Cover
Cover - USD ($) | 12 Months Ended | |
Dec. 31, 2023 | Feb. 26, 2024 | |
Cover [Abstract] | ||
Document Type | 10-K | |
Amendment Flag | false | |
Document Annual Report | true | |
Document Transition Report | false | |
Document Period End Date | Dec. 31, 2023 | |
Document Fiscal Period Focus | FY | |
Document Fiscal Year Focus | 2023 | |
Current Fiscal Year End Date | --12-31 | |
Entity File Number | 000-53591 | |
Entity Registrant Name | Ridgewood Energy X Fund, LLC | |
Entity Central Index Key | 0001455741 | |
Entity Tax Identification Number | 26-0870318 | |
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 | |
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 | 477.8874 | |
ICFR Auditor Attestation Flag | false | |
Document Financial Statement Error Correction [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, 2023 | Dec. 31, 2022 |
Current assets: | ||
Cash and cash equivalents | $ 6,969 | $ 8,831 |
Salvage fund | 100 | |
Production receivable | 272 | 392 |
Other current assets | 12 | 20 |
Total current assets | 7,253 | 9,343 |
Salvage fund | 1,301 | 909 |
Investment in Delta House | 119 | 119 |
Oil and gas properties: | ||
Advances to operators for capital expenditures | 103 | |
Proved properties | 10,750 | 9,508 |
Less: accumulated depletion and amortization | (7,896) | (7,541) |
Total oil and gas properties, net | 2,957 | 1,967 |
Total assets | 11,630 | 12,338 |
Current liabilities: | ||
Due to operators | 70 | 102 |
Accrued expenses | 47 | 61 |
Asset retirement obligations | 100 | |
Total current liabilities | 117 | 263 |
Due to operators | 47 | |
Asset retirement obligations | 489 | 350 |
Total liabilities | 653 | 613 |
Manager: | ||
Distributions | (8,107) | (7,694) |
Retained earnings | 7,152 | 6,826 |
Manager's total | (955) | (868) |
Shareholders: | ||
Capital contributions (500 shares authorized; 477.8874 issued and outstanding) | 94,698 | 94,698 |
Syndication costs | (11,080) | (11,080) |
Distributions | (48,117) | (45,772) |
Accumulated deficit | (23,569) | (25,253) |
Shareholders' total | 11,932 | 12,593 |
Total members' capital | 10,977 | 11,725 |
Total liabilities and members' capital | $ 11,630 | $ 12,338 |
BALANCE SHEETS (Parenthetical)
BALANCE SHEETS (Parenthetical) - shares | Dec. 31, 2023 | Dec. 31, 2022 |
Statement of Financial Position [Abstract] | ||
Shares authorized | 500 | 500 |
Shares issued | 477.8874 | 477.8874 |
Shares outstanding | 477.8874 | 477.8874 |
STATEMENTS OF OPERATIONS
STATEMENTS OF OPERATIONS - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Revenue | ||
Oil and gas revenue | $ 3,573 | $ 4,550 |
Expenses | ||
Depletion and amortization | 349 | 359 |
Operating expenses | 545 | 561 |
Management fees to affiliate (Note 2) | 713 | 719 |
General and administrative expenses | 174 | 143 |
Total expenses | 1,781 | 1,782 |
Income from operations | 1,792 | 2,768 |
Other income | ||
Dividend income | 23 | 23 |
Interest income | 195 | 30 |
Total other income | 218 | 53 |
Net income | 2,010 | 2,821 |
Manager Interest | ||
Net income | 326 | 473 |
Shareholder Interest | ||
Net income | $ 1,684 | $ 2,348 |
Net income per share | $ 3,524 | $ 4,913 |
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, 2021 | $ (899) | $ 12,750 | $ 11,851 | |
Beginning balance, shares at Dec. 31, 2021 | 477.8874 | |||
Distributions | (442) | (2,505) | (2,947) | |
Net income | 473 | 2,348 | 2,821 | |
Ending balance, value at Dec. 31, 2022 | (868) | 12,593 | $ 11,725 | |
Ending balance, shares at Dec. 31, 2022 | 477.8874 | 477.8874 | ||
Distributions | (413) | (2,345) | $ (2,758) | |
Net income | 326 | 1,684 | 2,010 | |
Ending balance, value at Dec. 31, 2023 | $ (955) | $ 11,932 | $ 10,977 | |
Ending balance, shares at Dec. 31, 2023 | 477.8874 | 477.8874 |
STATEMENTS OF CASH FLOWS
STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Cash flows from operating activities | ||
Net income | $ 2,010 | $ 2,821 |
Adjustments to reconcile net income to net cash provided by operating activities: | ||
Depletion and amortization | 349 | 359 |
Accretion expense | 24 | 11 |
Changes in assets and liabilities: | ||
Decrease (increase) in production receivable | 120 | (110) |
Decrease in other current assets | 8 | |
Decrease in due to operators | (85) | (4) |
Decrease in accrued expenses | (14) | (2) |
Credit from (settlement of) asset retirement obligations | 7 | (14) |
Net cash provided by operating activities | 2,419 | 3,061 |
Cash flows from investing activities | ||
Advance payments to operators for capital expenditures for oil and gas properties | (103) | |
Capital expenditures for oil and gas properties | (1,128) | (9) |
Proceeds from salvage fund | 93 | 14 |
Increase in salvage fund | (385) | (26) |
Net cash used in investing activities | (1,523) | (21) |
Cash flows from financing activities | ||
Distributions | (2,758) | (2,947) |
Net cash used in financing activities | (2,758) | (2,947) |
Net (decrease) increase in cash and cash equivalents | (1,862) | 93 |
Cash and cash equivalents, beginning of year | 8,831 | 8,738 |
Cash and cash equivalents, end of year | $ 6,969 | $ 8,831 |
Insider Trading Arrangements
Insider Trading Arrangements | 3 Months Ended |
Dec. 31, 2023 | |
Insider Trading Arrangements [Line Items] | |
Rule 10b5-1 Arrangement Adopted | false |
Non-Rule 10b5-1 Arrangement Adopted | false |
Rule 10b5-1 Arrangement Terminated | false |
Non-Rule 10b5-1 Arrangement Terminated | false |
Organization and Summary of Sig
Organization and Summary of Significant Accounting Policies | 12 Months Ended |
Dec. 31, 2023 | |
Accounting Policies [Abstract] | |
Organization and Summary of Significant Accounting Policies | 1. Organization and Summary of Significant Accounting Policies Organization The Ridgewood Energy X Fund, LLC (the “Fund”), a Delaware limited liability company, was formed on August 30, 2007 and operates pursuant to a limited liability company agreement (the “LLC Agreement”) dated as of January 2, 2008 by and among Ridgewood Energy Corporation (the “Manager”) and the shareholders of the Fund, which addresses matters such as the authority and voting rights of the Manager and shareholders, capitalization, transferability of membership interests, participation in costs and revenues, distribution of assets and dissolution and winding up. The Fund was organized to primarily acquire interests in oil and gas properties located in the United States offshore waters of Texas, Louisiana and Alabama in the Gulf of Mexico. The Manager has direct and exclusive control over the management of the Fund’s operations. 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, production receivable, other current assets, salvage fund, investment in Delta House, due to operators and accrued expenses. Except for investment in Delta House, the carrying amounts of these financial assets and liabilities approximate fair value due to their short-term nature. The Fund’s investment in Delta House is valued using the measurement alternative for investment in other entities (see Investment in Delta House 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, 2023, the Fund had no cash equivalents. At times, deposits may be in excess of federally insured limits, which are $ 250 8.2 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. Investment in Delta House The Fund has investments in Delta House Oil and Gas Lateral, LLC and Delta House FPS, LLC (collectively “Delta House”), legal entities that own interests in a deepwater floating production system operated by Murphy Exploration & Production Company - USA. The investment in Delta House is valued using the measurement alternative to record the investment at cost, less impairment and plus or minus subsequent adjustments for observable price changes with change in basis reported in current earnings. At each reporting period, the Fund reviews its investment in Delta House to evaluate whether the investment is impaired. During the years ended December 31, 2023 and 2022, there were no impairments of the Fund’s investment in Delta House. 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 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, 2023 and 2022: Schedule of changes in asset retirement obligations Year ended December 31, 2023 2022 (in thousands) Balance, beginning of year $ 450 $ 351 Liabilities incurred 34 - Liabilities settled/relieved (93 ) (14 ) Accretion expense 24 11 Revision of estimates 74 102 Balance, end of year $ 489 $ 450 On September 12, 2023, the Fund entered into a bill of sale agreement with the operator of the Liberty and Carrera projects to sell its proportionate ownership in the producer-owned platform facilities and certain components of the subsea production systems of the project. The agreement relieved the Fund from all abandonment obligations related to the equipment. As a result, the Fund relieved the remaining asset retirement obligations in the Liberty and Carrera projects totaling $ 0.1 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. 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, 2023 and 2022, 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, 2023 and 2022. 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. 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 2020 through 2022 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, 2023 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, 2023 | |
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% 0.7 The Manager is also entitled to receive 15% 0.4 The Fund utilizes DH Sales and Transport, LLC (“DH 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 Diller and Marmalard projects. In 2016, as amended in April 2018 and September 2021, the Fund entered into a master agreement with DH S&T pursuant to which DH S&T is obligated to purchase from the Fund all of its interests in oil and natural gas produced from the Diller and Marmalard projects and sell such volumes to unrelated third-party purchasers. Pursuant to the master agreement, DH 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 DH 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 Diller and Marmalard projects. 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 Diller and Marmalard projects. 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, 2023 | |
Commitments and Contingencies Disclosure [Abstract] | |
Commitments and Contingencies | 3. Commitments and Contingencies Capital Commitments As of December 31, 2023, the Fund’s estimated capital commitments related to its oil and gas properties were $ 3.2 1.2 0.1 Impact from market conditions Oil prices are constantly adjusting to reflect changes in both the current status of, as well as expectations regarding the future of supply/demand balance, which is impacted by the following factors: (i) sentiments regarding current and future global economic activity, whether robust or tepid; (ii) upstream investment activity by the energy industry, which itself reflects the price of oil, as well as access to investment capital; (iii) governmental energy policy in the U.S. and abroad; (iv) the levels of crude oil in commercial storage and global strategic petroleum reserves, which buffer imbalances in daily supply and demand; (v) changing policy out of OPEC Plus aimed to directly manage the global supply/demand balance for crude throughout coordinated output quotas; and (vi) fluctuations in the global purchasing power of the U.S. Dollar, the value of which is inversely related to the price of oil. In addition, ongoing geopolitical conditions, including the ongoing Russia-Ukraine war and the evolving Israel-Hamas conflict as well as acts of terrorism, will continue to dictate oil and natural gas commodity prices. 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, 2023 and 2022, 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. BSEE and 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, the NTL 2016-N01 was not fully implemented. On October 16, 2020, BOEM and the Bureau of Safety and Environmental Enforcement (“BSEE”) 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. Upon review of the 2020 joint proposed rule and analysis of public comments, the Secretary of the U.S. Department of the Interior elected to separate the BOEM and BSEE portions of the supplemental bonding requirements. BSEE finalized some provisions from the 2020 proposal as discussed below. BOEM rescinded its portion of the 2020 proposed rule and issued its new proposed rule below. On April 18, 2023, BSEE published a final rule at 88 FR 23569 on Risk Management, Financial Assurance and Loss Prevention, wherein BSEE clarified and formalized its regulations related to decommissioning responsibilities of Outer Continental Shelf (“OCS”) oil, gas, and sulfur lessees and grant holders to ensure compliance with lease, grant, and regulatory obligations. The rule became effective May 18, 2023. The rule implements provisions of the 2020 proposed rule intended to clarify decommissioning responsibilities of right-of-use and easement grant holders and to formalize BSEE's policies regarding performance by predecessors ordered to decommission OCS facilities. The final rule withdraws the proposal set forth in the 2020 proposed rule to amend BSEE's regulations to require BSEE to proceed in reverse chronological order against predecessor lessees, owners of operating rights, and grant holders when requiring such entities to perform their accrued decommissioning obligations if the current lessees, owners, or holders have failed to perform. In addition, BSEE also decided not to finalize the proposed appeal bonding requirements in this final rule. On June 29, 2023, BOEM published a proposed rule, that if adopted as initially proposed, would substantially revise the supplemental financial assurance requirements to decommission offshore wells and infrastructure once they are no longer in use. The proposed rule proposes a simplified test using only two criteria by which BOEM would determine whether supplemental financial assurance should be required of OCS oil and gas lessees: (1) credit rating, and (2) the ratio of the value of proved oil and gas reserves of the lease to the estimated decommissioning liability associated with the reserves. In addition, as it relates to supplemental financial assurance requirements for OCS oil and gas right-of-use and easement grant holders, BOEM will only consider the first criteria – i.e., credit rating. Under the proposed rule, BOEM would no longer consider or rely upon the financial strength of prior grant holders and lessees in determining whether, or how much, supplemental financial assurance should be provided by the current grant holders and lessees. The proposed rule would allow existing lessees and grant holders to request phased-in payments over three years for new financial assurance amounts. The extended public comment period closed on September 7, 2023, and BOEM is reviewing the comments received. The Fund is not able to evaluate the impact of the proposed new rule on its operations or financial condition until a final rule is issued or some other definitive action is taken by the Interior or BOEM. 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, 2023 | |
Information About Oil And Gas Producing Activities | |
Information about Oil and Gas Producing Activities | Information about Oil and Gas Producing Activities Ridgewood Energy X Fund, LLC 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, 2023 2022 (in thousands) Advances to operators for capital expenditures $ 103 $ - Proved properties 10,750 9,508 Accumulated depletion and amortization (7,896 ) (7,541 ) Oil and gas properties, net $ 2,957 $ 1,967 Table II - Costs Incurred in Oil and Gas Property Acquisition, Exploration, and Development Schedule of costs incurred in oil and gas property acquisition, exploration, and development Year ended December 31, 2023 2022 (in thousands) Development costs $ 1,235 $ 128 $ 1,235 $ 128 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, 2023 and 2022. 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. Schedule of reserve quantity information December 31, 2023 December 31, 2022 United States Oil (MBBL) NGL (MBBL) Gas (MMCF) Total (MBOE) (a) Oil (MBBL) NGL (MBBL) Gas (MMCF) Total (MBOE) (a) Proved developed and undeveloped reserves: Beginning of year 318.2 109.6 808.3 562.5 335.9 124.9 973.7 623.1 Revisions of previous estimates (b) (46.6 ) (45.7 ) (297.8 ) (141.9 ) 23.4 (9.3 ) (121.5 ) (6.2 ) Production (42.7 ) (6.4 ) (51.5 ) (57.7 ) (41.1 ) (6.0 ) (43.9 ) (54.4 ) End of year 228.9 57.5 459.0 362.9 318.2 109.6 808.3 562.5 Proved developed reserves: Beginning of year 228.1 62.1 457.9 366.5 176.2 55.0 432.1 303.3 End of year 218.8 50.5 403.1 336.5 228.1 62.1 457.9 366.5 Proved undeveloped reserves: Beginning of year 90.1 47.5 350.4 196.0 159.7 69.9 541.6 319.8 End of year 10.1 7.0 55.9 26.4 90.1 47.5 350.4 196.0 (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. 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. Schedule of standardized measure of discounted future net cash flows relating to proved oil and gas reserves December 31, 2023 2022 (in thousands) Future cash inflows $ 19,437 $ 38,791 Future production costs (4,711 ) (8,373 ) Future development costs (2,107 ) (3,973 ) Future net cash flows 12,619 26,445 10% annual discount for estimated timing of cash flows (2,492 ) (7,482 ) Standardized measure of discounted future net cash flows $ 10,127 $ 18,963 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. Schedule of changes in the standardized measure for discounted cash flows Year ended December 31, 2023 2022 (in thousands) Net change in sales and transfer prices and in production costs related to future production $ (4,703 ) $ 10,677 Sales and transfers of oil and gas produced during the period (3,113 ) (4,030 ) Changes in estimated future development costs 1,866 (949 ) Net change due to revisions in quantities estimates (4,622 ) (241 ) Accretion of discount 1,896 1,088 Other (160 ) 1,542 Aggregate change in the standardized measure of discounted future net cash flows for the year $ (8,836 ) $ 8,087 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, 2023 | |
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, production receivable, other current assets, salvage fund, investment in Delta House, due to operators and accrued expenses. Except for investment in Delta House, the carrying amounts of these financial assets and liabilities approximate fair value due to their short-term nature. The Fund’s investment in Delta House is valued using the measurement alternative for investment in other entities (see Investment in Delta House |
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, 2023, the Fund had no cash equivalents. At times, deposits may be in excess of federally insured limits, which are $ 250 8.2 |
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. |
Investment in Delta House | Investment in Delta House The Fund has investments in Delta House Oil and Gas Lateral, LLC and Delta House FPS, LLC (collectively “Delta House”), legal entities that own interests in a deepwater floating production system operated by Murphy Exploration & Production Company - USA. The investment in Delta House is valued using the measurement alternative to record the investment at cost, less impairment and plus or minus subsequent adjustments for observable price changes with change in basis reported in current earnings. At each reporting period, the Fund reviews its investment in Delta House to evaluate whether the investment is impaired. During the years ended December 31, 2023 and 2022, there were no impairments of the Fund’s investment in Delta House. |
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. |
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, 2023 and 2022: Schedule of changes in asset retirement obligations Year ended December 31, 2023 2022 (in thousands) Balance, beginning of year $ 450 $ 351 Liabilities incurred 34 - Liabilities settled/relieved (93 ) (14 ) Accretion expense 24 11 Revision of estimates 74 102 Balance, end of year $ 489 $ 450 On September 12, 2023, the Fund entered into a bill of sale agreement with the operator of the Liberty and Carrera projects to sell its proportionate ownership in the producer-owned platform facilities and certain components of the subsea production systems of the project. The agreement relieved the Fund from all abandonment obligations related to the equipment. As a result, the Fund relieved the remaining asset retirement obligations in the Liberty and Carrera projects totaling $ 0.1 |
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. 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, 2023 and 2022, 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, 2023 and 2022. 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. |
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 2020 through 2022 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, 2023 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, 2023 | |
Accounting Policies [Abstract] | |
Schedule of changes in asset retirement obligations | Schedule of changes in asset retirement obligations Year ended December 31, 2023 2022 (in thousands) Balance, beginning of year $ 450 $ 351 Liabilities incurred 34 - Liabilities settled/relieved (93 ) (14 ) Accretion expense 24 11 Revision of estimates 74 102 Balance, end of year $ 489 $ 450 |
Information about Oil and Gas_2
Information about Oil and Gas Producing Activities (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Information About Oil And Gas Producing Activities | |
Schedule of capitalized costs relating to oil and gas producing activities | Schedule of capitalized costs relating to oil and gas producing activities December 31, 2023 2022 (in thousands) Advances to operators for capital expenditures $ 103 $ - Proved properties 10,750 9,508 Accumulated depletion and amortization (7,896 ) (7,541 ) Oil and gas properties, net $ 2,957 $ 1,967 |
Schedule of costs incurred in oil and gas property acquisition, exploration, and development | Schedule of costs incurred in oil and gas property acquisition, exploration, and development Year ended December 31, 2023 2022 (in thousands) Development costs $ 1,235 $ 128 $ 1,235 $ 128 |
Schedule of reserve quantity information | Schedule of reserve quantity information December 31, 2023 December 31, 2022 United States Oil (MBBL) NGL (MBBL) Gas (MMCF) Total (MBOE) (a) Oil (MBBL) NGL (MBBL) Gas (MMCF) Total (MBOE) (a) Proved developed and undeveloped reserves: Beginning of year 318.2 109.6 808.3 562.5 335.9 124.9 973.7 623.1 Revisions of previous estimates (b) (46.6 ) (45.7 ) (297.8 ) (141.9 ) 23.4 (9.3 ) (121.5 ) (6.2 ) Production (42.7 ) (6.4 ) (51.5 ) (57.7 ) (41.1 ) (6.0 ) (43.9 ) (54.4 ) End of year 228.9 57.5 459.0 362.9 318.2 109.6 808.3 562.5 Proved developed reserves: Beginning of year 228.1 62.1 457.9 366.5 176.2 55.0 432.1 303.3 End of year 218.8 50.5 403.1 336.5 228.1 62.1 457.9 366.5 Proved undeveloped reserves: Beginning of year 90.1 47.5 350.4 196.0 159.7 69.9 541.6 319.8 End of year 10.1 7.0 55.9 26.4 90.1 47.5 350.4 196.0 (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. |
Standardized Measure of Discounted Future Cash Flows Relating to Proved Reserves Disclosure [Table Text Block] | Schedule of standardized measure of discounted future net cash flows relating to proved oil and gas reserves December 31, 2023 2022 (in thousands) Future cash inflows $ 19,437 $ 38,791 Future production costs (4,711 ) (8,373 ) Future development costs (2,107 ) (3,973 ) Future net cash flows 12,619 26,445 10% annual discount for estimated timing of cash flows (2,492 ) (7,482 ) Standardized measure of discounted future net cash flows $ 10,127 $ 18,963 |
Schedule of changes in the standardized measure for discounted cash flows | Schedule of changes in the standardized measure for discounted cash flows Year ended December 31, 2023 2022 (in thousands) Net change in sales and transfer prices and in production costs related to future production $ (4,703 ) $ 10,677 Sales and transfers of oil and gas produced during the period (3,113 ) (4,030 ) Changes in estimated future development costs 1,866 (949 ) Net change due to revisions in quantities estimates (4,622 ) (241 ) Accretion of discount 1,896 1,088 Other (160 ) 1,542 Aggregate change in the standardized measure of discounted future net cash flows for the year $ (8,836 ) $ 8,087 |
Organization and Summary of S_4
Organization and Summary of Significant Accounting Policies (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Accounting Policies [Abstract] | ||
Balance, beginning of year | $ 450 | $ 351 |
Liabilities incurred | 34 | |
Liabilities settled | (93) | (14) |
Accretion expense | 24 | 11 |
Revision of estimates | 74 | 102 |
Balance, end of year | $ 489 | $ 450 |
Organization and Summary of S_5
Organization and Summary of Significant Accounting Policies (Details Narrative) $ in Thousands | 12 Months Ended |
Dec. 31, 2023 USD ($) | |
Accounting Policies [Abstract] | |
FDIC Insured limit | $ 250 |
Exceeded federally insured limits | 8,200 |
Relieved asset retirement obligation | $ 100 |
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, 2023 | Dec. 31, 2022 | |
Related Party Transaction [Line Items] | ||
Annual management fee percentage rate | 2.50% | |
Management fees to affiliate | $ 713 | $ 719 |
Percentage of total distributions allocated to fund manager | 15% | |
Partners' capital account, distribution | $ 2,758 | 2,947 |
Fund Manager [Member] | ||
Related Party Transaction [Line Items] | ||
Partners' capital account, distribution | 413 | 442 |
Management [Member] | ||
Related Party Transaction [Line Items] | ||
Management fees to affiliate | $ 700 | $ 700 |
Commitments and Contingencies (
Commitments and Contingencies (Details Narrative) $ in Millions | 12 Months Ended |
Dec. 31, 2023 USD ($) | |
Commitments and Contingencies Disclosure [Abstract] | |
Commitments for the drilling and development of investment properties | $ 3.2 |
Commitments for asset retirement obligations included in estimated capital commitments | 1.2 |
Commitments for the drilling and development of investment properties expected to be incurred in the next 12 months | $ 0.1 |
Information about Oil and Gas_3
Information about Oil and Gas Producing Activities (Details) - USD ($) $ in Thousands | Dec. 31, 2023 | Dec. 31, 2022 |
Information About Oil And Gas Producing Activities | ||
Advances to operators for capital expenditures | $ 103 | |
Proved properties | 10,750 | 9,508 |
Accumulated depletion and amortization | (7,896) | (7,541) |
Total oil and gas properties, net | $ 2,957 | $ 1,967 |
Information about Oil and Gas_4
Information about Oil and Gas Producing Activities (Details 1) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Information About Oil And Gas Producing Activities | ||
Development costs | $ 1,235 | $ 128 |
Total Costs | $ 1,235 | $ 128 |
Information about Oil and Gas_5
Information about Oil and Gas Producing Activities (Details 2) | 12 Months Ended | ||
Dec. 31, 2023 MBbls Mcf | Dec. 31, 2022 MBbls Mcf | ||
Oil [Member] | |||
Reserve Quantities [Line Items] | |||
Beginning of year | 318.2 | 335.9 | |
Revisions of previous estimates | [1] | (46.6) | 23.4 |
Production | (42.7) | (41.1) | |
End of year | 228.9 | 318.2 | |
Beginning of year | 228.1 | 176.2 | |
End of year | 218.8 | 228.1 | |
Beginning of year | 90.1 | 159.7 | |
End of year | 10.1 | 90.1 | |
NGL (BBLS) [Member] | |||
Reserve Quantities [Line Items] | |||
Beginning of year | 109.6 | 124.9 | |
Revisions of previous estimates | [1] | (45.7) | (9.3) |
Production | (6.4) | (6) | |
End of year | 57.5 | 109.6 | |
Beginning of year | 62.1 | 55 | |
End of year | 50.5 | 62.1 | |
Beginning of year | 47.5 | 69.9 | |
End of year | 7 | 47.5 | |
Natural Gas [Member] | |||
Reserve Quantities [Line Items] | |||
Beginning of year | Mcf | 808.3 | 973.7 | |
Revisions of previous estimates | Mcf | [1] | (297.8) | (121.5) |
Production | Mcf | (51.5) | (43.9) | |
End of year | Mcf | 459 | 808.3 | |
Beginning of year | Mcf | 457.9 | 432.1 | |
End of year | Mcf | 403.1 | 457.9 | |
Beginning of year | Mcf | 350.4 | 541.6 | |
End of year | Mcf | 55.9 | 350.4 | |
Other Nonrenewable Natural Resources [Member] | |||
Reserve Quantities [Line Items] | |||
Beginning of year | [2] | 562.5 | 623.1 |
Revisions of previous estimates | [1],[2] | (141.9) | (6.2) |
Production | [2] | (57.7) | (54.4) |
End of year | [2] | 362.9 | 562.5 |
Beginning of year | [2] | 366.5 | 303.3 |
End of year | [2] | 336.5 | 366.5 |
Beginning of year | [2] | 196 | 319.8 |
End of year | [2] | 26.4 | 196 |
[1]Revisions of previous estimates were attributable to well performance.[2]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. |
Information about Oil and Gas_6
Information about Oil and Gas Producing Activities (Details 3) - USD ($) $ in Thousands | Dec. 31, 2023 | Dec. 31, 2022 |
Information About Oil And Gas Producing Activities | ||
Future cash inflows | $ 19,437 | $ 38,791 |
Future production costs | (4,711) | (8,373) |
Future development costs | (2,107) | (3,973) |
Future net cash flows | 12,619 | 26,445 |
10% annual discount for estimated timing of cash flows | (2,492) | (7,482) |
Standardized measure of discounted future net cash flows | $ 10,127 | $ 18,963 |
Information about Oil and Gas_7
Information about Oil and Gas Producing Activities (Details 4) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Information About Oil And Gas Producing Activities | ||
Net change in sales and transfer prices and in production costs related to future production | $ (4,703) | $ 10,677 |
Sales and transfers of oil and gas produced during the period | (3,113) | (4,030) |
Changes in estimated future development costs | 1,866 | (949) |
Net change due to revisions in quantities estimates | (4,622) | (241) |
Accretion of discount | 1,896 | 1,088 |
Other | (160) | 1,542 |
Aggregate change in the standardized measure of discounted future net cash flows for the year | $ (8,836) | $ 8,087 |