Cover
Cover - USD ($) | 12 Months Ended | |
Dec. 31, 2022 | Feb. 27, 2023 | |
Cover [Abstract] | ||
Document Type | 10-K | |
Amendment Flag | false | |
Document Annual Report | true | |
Document Transition Report | false | |
Document Period End Date | Dec. 31, 2022 | |
Document Fiscal Period Focus | FY | |
Document Fiscal Year Focus | 2022 | |
Current Fiscal Year End Date | --12-31 | |
Entity File Number | 000-53895 | |
Entity Registrant Name | Ridgewood Energy A-1 Fund, LLC | |
Entity Central Index Key | 0001457919 | |
Entity Tax Identification Number | 01-0921132 | |
Entity Incorporation, State or Country Code | DE | |
Entity Address, Address Line One | 14 Philips Parkway | |
Entity Address, City or Town | Montvale | |
Entity Address, State or Province | NJ | |
Entity Address, Postal Zip Code | 07645 | |
City Area Code | 800 | |
Local Phone Number | 942-5550 | |
Title of 12(b) Security | None | |
Entity Well Known Seasoned Issuer | No | |
Entity Voluntary Filers | No | |
Entity Current Reporting Status | Yes | |
Entity Interactive Data Current | Yes | |
Entity Filer Category | Non-accelerated Filer | |
Entity Small Business | true | |
Entity Emerging Growth Company | false | |
Entity Shell Company | false | |
Entity Public Float | $ 0 | |
Entity Common Stock, Shares Outstanding | 207.7026 | |
ICFR Auditor Attestation Flag | false | |
Auditor Firm ID | 34 | |
Auditor Name | Deloitte & Touche LLP | |
Auditor Location | Morristown, New Jersey |
BALANCE SHEETS
BALANCE SHEETS - USD ($) $ in Thousands | Dec. 31, 2022 | Dec. 31, 2021 |
Current assets: | ||
Cash and cash equivalents | $ 264 | $ 791 |
Salvage fund | 40 | 46 |
Production receivable | 365 | 329 |
Due from affiliate (Note 2) | 10 | 19 |
Other current assets | 32 | 36 |
Total current assets | 711 | 1,221 |
Salvage fund | 1,986 | 1,830 |
Oil and gas properties: | ||
Proved properties | 17,927 | 17,439 |
Less: accumulated depletion and amortization | (14,181) | (12,116) |
Total oil and gas properties, net | 3,746 | 5,323 |
Total assets | 6,443 | 8,374 |
Current liabilities: | ||
Due to operators | 24 | 27 |
Accrued expenses | 119 | 66 |
Asset retirement obligations | 40 | 46 |
Total current liabilities | 183 | 139 |
Asset retirement obligations | 1,035 | 888 |
Total liabilities | 1,218 | 1,027 |
Members' capital: | ||
Distributions | (6,317) | (5,589) |
Retained earnings | 7,651 | 6,950 |
Manager's total | 1,334 | 1,361 |
Shareholders: | ||
Capital contributions (250 shares authorized; 207.7026 issued and outstanding) | 41,143 | 41,143 |
Syndication costs | (4,804) | (4,804) |
Distributions | (42,556) | (38,436) |
Retained earnings | 10,108 | 8,083 |
Shareholders' total | 3,891 | 5,986 |
Total members' capital | 5,225 | 7,347 |
Total liabilities and members' capital | $ 6,443 | $ 8,374 |
BALANCE SHEETS (Parenthetical)
BALANCE SHEETS (Parenthetical) - shares | Dec. 31, 2022 | Dec. 31, 2021 |
Statement of Financial Position [Abstract] | ||
Shares authorized | 250 | 250 |
Shares issued | 207.7026 | 207.7026 |
Shares outstanding | 207.7026 | 207.7026 |
STATEMENTS OF OPERATIONS
STATEMENTS OF OPERATIONS - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2022 | Dec. 31, 2021 | |
Revenue | ||
Oil and gas revenue | $ 5,459 | $ 3,173 |
Other revenue | 307 | 363 |
Total revenue | 5,766 | 3,536 |
Expenses | ||
Depletion and amortization | 2,065 | 1,959 |
Operating expenses | 544 | 386 |
Management fees to affiliate (Note 2) | 291 | 294 |
General and administrative expenses | 147 | 142 |
Total expenses | 3,047 | 2,781 |
Income from operations | 2,719 | 755 |
Interest income (expense) | 7 | (85) |
Net income | 2,726 | 670 |
Manager Interest | ||
Net income | 701 | 390 |
Shareholder Interest | ||
Net income | $ 2,025 | $ 280 |
Net income per share | $ 9,753 | $ 1,347 |
STATEMENTS OF CHANGES IN PARTNE
STATEMENTS OF CHANGES IN PARTNERS CAPITAL - USD ($) $ in Thousands | Shares of Llc Interest [Member] | Fund Manager [Member] | Fund Shareholders [Member] | Total |
Beginning balance, value at Dec. 31, 2020 | $ 1,099 | $ 6,435 | $ 7,534 | |
Beginning balance (in shares) at Dec. 31, 2020 | 207.7026 | |||
Distributions | (128) | (729) | (857) | |
Net income | 390 | 280 | 670 | |
Ending balance, value at Dec. 31, 2021 | 1,361 | 5,986 | $ 7,347 | |
Balance at ending (in shares) at Dec. 31, 2021 | 207.7026 | 207.7026 | ||
Distributions | (728) | (4,120) | $ (4,848) | |
Net income | 701 | 2,025 | 2,726 | |
Ending balance, value at Dec. 31, 2022 | $ 1,334 | $ 3,891 | $ 5,225 | |
Balance at ending (in shares) at Dec. 31, 2022 | 207.7026 | 207.7026 |
STATEMENTS OF CASH FLOWS
STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2022 | Dec. 31, 2021 | |
Cash flows from operating activities | ||
Net income | $ 2,726 | $ 670 |
Adjustments to reconcile net income to net cash provided by operating activities: | ||
Depletion and amortization | 2,065 | 1,959 |
Accretion expense | 27 | 27 |
Amortization of debt discounts | 7 | |
Changes in assets and liabilities: | ||
Increase in production receivable | (36) | (108) |
Decrease in due from affiliate | 9 | 73 |
Decrease in other current assets | 4 | 11 |
Increase in due to operators | 3 | 5 |
Increase in accrued expenses | 53 | 15 |
Settlement of asset retirement obligations | (6) | (305) |
Net cash provided by operating activities | 4,845 | 2,354 |
Cash flows from investing activities | ||
Capital expenditures for oil and gas properties | (374) | (579) |
Proceeds from salvage fund | 6 | 305 |
Increase in salvage fund | (156) | (155) |
Net cash used in investing activities | (524) | (429) |
Cash flows from financing activities | ||
Repayments of long-term borrowings | (1,427) | |
Distributions | (4,848) | (857) |
Net cash used in financing activities | (4,848) | (2,284) |
Net decrease in cash and cash equivalents | (527) | (359) |
Cash and cash equivalents, beginning of year | 791 | 1,150 |
Cash and cash equivalents, end of year | 264 | 791 |
Supplemental disclosure of cash flow information | ||
Cash paid for interest | 78 | |
Supplemental disclosure of non-cash investing activities | ||
Due to operators for accrued capital expenditures for oil and gas properties | $ 6 |
Organization and Summary of Sig
Organization and Summary of Significant Accounting Policies | 12 Months Ended |
Dec. 31, 2022 | |
Accounting Policies [Abstract] | |
Organization and Summary of Significant Accounting Policies | 1. Organization and Summary of Significant Accounting Policies Organization The Ridgewood Energy A-1 Fund, LLC (the “Fund”), a Delaware limited liability company, was formed on February 3, 2009 and operates pursuant to a limited liability company agreement (the “LLC Agreement”) dated as of March 2, 2009 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 2 and 3. 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, management 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 assets and liabilities consist of cash and cash equivalents, salvage fund, production receivable, due from affiliate, other current assets, due to operators and accrued expenses. The carrying amounts of these financial assets and liabilities approximate fair value due to their short-term nature. 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, 2022, the Fund had no cash equivalents. At times, deposits may be in excess of federally insured limits, which are $ 250 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. Accrued Expenses Accrued expenses consist of the following: December 31, 2022 2021 (in thousands) Accrued accounting and legal fees $ 63 $ 66 Accrued royalty 56 - $ 119 $ 66 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 based on expected future cash outflows required to satisfy the obligation discounted at the Fund’s credit-adjusted risk-free rate. 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, 2022 and 2021: Schedule of Changes in Asset Retirement Obligations December 31, 2022 2021 (in thousands) Balance, beginning of year $ 934 $ 1,565 Liabilities settled (6 ) (305 ) Accretion expense 27 27 Revision of estimates 120 (353 ) Balance, end of year $ 1,075 $ 934 During the year ended December 31, 2021, the Fund recorded credits to depletion expense totaling $ 0.3 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 Oil and gas revenues from contracts with customers are recognized at the point when control of oil and natural gas is transferred to the customers in accordance with Accounting Standard Codification Topic 606, Revenue from Contracts with Customers (“ASC 606”) ASC 606 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. Natural gas liquid (“NGL”) sales are included within gas revenues. The Fund’s oil and natural gas generally are sold to its customers at prevailing market prices based on an index in which the prices are published, adjusted for pricing differentials, quality of oil and pipeline allowances. 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 natural 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 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. The receivables related to the Fund’s oil and gas revenue are included within “Production receivable” on the Fund’s balance sheets. Other Revenue Other revenue is generated from the Fund’s production handling, gathering and operating services agreement with affiliated entities and other third parties. The Fund 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, thus there are no unsatisfied performance obligations. The Fund’s project operator performs joint interest billing once the performance obligations have been satisfied, at which point the payment is unconditional. Accordingly, the Fund’s production handling, gathering and operating services agreement with affiliated entities and other third parties does not give rise to contract assets or liabilities. The receivables related to the Fund’s proportionate share of revenue from affiliates are included within “Due from affiliate” on the Fund’s balance sheets. The receivables related to the Fund’s proportionate share of revenue from third parties are presented as a reduction from “Due to operator” on the Fund’s balance sheets. The receivables are settled by issuance of a non-cash credit from the Beta Project operator to the Fund when the operator performs the joint interest billing of the lease operating expenses due from the Fund. However, if applying the joint interest billing credit results in a net credit balance due to the Fund, the Beta Project operator remits such balance in cash to the Fund. 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. During the years ended December 31, 2022 and 2021, revenue recognized from performance obligations satisfied in previous periods was not significant. Allowance for Credit Losses The Fund is exposed to credit losses through the sale of oil and natural gas to customers. However, the Fund only sells to a small number of major oil and gas companies that have investment-grade credit ratings. Based on historical collection experience, current and future economic and market conditions and a review of the current status of customers' production receivables, the Fund has not recorded an expected loss allowance as there are no past due receivable balances or projected credit losses. 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. Recoverability is evaluated by comparing estimated future net undiscounted cash flows to the carrying value of the oil and gas properties at the time of the review. If the carrying value exceeds the estimated future net undiscounted cash flows, the carrying value of the oil and gas properties is impaired, and written down to fair value. Fair value is determined using valuation techniques that include both market and income approaches and use Level 3 inputs. The fair value determinations require considerable judgment and are sensitive to change. Different pricing assumptions, estimates of oil and gas reserves and future development costs or discount rates could result in a significant impact on the amount of impairment. There were no impairments of oil and gas properties during the years ended December 31, 2022 and 2021. Fluctuations in oil and natural gas commodity prices may impact the fair value of the Fund’s oil and gas properties. In addition, significant declines in oil and natural gas commodity prices could reduce the quantities of reserves that are commercially recoverable, which could result in impairment 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 2019 through 2021 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. In general, profits and losses in any year are allocated 85 15 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 1 85 15 Recent Accounting Pronouncements The Fund has considered recent accounting pronouncements issued during the year ended December 31, 2022 and through the filing of this report, and the Fund has not identified new standards that it believes will have an impact on the Fund’s financial statements. |
Related Parties
Related Parties | 12 Months Ended |
Dec. 31, 2022 | |
Related Party Transactions [Abstract] | |
Related Parties | 2 . 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 0.3 The Manager is also entitled to receive 15 0.7 0.1 Beta Sales and Transport, LLC The Fund utilizes Beta Sales and Transport, LLC (“Beta S&T”), a wholly-owned subsidiary of the Manager, 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. Production Handling, Gathering and Operating Services Agreement The Fund and other third-party working interest owners in the Beta Project (collectively, the “Beta Project Owners”) are parties to 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. The PHA was effective on December 12, 2016 and will continue in effect unless terminated by default, by 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, November 30, 2018 and December 1, 2018). On September 23, 2020, a third-party working interest owner of the Claiborne Project executed a consent letter to assign the rights to the services under the PHA to Ridgewood Rattlesnake, LLC, a wholly-owned entity of Ridgewood Energy Oil & Gas Fund III, L.P. (“Institutional Fund III”). On May 12, 2022, a third-party working interest owner executed an assignment and bill of sale agreement to assign the rights to the services under the PHA to Ridgewood Institutional IV Prospective Leases, LLC, a wholly-owned entity of Ridgewood Energy Oil & Gas Fund IV, L.P. (“Institutional Fund IV”). Institutional Fund II, Institutional Fund III and Institutional Fund IV are entities that are 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 processed through the Beta Project production facility. During each of the years ended December 31, 2022 and 2021, the Fund earned $ 0.1 10 19 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. |
Commitments and Contingencies
Commitments and Contingencies | 12 Months Ended |
Dec. 31, 2022 | |
Commitments and Contingencies Disclosure [Abstract] | |
Commitments and Contingencies | 3. Commitments and Contingencies Capital Commitments As of December 31, 2022, the Fund’s estimated capital commitments related to its oil and gas properties were $ 2.9 1.8 40 Overriding Royalty Interest (ORRI) Effective January 1, 2023, the fixed percentage ORRI of 10.81% in the Fund’s net revenue interest in the Beta Project’s oil and natural gas production becomes payable to the Fund’s former lender, which was conveyed pursuant to the Fund’s credit agreement applicable to the project. The ORRI will be recorded as a reduction to oil and gas revenue on the Fund’s statement of operations and as accrued royalty within “Accrued expenses” on the Fund’s balance sheet. Impact from market conditions The oil and gas market, and the global economy in general, is subject to sources of uncertainty relating to: (i) further escalation in the Russia-Ukraine conflict, which could result in a major oil supply disruption; (ii) a prolonged high inflationary environment, which could result in a deep global recession; and (iii) the refilling of strategic petroleum reserves by the U.S. and other nations, which could add to crude demand and potentially push oil prices higher. The impact of these matters on global financial and commodity markets and their corresponding effect on the Fund remains uncertain. 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, 2022 and 2021, 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 Supplemental Financial Assurance Requirements On July 14, 2016, the Bureau of Ocean Energy Management (“BOEM”) issued a Notice to Lessees (“NTL 2016-N01”) 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 natural gas leases and owners of pipeline rights-of-way, rights-of-use and easements on the Outer Continental Shelf (“Lessees”). Generally, NTL 2016-N01 (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 May 1, 2017, the Secretary of the U.S. Department of the Interior (“Interior”) directed the BOEM to complete a review of NTL 2016-N01, to provide a report to certain Interior personnel describing the results of the review and options for revising or rescinding NTL 2016-N01, and to keep the implementation timeline extension in effect pending the completion of the review of NTL 2016-N01 by the identified Interior personnel. On October 16, 2020, BOEM and the published a proposed new rule at 85 FR 65904 on Risk, Management, Financial Assurance and Loss Prevention, addressing the streamlining of evaluation criteria when determining whether oil, gas and sulfur leases, right-of-use and easement grant holders, and pipeline right-of-way grant holders may be required to provide bonds or other security above the prescribed amounts for base bonds to ensure compliance with the Lessees’ obligations, primarily decommissioning obligations. The proposed rule was significantly less stringent with respect to financial assurance than NTL 2016-N01. To date, the BOEM is not currently implementing NTL 2016-N01 and its status is uncertain, and BOEM Notwithstanding the uncertain status of NTL 2016-N01, BOEM had continued under existing law to review supplemental financial assurance requirements relative to sole liability properties (i.e., properties in which only one company is liable for decommissioning). However, on August 18, 2021, the BOEM issued a Note to Stakeholders in which the BOEM stated that it was expanding its financial assurance efforts beyond sole liability projects to include “supplemental financial assurance of certain high-risk, non-sole liability properties” (those properties with more than one company potentially liable for decommissioning costs). The BOEM identified (i) inactive properties, (ii) those with less than five years of production left, and (iii) those with damaged infrastructure, as being high-risk, non-sole liability properties and for which supplemental financial assurance may be required. The BOEM may require the Fund to fully secure all of its potential abandonment liabilities, which potentially could increase costs to the Fund. 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. |
Information about Oil and Gas P
Information about Oil and Gas Producing Activities | 12 Months Ended |
Dec. 31, 2022 | |
Information About Oil And Gas Producing Activities | |
Information about Oil and Gas Producing Activities | Information about Oil and Gas Producing Activities Ridgewood Energy A-1 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 Schedule of Capitalized Costs Relating to Oil and Gas Producing Activities December 31, 2022 2021 (in thousands) Proved properties $ 17,927 $ 17,439 Accumulated depletion and amortization (14,181 ) (12,116 ) Oil and gas properties, net $ 3,746 $ 5,323 Table II - Costs Incurred in Oil and Gas Property Acquisition, Exploration, and Development Schedule of Cost Incurred in Oil and Gas Property Acquisition, Exploration and Development Year ended December 31, 2022 2021 (in thousands) Development costs $ 488 $ 245 $ 488 $ 245 Table III - Reserve Quantity Information Schedule of Reserve Quantity Information Oil and gas reserves of the Fund have been estimated by independent petroleum engineers, Netherland, Sewell & Associates, Inc. at December 31, 2022 and 2021. 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. December 31, 2022 December 31, 2021 United States Oil (MBBLS) NGL (MBBLS) Gas (MMCF) Total (MBOE) (a) Oil (MBBLS) NGL (MBBLS) Gas (MMCF) Total (MBOE) (a) Proved developed and undeveloped reserves: Beginning of year 175.7 13.7 71.4 201.4 130.6 11.1 63.8 152.3 Revisions of previous estimates (b) (0.5 ) 3.3 26.0 7.0 89.2 7.3 34.6 102.4 Production (54.4 ) (6.5 ) (34.7 ) (66.7 ) (44.1 ) (4.7 ) (27.0 ) (53.3 ) End of year 120.8 10.5 62.7 141.7 175.7 13.7 71.4 201.4 Proved developed reserves: Beginning of year 131.1 10.1 52.5 150.1 130.6 11.1 63.8 152.3 End of year 79.6 7.7 46.1 95.0 131.1 10.1 52.5 150.1 Proved undeveloped reserves: Beginning of year 44.6 3.6 18.9 51.3 - - - - End of year 41.2 2.8 16.6 46.7 44.6 3.6 18.9 51.3 (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) Revisions of previous estimates were attributable to well performance. (c) Effective January 1, 2023, the fixed percentage overriding royalty interest (“ORRI”) of 10.81% in the Fund’s net revenue interest in the Beta Project’s oil and natural gas production becomes payable to the Fund’s former lender, which was conveyed pursuant to the Fund’s credit agreement applicable to the project. The reserves shown in the table above reflect the Fund’s interest in the Beta Project as it existed prior to the effective date of the ORRI. Table IV - Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves Schedule of 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. December 31, 2022 2021 (in thousands) Future cash inflows $ 11,624 $ 11,504 Future production costs (2,616 ) (2,327 ) Future development costs (2,864 ) (2,318 ) Future net cash flows 6,144 6,859 10% annual discount for estimated timing of cash flows (765 ) (1,280 ) Standardized measure of discounted future estimated net cash flows $ 5,379 $ 5,579 Effective January 1, 2023, the fixed percentage ORRI of 10.81% in the Fund’s net revenue interest in the Beta Project’s oil and natural gas production becomes payable to the Fund’s former lender, which was conveyed pursuant to the Fund’s credit agreement applicable to the project. The future cash inflows or future revenue shown in the table above reflect the Fund’s interest in the Beta Project as it existed prior to the effective date of the ORRI. Table V - Changes in the Standardized Measure for Discounted Future Net Cash Flows Schedule of Changes in the Standardized Measure for Discounted Future Net 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. Year ended December 31, 2022 2021 (in thousands) Net change in sales and transfer prices and in production costs $ 3,509 $ 3,971 Sales and transfers of oil and gas produced during the period (4,957 ) (2,802 ) Changes in estimated future development costs (546 ) 175 Net change due to revisions in quantities estimates 394 3,797 Accretion of discount 558 58 Other 842 (204 ) Aggregate change in the standardized measure of discounted future net cash $ (200 ) $ 4,995 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. |
Organization and Summary of S_2
Organization and Summary of Significant Accounting Policies (Policies) | 12 Months Ended |
Dec. 31, 2022 | |
Accounting Policies [Abstract] | |
Use of Estimates | 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, management 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 | 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 assets and liabilities consist of cash and cash equivalents, salvage fund, production receivable, due from affiliate, other current assets, due to operators and accrued expenses. The carrying amounts of these financial assets and liabilities approximate fair value due to their short-term nature. 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 | 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, 2022, the Fund had no cash equivalents. At times, deposits may be in excess of federally insured limits, which are $ 250 |
Salvage Fund | 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 | 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. |
Accrued Expenses | Accrued Expenses Accrued expenses consist of the following: December 31, 2022 2021 (in thousands) Accrued accounting and legal fees $ 63 $ 66 Accrued royalty 56 - $ 119 $ 66 |
Asset Retirement Obligations | 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 based on expected future cash outflows required to satisfy the obligation discounted at the Fund’s credit-adjusted risk-free rate. 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, 2022 and 2021: Schedule of Changes in Asset Retirement Obligations December 31, 2022 2021 (in thousands) Balance, beginning of year $ 934 $ 1,565 Liabilities settled (6 ) (305 ) Accretion expense 27 27 Revision of estimates 120 (353 ) Balance, end of year $ 1,075 $ 934 During the year ended December 31, 2021, the Fund recorded credits to depletion expense totaling $ 0.3 |
Syndication Costs | 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 | Revenue Recognition Oil and gas revenues from contracts with customers are recognized at the point when control of oil and natural gas is transferred to the customers in accordance with Accounting Standard Codification Topic 606, Revenue from Contracts with Customers (“ASC 606”) ASC 606 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. Natural gas liquid (“NGL”) sales are included within gas revenues. The Fund’s oil and natural gas generally are sold to its customers at prevailing market prices based on an index in which the prices are published, adjusted for pricing differentials, quality of oil and pipeline allowances. 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 natural 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 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. The receivables related to the Fund’s oil and gas revenue are included within “Production receivable” on the Fund’s balance sheets. Other Revenue Other revenue is generated from the Fund’s production handling, gathering and operating services agreement with affiliated entities and other third parties. The Fund 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, thus there are no unsatisfied performance obligations. The Fund’s project operator performs joint interest billing once the performance obligations have been satisfied, at which point the payment is unconditional. Accordingly, the Fund’s production handling, gathering and operating services agreement with affiliated entities and other third parties does not give rise to contract assets or liabilities. The receivables related to the Fund’s proportionate share of revenue from affiliates are included within “Due from affiliate” on the Fund’s balance sheets. The receivables related to the Fund’s proportionate share of revenue from third parties are presented as a reduction from “Due to operator” on the Fund’s balance sheets. The receivables are settled by issuance of a non-cash credit from the Beta Project operator to the Fund when the operator performs the joint interest billing of the lease operating expenses due from the Fund. However, if applying the joint interest billing credit results in a net credit balance due to the Fund, the Beta Project operator remits such balance in cash to the Fund. 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. During the years ended December 31, 2022 and 2021, revenue recognized from performance obligations satisfied in previous periods was not significant. |
Allowance for Credit Losses | Allowance for Credit Losses The Fund is exposed to credit losses through the sale of oil and natural gas to customers. However, the Fund only sells to a small number of major oil and gas companies that have investment-grade credit ratings. Based on historical collection experience, current and future economic and market conditions and a review of the current status of customers' production receivables, the Fund has not recorded an expected loss allowance as there are no past due receivable balances or projected credit losses. |
Impairment of Long-Lived Assets | 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. Recoverability is evaluated by comparing estimated future net undiscounted cash flows to the carrying value of the oil and gas properties at the time of the review. If the carrying value exceeds the estimated future net undiscounted cash flows, the carrying value of the oil and gas properties is impaired, and written down to fair value. Fair value is determined using valuation techniques that include both market and income approaches and use Level 3 inputs. The fair value determinations require considerable judgment and are sensitive to change. Different pricing assumptions, estimates of oil and gas reserves and future development costs or discount rates could result in a significant impact on the amount of impairment. There were no impairments of oil and gas properties during the years ended December 31, 2022 and 2021. Fluctuations in oil and natural gas commodity prices may impact the fair value of the Fund’s oil and gas properties. In addition, significant declines in oil and natural gas commodity prices could reduce the quantities of reserves that are commercially recoverable, which could result in impairment |
Depletion and Amortization | 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 | 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 2019 through 2021 tax returns remain open for examination by tax authorities. |
Income and Expense Allocation | Income and Expense Allocation Profits and losses are allocated to shareholders and the Manager in accordance with the LLC Agreement. In general, profits and losses in any year are allocated 85 15 |
Distributions | 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 1 85 15 |
Recent Accounting Pronouncements | Recent Accounting Pronouncements The Fund has considered recent accounting pronouncements issued during the year ended December 31, 2022 and through the filing of this report, and the Fund has not identified new standards that it believes will have an impact on the Fund’s financial statements. |
Organization and Summary of S_3
Organization and Summary of Significant Accounting Policies (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Accounting Policies [Abstract] | |
Accrued expenses consist of the following: | Accrued expenses consist of the following: December 31, 2022 2021 (in thousands) Accrued accounting and legal fees $ 63 $ 66 Accrued royalty 56 - $ 119 $ 66 |
Schedule of Changes in Asset Retirement Obligations | Schedule of Changes in Asset Retirement Obligations December 31, 2022 2021 (in thousands) Balance, beginning of year $ 934 $ 1,565 Liabilities settled (6 ) (305 ) Accretion expense 27 27 Revision of estimates 120 (353 ) Balance, end of year $ 1,075 $ 934 |
Information about Oil and Gas_2
Information about Oil and Gas Producing Activities (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Information About Oil And Gas Producing Activities | |
Schedule of Capitalized Costs Relating to Oil and Gas Producing Activities | Table I - Capitalized Costs Relating to Oil and Gas Producing Activities Schedule of Capitalized Costs Relating to Oil and Gas Producing Activities December 31, 2022 2021 (in thousands) Proved properties $ 17,927 $ 17,439 Accumulated depletion and amortization (14,181 ) (12,116 ) Oil and gas properties, net $ 3,746 $ 5,323 |
Schedule of Cost Incurred in Oil and Gas Property Acquisition, Exploration and Development | Table II - Costs Incurred in Oil and Gas Property Acquisition, Exploration, and Development Schedule of Cost Incurred in Oil and Gas Property Acquisition, Exploration and Development Year ended December 31, 2022 2021 (in thousands) Development costs $ 488 $ 245 $ 488 $ 245 |
Schedule of Reserve Quantity Information | Table III - Reserve Quantity Information Schedule of Reserve Quantity Information Oil and gas reserves of the Fund have been estimated by independent petroleum engineers, Netherland, Sewell & Associates, Inc. at December 31, 2022 and 2021. 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. December 31, 2022 December 31, 2021 United States Oil (MBBLS) NGL (MBBLS) Gas (MMCF) Total (MBOE) (a) Oil (MBBLS) NGL (MBBLS) Gas (MMCF) Total (MBOE) (a) Proved developed and undeveloped reserves: Beginning of year 175.7 13.7 71.4 201.4 130.6 11.1 63.8 152.3 Revisions of previous estimates (b) (0.5 ) 3.3 26.0 7.0 89.2 7.3 34.6 102.4 Production (54.4 ) (6.5 ) (34.7 ) (66.7 ) (44.1 ) (4.7 ) (27.0 ) (53.3 ) End of year 120.8 10.5 62.7 141.7 175.7 13.7 71.4 201.4 Proved developed reserves: Beginning of year 131.1 10.1 52.5 150.1 130.6 11.1 63.8 152.3 End of year 79.6 7.7 46.1 95.0 131.1 10.1 52.5 150.1 Proved undeveloped reserves: Beginning of year 44.6 3.6 18.9 51.3 - - - - End of year 41.2 2.8 16.6 46.7 44.6 3.6 18.9 51.3 (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) Revisions of previous estimates were attributable to well performance. (c) Effective January 1, 2023, the fixed percentage overriding royalty interest (“ORRI”) of 10.81% in the Fund’s net revenue interest in the Beta Project’s oil and natural gas production becomes payable to the Fund’s former lender, which was conveyed pursuant to the Fund’s credit agreement applicable to the project. The reserves shown in the table above reflect the Fund’s interest in the Beta Project as it existed prior to the effective date of the ORRI. |
Schedule of Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves. | Table IV - Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves Schedule of 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. December 31, 2022 2021 (in thousands) Future cash inflows $ 11,624 $ 11,504 Future production costs (2,616 ) (2,327 ) Future development costs (2,864 ) (2,318 ) Future net cash flows 6,144 6,859 10% annual discount for estimated timing of cash flows (765 ) (1,280 ) Standardized measure of discounted future estimated net cash flows $ 5,379 $ 5,579 |
Schedule of Changes in the Standardized Measure for Discounted Future Net Cash Flows | Table V - Changes in the Standardized Measure for Discounted Future Net Cash Flows Schedule of Changes in the Standardized Measure for Discounted Future Net 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. Year ended December 31, 2022 2021 (in thousands) Net change in sales and transfer prices and in production costs $ 3,509 $ 3,971 Sales and transfers of oil and gas produced during the period (4,957 ) (2,802 ) Changes in estimated future development costs (546 ) 175 Net change due to revisions in quantities estimates 394 3,797 Accretion of discount 558 58 Other 842 (204 ) Aggregate change in the standardized measure of discounted future net cash $ (200 ) $ 4,995 |
Accrued expenses consist of the
Accrued expenses consist of the following: (Details) - USD ($) $ in Thousands | Dec. 31, 2022 | Dec. 31, 2021 |
Accounting Policies [Abstract] | ||
Accrued accounting and legal fees | $ 63 | $ 66 |
Accrued royalty | 56 | |
Total | $ 119 | $ 66 |
Schedule of Changes in Asset Re
Schedule of Changes in Asset Retirement Obligations (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2022 | Dec. 31, 2021 | |
Accounting Policies [Abstract] | ||
Balance, beginning of year | $ 934 | $ 1,565 |
Liabilities settled | (6) | (305) |
Accretion expense | 27 | 27 |
Revision of estimates | 120 | (353) |
Balance, end of year | $ 1,075 | $ 934 |
Organization and Summary of S_4
Organization and Summary of Significant Accounting Policies (Details Narrative) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2021 | Dec. 31, 2022 | |
Accounting Policies [Abstract] | ||
Cash insured amount | $ 250 | |
Depletion credit | $ 300 | |
Percentage of cash from operations allocated to shareholders | 85% | |
Percentage of cash from operations allocated to Fund Manager | 15% | |
Percentage of cash from dispositions allocated to shareholders | 99% | |
Percentage of cash from dispositions allocated to Fund Manager | 1% | |
Percentage of cash from dispositions allocated to shareholders after distributions have equaled capital contributions | 85% | |
Percentage of cash from dispositions allocated to Fund Manager after distributions have equaled capital contributions | 15% |
Related Parties (Details Narrat
Related Parties (Details Narrative) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2022 | Dec. 31, 2021 | |
Related Party Transaction [Line Items] | ||
Annual management fee percentage rate | 2.50% | |
Management fees | $ 291 | $ 294 |
Percentage of total distributions allocated to fund manager | 15% | |
Partners' capital account, distribution | $ 4,848 | 857 |
Due from affiliate | 10 | 19 |
Fund Manager [Member] | ||
Related Party Transaction [Line Items] | ||
Partners' capital account, distribution | 728 | 128 |
Management [Member] | ||
Related Party Transaction [Line Items] | ||
Management fees | 300 | 300 |
Institutional Funds [Member] | ||
Related Party Transaction [Line Items] | ||
Other revenues from affiliates | 100 | 100 |
Due from affiliate | $ 10 | $ 19 |
Commitments and Contingencies (
Commitments and Contingencies (Details Narrative) $ in Millions | 12 Months Ended |
Dec. 31, 2022 USD ($) | |
Commitments and Contingencies Disclosure [Abstract] | |
Commitments for the drilling and development of investment properties | $ 2.9 |
Commitments for asset retirement obligations included in estimated capital commitments | 1.8 |
Commitments for the drilling and development of investment properties expected to be incurred in the next 12 months | $ 40 |
Schedule of Capitalized Costs R
Schedule of Capitalized Costs Relating to Oil and Gas Producing Activities (Details) - USD ($) $ in Thousands | Dec. 31, 2022 | Dec. 31, 2021 |
Information About Oil And Gas Producing Activities | ||
Proved properties | $ 17,927 | $ 17,439 |
Accumulated depletion and amortization | (14,181) | (12,116) |
Total oil and gas properties, net | $ 3,746 | $ 5,323 |
Schedule of Cost Incurred in Oi
Schedule of Cost Incurred in Oil and Gas Property Acquisition, Exploration and Development (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2022 | Dec. 31, 2021 | |
Information About Oil And Gas Producing Activities | ||
Development costs | $ 488 | $ 245 |
Total Costs | $ 488 | $ 245 |
Schedule of Reserve Quantity In
Schedule of Reserve Quantity Information (Details) | 12 Months Ended | ||
Dec. 31, 2022 MBbls Mcf | Dec. 31, 2021 MBbls Mcf | ||
Oil [Member] | |||
Reserve Quantities [Line Items] | |||
Beginning of year | 175.7 | 130.6 | |
Revisions of previous estimates | [1] | (0.5) | 89.2 |
Production | (54.4) | (44.1) | |
End of year | 120.8 | 175.7 | |
Beginning of year | 131.1 | 130.6 | |
End of year | 79.6 | 131.1 | |
Beginning of year | 44.6 | ||
End of year | 41.2 | 44.6 | |
NGL (BBLS) [Member] | |||
Reserve Quantities [Line Items] | |||
Beginning of year | 13.7 | 11.1 | |
Revisions of previous estimates | [1] | 3.3 | 7.3 |
Production | (6.5) | (4.7) | |
End of year | 10.5 | 13.7 | |
Beginning of year | 10.1 | 11.1 | |
End of year | 7.7 | 10.1 | |
Beginning of year | 3.6 | ||
End of year | 2.8 | 3.6 | |
Natural Gas [Member] | |||
Reserve Quantities [Line Items] | |||
Beginning of year | Mcf | 71.4 | 63.8 | |
Revisions of previous estimates | Mcf | [1] | 26 | 34.6 |
Production | Mcf | (34.7) | (27) | |
End of year | Mcf | 62.7 | 71.4 | |
Beginning of year | Mcf | 52.5 | 63.8 | |
End of year | Mcf | 46.1 | 52.5 | |
Beginning of year | Mcf | 18.9 | ||
End of year | Mcf | 16.6 | 18.9 | |
Other Nonrenewable Natural Resources [Member] | |||
Reserve Quantities [Line Items] | |||
Beginning of year | [2] | 201.4 | 152.3 |
Revisions of previous estimates | [1],[2] | 7 | 102.4 |
Production | [2] | (66.7) | (53.3) |
End of year | [2] | 141.7 | 201.4 |
Beginning of year | [2] | 150.1 | 152.3 |
End of year | [2] | 95 | 150.1 |
Beginning of year | [2] | 51.3 | |
End of year | [2] | 46.7 | 51.3 |
[1]Revisions of previous estimates were attributable to well performance.[2]BOE refers to barrel of oil equivalent |
Schedule of Standardized Measur
Schedule of Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves. (Details) - USD ($) $ in Thousands | Dec. 31, 2022 | Dec. 31, 2021 |
Information About Oil And Gas Producing Activities | ||
Future cash inflows | $ 11,624 | $ 11,504 |
Future production costs | (2,616) | (2,327) |
Future development costs | (2,864) | (2,318) |
Future net cash flows | 6,144 | 6,859 |
10% annual discount for estimated timing of cash flows | (765) | (1,280) |
Standardized measure of discounted future estimated net cash flows | $ 5,379 | $ 5,579 |
Schedule of Changes in the Stan
Schedule of Changes in the Standardized Measure for Discounted Future Net Cash Flows (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2022 | Dec. 31, 2021 | |
Information About Oil And Gas Producing Activities | ||
Net change in sales and transfer prices and in production costs related to future production | $ 3,509 | $ 3,971 |
Sales and transfers of oil and gas produced during the period | (4,957) | (2,802) |
Changes in estimated future development costs | (546) | 175 |
Net change due to revisions in quantities estimates | 394 | 3,797 |
Accretion of discount | 558 | 58 |
Other | 842 | (204) |
Aggregate change in the standardized measure of discounted future net cash flows for the year | $ (200) | $ 4,995 |