta Project Owners commenced their production and handling services for the oil and natural gas produced from the Claiborne Project. As the control of oil and natural gas is never transferred, the Fund simply earns a fee for its services and recognizes these fees as revenue at the time its performance obligations are satisfied. During the year ended December 31, 2018, the Fund earned $0.1 million representing its proportionate share of the production handling fees earned from the production handling services, which are included within “Other revenue from affiliate” on its statements of operations and “Due from affiliate” on its balance sheets. The transactions are settled by issuance of a non-cash credit from the Beta Project operator to the Fund on behalf of the Producers when the operator performs the joint interest billing of the lease operating expenses due from the Fund. The revenue received from the PHA will be utilized by the Fund to repay a portion of the long-term debt outstanding under its credit agreement until the loan is repaid in full, in no event later than December 31, 2022. During the year ended December 31, 2018, the Fund recorded other income of $0.1 million related to a fee received upon execution of the PHA. There were no such amounts recorded during the year ended December 31, 2017.
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 oil and natural gas projects, which are also owned by other entities that are likewise managed by the Manager.
4. Credit Agreement - Beta Project Financing
On June 1, 2018, the Fund and other participating funds managed by the Manager, and Rahr Energy Investments LLC, as administrative agent and lender (and other lenders that may become a party thereto, collectively “Lenders”), entered into a third amendment (the “Third Amendment”) effective as of September 1, 2018 to the credit agreement, dated as of November 27, 2012 (as amended by the first amendment to credit agreement, dated September 30, 2016, and the second amendment to credit agreement and reaffirmation of waiver, dated September 15, 2017 and as amended by the Third Amendment, the “Credit Agreement”). Subsequently, in conjunction with the sale of a portion of the Beta Project working interest and the repayment of a portion of amounts outstanding on the Credit Agreement, on August 10, 2018, the Fund and other participating funds managed by the Manager and the Lenders entered into a fourth amendment (the “Fourth Amendment”) to the Credit Agreement effective as of September 1, 2018.
The Third Amendment extended the loan maturity from December 31, 2020 to December 31, 2022, revised the interest rate and required a monthly payment amount based on a fixed percentage of the Fund’s Net Revenue (as defined in the Credit Agreement) derived from the Beta Project. Previously, the annual interest rate of the loan was 8% compounded annually and the monthly principal and interest payments were based on the lesser of the monthly fixed amount of approximately $0.3 million or the Debt Service Cap amount, as defined in the old credit agreement. The Third Amendment also changed the overriding royalty interest (“ORRI”) in its working interest in the Beta Project conveyed to the Lenders to a fixed percentage of 8.16% from a tiered structure, and deferred the payment of such ORRI, which will not become payable to the Lenders until January 1, 2023. The Credit Agreement also required mandatory prepayment of excess cash flows received by the Fund from certain insurance reimbursements, platform related revenues, production handling fees and any additional revenues received with respect to the use of the Beta Project other than any revenues included in the calculation of Net Revenue, as well as proceeds from a sale or transfer of any interest in the Beta Project as permitted under the Credit Agreement.
In August 2018, the proceeds from the sale of a portion of the working interest in the Beta Project were used to reduce the outstanding debt under the Credit Agreement. As a result, the Fourth Amendment principally reduced the fixed percentage for the calculation of the monthly payments and amended the interest calculation. Beginning on September 1, 2018 up to and including March 31, 2019, the Fund’s fixed percentage is 30%, which was based on the Fund’s ratio of outstanding debt to working interest ownership in the Beta Project determined on September 1, 2018, as scheduled in the Credit Agreement. Beginning on April 1, 2019 and each April 1st thereafter, the Fund’s fixed percentage will be the greater of (i) 30% or (ii) the Fixed Reassessment Percentage, as defined in the Credit Agreement. The Fixed Reassessment Percentage is determined annually and will be based on the Fund’s ratio of its outstanding debt as of the reassessment date relative to 80% of third-party reserve engineers’ proved plus probable future undiscounted cash flows attributable to the Beta Project through the maturity of the loan. Beginning on September 1, 2018 and thereafter until the loan is repaid in full, in no event later than December 31, 2022, the loan bears interest at a rate equal to 8.75% compounded monthly.
The Fund reviewed the terms of the Third Amendment and determined that the conditions were met, pursuant to Accounting Standard Codification 470-50 Debt: Modification and Extinguishments (“ASC 470-50”) guidance, to treat the Third Amendment as a debt extinguishment in a non-troubled debt restructuring. Pursuant to ASC 470-50 guidance, the new debt instrument shall be initially recorded at fair value and the difference between the fair value of the new debt instrument and the carrying amount of the debt being extinguished is recognized as a gain or loss on extinguishment of debt. Additionally, the difference in the fair value of the ORRI before and after the Third Amendment is included in the gain or loss recognized upon extinguishment of the debt. The Fund then reviewed the terms of the Fourth Amendment and determined that the Fourth Amendment met the conditions of debt modification pursuant to ASC 470-50 guidance in a non-troubled debt restructuring.
The Fund recognized a gain on debt extinguishment of $2.3 million during third quarter 2018, which is recorded within “Other income (loss)” in its statements of operations. The gain on debt extinguishment primarily represents non-cash gains associated with the change in the fair value of ORRI conveyed to the Lenders totaling $2.3 million and the difference between the fair value of the new debt and the carrying amount of the old debt totaling $28 thousand. The Fund estimated the fair value of the ORRI before and after the Third Amendment using a discounted cash flow method based on Level 3 inputs, which included future revenue from proved and probable oil and natural gas reserves from the Beta Project, future commodity pricing curves to derive future cash flows and a risk-adjusted discount rate of 9.0%. The change in the fair value of the ORRI of $2.3 million was recorded as an increase to property within “Total oil and gas properties, net” on the Fund’s balance sheet, which is being amortized to depletion expense using the units-of-production method over the life of the Beta Project. The Fund estimated the fair value of the amended debt by discounting future cash payments of principal and interest to a present value amount using a market yield for debt instruments with similar terms, maturities and credit ratings. The Fund used a market yield of 9.25% to estimate the fair value of the amended debt, which was determined to be $5.7 million. The discounted loan is being accreted to its face value over the remaining term of the amended debt.
As of December 31, 2018 and 2017, the Fund had borrowings of $5.7 million and $8.5 million, respectively, under the Credit Agreement. The loan may be prepaid by the Fund without premium or penalty. As of December 31, 2018, the estimated fair value of the debt was $5.4 million.
The unamortized debt discounts related to the amended debt of $26 thousand as of December 31, 2018 were presented as a reduction of “Long-term borrowings” on the balance sheet. There were no unamortized debt discounts and deferred financing costs as of December 31, 2017. Amortization expense during the years ended December 31, 2018 and 2017 of $2 thousand and $0.1 million, respectively, was expensed and included on the statements of operations within “Interest expense, net”.
As of December 31, 2018 and 2017, there were no accrued interest costs outstanding. Interest costs incurred during the years ended December 31, 2018 and 2017 of $0.6 million and $0.8 million, respectively, were expensed and included on the statements of operations within “Interest expense, net.
As of December 31, 2018, the estimated principal repayments of debt are as follows: $1.7 million in 2019, $2.0 million in 2020 and $2.0 million in 2021.
The Credit Agreement contains customary covenants, with which the Fund was in compliance as of December 31, 2018 and 2017.
5. Commitments and Contingencies
Capital Commitments
As of December 31, 2018, the Fund’s estimated capital commitments related to its oil and gas properties were $4.8 million (which include asset retirement obligations for the Fund’s projects of $3.0 million), of which $0.6 million is expected to be spent during the year ending December 31, 2019. 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 temporarily waive all or a portion of the management fee as well as 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, 2018 and 2017, 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 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 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 NTL. However, as of December 31, 2018, the BOEM has not completed its review nor has the NTL been enforced. 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 entities managed by the Manager. Depending on the extent, nature and payment of claims made by the Fund or other entities 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 W 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, 2018 and 2017. 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 as of December 31, 2017 were attributable to extensions for the Beta Project.
(c)Revisions of previous estimates were attributable to well performance.
(d)On August 10, 2018, the Fund sold a portion of the Fund’s working interest in the Beta Project to third parties.
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.