Document and Entity Information
Document and Entity Information - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2018 | Mar. 01, 2019 | |
Document And Entity Information [Abstract] | ||
Document Type | 10-K | |
Amendment Flag | false | |
Document Period End Date | Dec. 31, 2018 | |
Entity Registrant Name | RIDGEWOOD ENERGY A-1 FUND LLC | |
Entity Central Index Key | 1,457,919 | |
Current Fiscal Year End Date | --12-31 | |
Document Fiscal Period Focus | FY | |
Document Fiscal Year Focus | 2,018 | |
Entity Filer Category | Non-accelerated Filer | |
Entity Small Business | true | |
Entity Emerging Growth Company | false | |
Entity Shell Company | false | |
Entity Units Outstanding | 207.7026 | |
Entity Current Reporting Status | Yes | |
Entity Well-known Seasoned Issuer | No | |
Entity Voluntary Filers | No | |
Entity Public Float | $ 0 |
BALANCE SHEETS
BALANCE SHEETS - USD ($) $ in Thousands | Dec. 31, 2018 | Dec. 31, 2017 |
Current assets: | ||
Cash and cash equivalents | $ 2,124 | $ 2,423 |
Salvage fund | 1,191 | |
Production receivable | 338 | 491 |
Due from affiliate (Note 3) | 50 | |
Other current assets | 48 | 52 |
Total current assets | 2,560 | 4,157 |
Salvage fund | 1,710 | 355 |
Oil and gas properties: | ||
Proved properties | 20,663 | 20,498 |
Less: accumulated depletion and amortization | (9,405) | (7,391) |
Total oil and gas properties, net | 11,258 | 13,107 |
Total assets | 15,528 | 17,619 |
Current liabilities: | ||
Due to operators | 618 | 609 |
Accrued expenses | 43 | 54 |
Current portion of long-term borrowings | 945 | 1,566 |
Asset retirement obligations | 1,191 | |
Other current liabilities | 40 | |
Total current liabilities | 1,606 | 3,460 |
Long-term borrowings | 2,256 | 5,639 |
Asset retirement obligations | 1,446 | 210 |
Total liabilities | 5,308 | 9,309 |
Commitments and contingencies (Note 5) | ||
Members' capital: | ||
Distributions | (5,129) | (5,058) |
Retained earnings | 6,054 | 5,484 |
Manager's total | 925 | 426 |
Capital contributions (250 shares authorized; 207.7026 issued and outstanding) | 41,143 | 41,143 |
Syndication costs | (4,804) | (4,804) |
Distributions | (35,829) | (35,427) |
Retained earnings | 8,784 | 6,970 |
Shareholders' total | 9,294 | 7,882 |
Accumulated other comprehensive income | 1 | 2 |
Total members' capital | 10,220 | 8,310 |
Total liabilities and members' capital | $ 15,528 | $ 17,619 |
BALANCE SHEETS (Parenthetical)
BALANCE SHEETS (Parenthetical) - shares | Dec. 31, 2018 | Dec. 31, 2017 |
Statement of Financial Position [Abstract] | ||
Shares authorized | 250 | 250 |
Shares issued | 207.7026 | 207.7026 |
Shares outstanding | 207.7026 | 207.7026 |
STATEMENTS OF OPERATIONS AND CO
STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME (LOSS) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Revenue | ||
Oil and gas revenue | $ 4,947 | $ 3,865 |
Other revenue from affiliate | 50 | |
Total revenue | 4,997 | 3,865 |
Expenses | ||
Depletion and amortization | 3,199 | 3,445 |
Management fees to affiliate | 373 | 374 |
Operating expenses | 611 | 642 |
General and administrative expenses | 188 | 168 |
Total expenses | 4,371 | 4,629 |
Gain on sale of oil and gas properties | 865 | |
Income (loss) from operations | 1,491 | (764) |
Other income (loss) | ||
Gain on debt extinguishment | 1,313 | |
Other income | 40 | |
Interest expense, net | (460) | (744) |
Total other income (loss) | 893 | (744) |
Net income (loss) | 2,384 | (1,508) |
Other comprehensive loss | ||
Unrealized loss on marketable securities | (1) | (1) |
Total comprehensive income (loss) | 2,383 | (1,509) |
Manager Interest | ||
Net income | 570 | 367 |
Shareholder Interest | ||
Net income (loss) | $ 1,814 | $ (1,875) |
Net income (loss) per share | $ 8,732 | $ (9,025) |
STATEMENTS OF CHANGES IN PARTNE
STATEMENTS OF CHANGES IN PARTNERS CAPITAL - USD ($) $ in Thousands | # of Shares [Member] | Manager [Member] | Shareholders [Member] | Accumulated Other Comprehensive Income (loss) [Member] | Total |
Balances at Dec. 31, 2016 | $ 59 | $ 9,757 | $ 3 | $ 9,819 | |
Balances, shares at Dec. 31, 2016 | 207.7026 | 207.7026 | |||
Net income (loss) | 367 | (1,875) | $ (1,508) | ||
Other comprehensive loss | (1) | (1) | |||
Balances at Dec. 31, 2017 | 426 | 7,882 | 2 | $ 8,310 | |
Balances, shares at Dec. 31, 2017 | 207.7026 | 207.7026 | |||
Distributions | (71) | (402) | $ (473) | ||
Net income (loss) | 570 | 1,814 | 2,384 | ||
Other comprehensive loss | (1) | (1) | |||
Balances at Dec. 31, 2018 | $ 925 | $ 9,294 | $ 1 | $ 10,220 | |
Balances, shares at Dec. 31, 2018 | 207.7026 | 207.7026 |
STATEMENTS OF CASH FLOWS
STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Cash flows from operating activities | ||
Net income (loss) | $ 2,384 | $ (1,508) |
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | ||
Depletion and amortization | 3,199 | 3,445 |
Gain on sale of oil and gas properties | (865) | |
Accretion expense | 25 | 30 |
Gain on debt extinguishment | (1,313) | |
Amortization of debt discounts and deferred financing costs | 1 | 122 |
Changes in assets and liabilities: | ||
Decrease (increase) in production receivable | 144 | (167) |
Increase in due from affiliate | (50) | |
Decrease in other current assets | 4 | 67 |
Increase in due to operators | 62 | |
Decrease in accrued expenses | (2) | (200) |
Decrease in other current liabilities | (40) | |
Settlement of asset retirement obligations | (13) | (82) |
Net cash provided by operating activities | 3,474 | 1,769 |
Cash flows from investing activities | ||
Capital expenditures for oil and gas properties | (2,211) | (2,749) |
Proceeds from sale of oil and gas properties | 3,065 | |
(Increase) decrease in salvage fund | (165) | 5 |
Net cash provided by (used in) investing activities | 689 | (2,744) |
Cash flows from financing activities | ||
Repayments of long-term borrowings | (3,989) | (60) |
Distributions | (473) | |
Net cash used in financing activities | (4,462) | (60) |
Net decrease in cash and cash equivalents | (299) | (1,035) |
Cash and cash equivalents, beginning of year | 2,423 | 3,458 |
Cash and cash equivalents, end of year | 2,124 | 2,423 |
Supplemental disclosure of cash flow information | ||
Cash paid for interest, net of amounts capitalized | 468 | 817 |
Supplemental disclosure of non-cash investing activities | ||
Due to operators for accrued capital expenditures for oil and gas properties | $ 509 | $ 500 |
Organization and Summary of Sig
Organization and Summary of Significant Accounting Policies | 12 Months Ended |
Dec. 31, 2018 | |
Organization, Consolidation and Presentation of Financial Statements [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 3, 4 and 5. Use of Estimates The preparation of financial statements in accordance with accounting principles generally accepted in the United States of America (“GAAP”) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities as of the date of the financial statements and the reported amounts of revenue and expense during the reporting period. On an ongoing basis, the Manager reviews its estimates, including those related to the fair value of financial instruments, depletion and amortization, determination of proved reserves, impairment of long-lived assets and asset retirement obligations. Actual results may differ from those estimates. Fair Value Measurements The Fund follows the accounting guidance for fair value measurement for measuring fair value of assets and liabilities in its financial statements. The fair value measurement guidance provides a hierarchy that prioritizes and defines the types of inputs used to measure fair value. The fair value hierarchy gives the highest priority to Level 1 inputs, which consist of unadjusted quoted prices for identical instruments in active markets. Level 2 inputs consist of quoted prices for similar instruments. Level 3 inputs are unobservable inputs and include situations where there is little, if any, market activity for the instrument; hence, these inputs have the lowest priority. The Fund’s financial instruments consist of cash and cash equivalents, salvage fund, production receivable, due from affiliate, other current assets, due to operators, accrued expenses, other current liabilities and long-term debt. Except for long-term debt, the carrying amounts of these instruments approximate fair value due to their short-term nature. Mortgage-backed securities within the salvage fund are recorded based on Level 2 inputs, as such instruments trade in over-the-counter markets and the inputs are consistent with the Level 2 definition above. The Fund’s long-term debt is valued using an income approach and is classified as Level 3 in the fair value hierarchy. The fair value of the long-term debt is estimated by discounting future cash payments of principal and interest to a present value amount using a market yield for debt instruments with similar terms, maturities and credit ratings. The Fund also applies the provisions of the fair value measurement accounting guidance to its non-financial assets and liabilities, such as oil and gas properties and asset retirement obligations, on a non-recurring basis. Cash and Cash Equivalents All highly liquid investments with maturities, when purchased, of three months or less, are considered cash equivalents. These balances, as well as cash on hand, are included in “Cash and cash equivalents” on the balance sheet. As of December 31, 2018, the Fund had no cash equivalents. At times, deposits may be in excess of federally insured limits, which are $250 thousand per insured financial institution. As of December 31, 2018, the Fund’s bank balances were maintained in uninsured bank accounts at Wells Fargo Bank, N.A. Salvage Fund The Fund deposits cash in a separate interest-bearing account, or salvage fund, to provide for the dismantling and removal of production platforms and facilities and plugging and abandoning its wells at the end of their useful lives in accordance with applicable federal and state laws and regulations. As of December 31, 2018 and 2017, the Fund had investments in federal agency mortgage-backed securities as detailed in the following table, which are classified as available-for-sale. Available-for-sale securities are carried in the financial statements at fair value. Gross Amortized Unrealized Fair Cost Gains Value (in thousands) Government National Mortgage Association security (GNMA July 2041) December 31, 2018 $ 36 $ 1 $ 37 December 31, 2017 $ 46 $ 2 $ 48 The unrealized gains on the Fund's investments in federal agency mortgage-backed securities were the result of fluctuations in market interest rates. The contractual cash flows of those investments are guaranteed by an agency of the U.S. government. Unrealized gains or losses on available-for-sale debt securities are reported in other comprehensive income until realized. For all investments, interest income is accrued as earned and amortization of premium or discount, if any, is included in interest income. Interest earned on the account will become part of the salvage fund. There are no restrictions on withdrawals from the salvage fund. Oil and Gas Properties The Fund invests in oil and gas properties, which are operated by unaffiliated entities that are responsible for drilling, administering and producing activities pursuant to the terms of the applicable operating agreements with working interest owners. The Fund’s portion of exploration, drilling, operating and capital equipment expenditures is billed by operators. Acquisition, exploration and development costs are accounted for using the successful efforts method. Costs of acquiring unproved and proved oil and natural gas leasehold acreage, including lease bonuses, brokers’ fees and other related costs are capitalized. Costs of drilling and equipping productive wells and related production facilities are capitalized. The costs of exploratory wells are capitalized pending determination of whether proved reserves have been found. If proved commercial reserves are not found, exploratory well costs are expensed as dry-hole costs. At times, the Fund receives adjustments to certain wells from their respective operators upon review and audit of the wells’ costs. Annual lease rentals and exploration expenses are expensed as incurred. All costs related to production activity, transportation expense and workover efforts are expensed as incurred. Once a property has been determined to be fully depleted or upon the sale, retirement or abandonment of a property, the cost and related accumulated depletion and amortization, if any, is eliminated from the property accounts, and the resultant gain or loss is recognized. The Fund may be required to advance its share of the estimated succeeding month’s expenditures to the operator for its oil and gas properties. As the costs are incurred, the advances are reclassified to proved properties. Asset Retirement Obligations For oil and gas properties, there are obligations to perform removal and remediation activities when the properties are retired. Upon the determination that a property is either proved or dry, a retirement obligation is incurred. The Fund recognizes the fair value of a liability for an asset retirement obligation in the period incurred. Plug and abandonment costs associated with unsuccessful projects are expensed as dry-hole costs. Annually, or more frequently if an event occurs that would dictate a change in assumptions or estimates underlying the obligations, the Fund reassesses its asset retirement obligations to determine whether any revisions to the obligations are necessary. The Fund maintains a salvage fund to provide for the funding of future asset retirement obligations. The following table presents changes in asset retirement obligations during the years ended December 31, 2018 and 2017: December 31, 2018 2017 (in thousands) Balance, beginning of year $ 1,401 $ 1,675 Liabilities incurred 2 2 Liabilities settled/relieved (54 ) (82 ) Accretion expense 25 30 Revision of estimates 72 (224 ) Balance, end of year $ 1,446 $ 1,401 During the year ended December 31, 2017, the Fund recorded credits to depletion expense totaling $0.1 million, which related to an adjustment to the asset retirement obligation for a fully depleted property. Syndication Costs Syndication costs are direct costs incurred by the Fund in connection with the offering of the Fund’s shares, including professional fees, selling expenses and administrative costs payable to the Manager, an affiliate of the Manager and unaffiliated broker-dealers, which are reflected on the Fund’s balance sheet as a reduction of shareholders’ capital. Revenue Recognition The Fund adopted the new revenue standard on January 1, 2018 using the modified retrospective method for all new contracts entered into after January 1, 2018 and all existing contracts for which revenues have not been recognized under the previous revenue guidance as of December 31, 2017. Although the Fund did not identify changes to its revenue recognition that resulted in a cumulative adjustment to retained earnings on January 1, 2018, the adoption of the accounting guidance resulted in enhanced disclosures related to revenue recognition policies, the Fund’s performance obligations and significant judgments used in applying the new revenue standard as described below. Revenue from Contracts with Customers Oil and gas revenues are recognized at the point when control of oil and natural gas is transferred to the customers. Natural gas liquid (“NGL”) sales are included within gas sales. The Fund’s oil and natural gas generally is sold to its customers at prevailing market prices based on an index in which the prices are published, adjusted for pricing differentials, quality of the oil and pipeline allowances. Oil and Gas Revenue Generally, the Fund sells oil and natural gas under two types of agreements, which are common in the oil and gas industry. In the first type of agreement, a netback agreement, the Fund receives a price, net of pricing differentials as well as transportation expense incurred by the customer, and the Fund records revenue at the wellhead at the net price received where control transfers to the customer. In the second type of agreement, the Fund delivers oil and natural gas to the customer at a contractually agreed-upon delivery point where the customer takes control. The Fund pays a third-party to transport the oil and natural gas and receives a specific market price from the customer net of pricing adjustments. The Fund records the transportation expense within operating expenses in the statements of operations. Under the Fund’s natural gas processing contracts, the Fund delivers natural gas to a midstream processing company at the inlet of the midstream processing company’s facility. The midstream processing company gathers and processes the natural gas and remits the proceeds to the Fund for the sale of NGLs. In this type of arrangement, the Fund evaluates whether it is the principal or agent in the transaction. The Fund concluded that it is the principal and the ultimate third-party purchaser is the customer; therefore, the Fund recognizes revenue on a gross basis, with transportation, gathering and processing fees recorded as an expense within operating expenses in the statements of operations. In certain instances, the Fund may elect to take its residue gas and NGLs in-kind at the tailgate of the midstream company’s processing plant and subsequently market such volumes. Through its marketing process, the Fund delivers the residue gas and NGLs to the ultimate third-party customer at a contractually agreed-upon delivery point and receives a specified market price from the customer. In this arrangement, the Fund recognizes revenue when control transfers to the customer at the delivery point based on the market price received from the customer. The transportation, gathering and processing fees are recorded as expense within operating expenses in the statements of operations. The Fund assesses the performance obligations promised in its oil and natural gas contracts based on each unit of oil and natural gas that will be transferred to its customer because each unit is capable of being distinct. The Fund satisfies its performance obligation when control transfers at a point in time when its customer is able to direct the use of, and obtain substantially all of the benefits from, the oil and natural gas delivered. Under each of the Fund’s oil and natural gas contracts, contract prices are variable and based on an index in which the prices are published, which fluctuate as a result of related industry variables, adjusted for pricing differentials, quality of the oil and pipeline allowances. The use of index-based pricing with predictable differentials reduces the level of uncertainty related to oil and gas prices. Additionally, any variable consideration is not constrained. Payments are received in the month following the oil and natural gas production month. Adjustments that occur after delivery, such as quality bank adjustments, are reflected in revenue in the month payments are received. Transaction Price Allocated to Remaining Performance Obligations Under the Fund’s oil and natural gas contracts, each unit of oil and natural gas represents a separate performance obligation; therefore, future volumes are wholly unsatisfied and the transaction price related to the remaining performance obligations is the variable index-based price attributable to each unit of oil and natural gas that is transferred to the customer. Contract Balances The Fund invoices customers once its performance obligations have been satisfied, at which point the payment is unconditional. Accordingly, the Fund’s oil and natural gas contracts do not give rise to contract assets or liabilities under the new revenue standard. The receivables related to the Fund’s oil and gas revenue are included within “Production receivable” on the balance sheets. Prior Period Performance Obligations The Fund records oil and gas revenue in the month production is delivered to its customers. However, settlement statements for residue gas and NGLs sales may not be received for 30 to 60 days after the date production is delivered. As a result, the Fund is required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the residue gas and NGLs. The Fund records the differences between its estimates and the actual amounts received in the month that the payment is received from the customer. The Fund has an estimation process for revenue and related accruals, and any identified difference between its revenue estimates and actual revenue historically have not been significant. There was no material revenue recognized in the current period from performance obligations satisfied in previous periods. Other Revenue from Affiliate Other revenue is generated from the Fund’s production handling, gathering and operating services agreement with an affiliated entity. The Fund simply earns a fee for its services and recognizes these fees as revenue at the time its performance obligations are satisfied as the control of oil and natural gas is never transferred to the Fund. Impairment of Long-Lived Assets The Fund reviews the carrying value of its oil and gas properties for impairment whenever events and circumstances indicate that the recorded carrying value of its oil and gas properties may not be recoverable. Impairments are determined by comparing estimated future net undiscounted cash flows to the carrying value of the assets at the time of the review. If the carrying value exceeds the estimated future net undiscounted cash flows, the carrying value of the asset is written down to fair value, which is determined using a valuation technique that considers both market and income approaches and uses Level 3 inputs. The fair value determinations require considerable judgment and are sensitive to change. Different pricing assumptions, reserve estimates or discount rates could result in a different calculated impairment There were no impairments of oil and gas properties during the years ended December 31, 2018 and 2017. Fluctuations in oil and natural gas commodity prices may impact the fair value of the Fund’s oil and gas properties. If oil and natural gas commodity prices decline, even if only for a short period of time, it is possible that impairments of oil and gas properties will occur. Depletion and Amortization Depletion and amortization of the cost of proved oil and gas properties are calculated using the units-of-production method. Proved developed reserves are used as the base for depleting capitalized costs associated with successful exploratory well costs, development costs and related facilities, other than offshore platforms. The sum of proved developed and proved undeveloped reserves is used as the base for depleting or amortizing leasehold acquisition costs and costs to construct offshore platform and associated asset retirement costs. Income Taxes No provision is made for income taxes in the financial statements. The Fund is a limited liability company, and as such, the Fund’s income or loss is passed through and included in the tax returns of the Fund’s shareholders. The Fund files U.S. Federal and State tax returns and the 2015 through 2017 tax returns remain open for examination by tax authorities. Income and Expense Allocation Profits and losses are allocated to shareholders and the Manager in accordance with the LLC Agreement. Distributions Distributions to shareholders are allocated in proportion to the number of shares held. The Manager determines whether available cash from operations, as defined in the LLC Agreement, will be distributed. Such distributions are allocated 85% to the shareholders and 15% to the Manager, as required by the LLC Agreement. Available cash from dispositions, as defined in the LLC Agreement, will be paid 99% to shareholders and 1% to the Manager until the shareholders have received total distributions equal to their capital contributions. After shareholders have received distributions equal to their capital contributions, 85% of available cash from dispositions will be distributed to shareholders and 15% to the Manager. Recent Accounting Pronouncements In August 2018, the Financial Accounting Standards Board (“FASB”) issued accounting guidance on fair value measurement, which adds, among other things, disclosure requirements for the range and weighted average of significant unobservable inputs used to develop Level 3 fair value measurements. This accounting guidance is effective for the Fund in the first quarter 2020 with early adoption permitted. The Fund does not expect this accounting guidance will have a material impact on its financial statements upon adoption. In February 2016, the FASB issued accounting guidance on leases as amended on January 2018 and July 2018, which requires an entity to recognize all lease assets and liabilities with a term greater than one year on the balance sheet, disclose key quantitative and qualitative information about leasing arrangements, and permits an entity not to evaluate existing or expired land easements that were not previously assessed under the existing lease guidance. The accounting guidance does not apply to leases of mineral rights to explore for or use of oil and natural gas. The accounting guidance is effective for the Fund beginning January 1, 2019 with early adoption permitted. Although the Fund, as a non-operator, does not enter into lease agreements to support its operations, the Fund completed its evaluation of existing contracts that may have a lease impact and embedded lease features to determine the contracts to which the new guidance applies. Based on this evaluation, the Fund determined its existing contracts did not meet the definition of leases under the new accounting guidance and therefore, did not qualify for lease accounting. In May 2014, the FASB issued accounting guidance on revenue recognition (“New Revenue Standard”), which provides for a single five-step model to be applied to all revenue contracts with customers. In July 2015, the FASB issued a deferral of the effective date of the New Revenue Standard to 2018, with early adoption permitted in 2017. In March 2016, the FASB issued accounting guidance, which clarifies the implementation guidance on principal versus agent considerations in the New Revenue Standard. In April 2016, the FASB issued guidance on identifying performance obligations and licensing and in May 2016, the FASB issued final amendments which provided narrow scope improvements and practical expedients related to the implementation of the New Revenue Standard. The New Revenue Standard may be applied either retrospectively or through the use of a modified-retrospective method. Under the New Revenue Standard, the revenue associated with the Fund’s existing contracts will be recognized in the period that control of the related commodity is transferred to the customer, which is generally consistent with the Fund’s previous revenue recognition model. The Fund adopted the New Revenue Standard using the modified retrospective method on January 1, 2018. See “Revenue Recognition” above for the required disclosures related to the impact of adopting this guidance and a discussion of the Fund’s updated policies related to revenue recognition for revenue from contracts with customers. |
Oil and Gas Properties
Oil and Gas Properties | 12 Months Ended |
Dec. 31, 2018 | |
Oil And Gas Properties | |
Oil and Gas Properties | 2. Oil and Gas Properties On August 10, 2018, the Fund entered into a purchase and sale agreement (“PSA”) to sell a portion of the Fund’s working interest in the Beta Project to Walter Oil & Gas Corporation and Gordy Oil Company (collectively the “Buyers”) with an effective date of January 1, 2018. Certain other funds managed by the Manager were also parties to the PSA. The Fund had a 2.0% working interest in the Beta Project and sold a 0.364% working interest to the Buyers for a total purchase price of $3.3 million, subject to purchase price and customary post-closing adjustments. The transaction closed on August 10, 2018 and the Fund received $3.1 million in cash, which included preliminary purchase price adjustments primarily related to the net cash flows from the effective date to the closing date. During fourth quarter 2018, the Fund recognized a post-closing adjustment in the amount of $34 thousand, which was recorded as an adjustment to the purchase price and included within “Gain on sale of oil and gas properties” on its statements of operations. The net carrying value of the working interest sold as of the closing date was $2.2 million and the related asset retirement obligation was $40 thousand. A gain to the Fund of $0.9 million was recognized during the year ended December 31, 2018, including post-closing adjustments. The proceeds from the sale were utilized to repay a portion of the long-term debt outstanding under the credit agreement. |
Related Parties
Related Parties | 12 Months Ended |
Dec. 31, 2018 | |
Related Party Transactions [Abstract] | |
Related Parties | 3 . Related Parties Pursuant to the terms of the LLC Agreement, the Manager is entitled to receive an annual management fee, payable monthly, of 2.5% of total capital contributions, net of cumulative dry-hole and related well costs incurred by the Fund, however, the Manager is permitted to waive the management fee at its own discretion. Therefore, the management fee may be temporarily waived to accommodate the Fund’s short-term commitments. Management fees during each of the years ended December 31, 2018 and 2017 were $0.4 million. The Manager is also entitled to receive 15% of the cash distributions from operations made by the Fund. Distributions paid to the Manager during the year ended December 31, 2018 were $0.1 million. The Fund did not pay distributions during the year ended December 31, 2017. Beta Sales and Transport, LLC The Fund utilizes Beta Sales and Transport, LLC (“Beta S&T”), a wholly-owned subsidiary of the Manager, as aggregator to and as an accommodation for the Fund and other funds managed by the Manager to facilitate the transportation and sale of oil and natural gas produced from the Beta Project. In 2016, the Fund entered into a master agreement with Beta S&T pursuant to which Beta S&T is obligated to purchase from the Fund all of its interests in oil and natural gas produced from the Beta Project and sell such volumes to unrelated third-party purchasers. Pursuant to the master agreement, Beta S&T is a pass-through entity such that it receives no benefit or compensation for the services provided under the master agreement or under any other agreements it enters into with regard to the oil and natural gas purchased from the Fund. The Fund and other funds managed by the Manager have agreed to indemnify, defend and hold harmless Beta S&T from and against all claims, liabilities, losses, causes of action, costs and expenses asserted against it as a result of or arising from any act or omission, breach and claims for losses or damages arising out of its dealing with third parties with respect to the transportation, processing or sale of oil and natural gas from the Beta Project. The revenues and expenses from the sale of oil and natural gas to third-party purchasers are recorded as oil and gas revenue and operating expenses in the Fund’s statements of operations, and are allocable to the Fund based on the Fund’s working interest ownership in the Beta Project. Production Handling, Gathering and Operating Services Agreement On December 12, 2016, the Fund and other third party working interest owners in the Beta Project (collectively, the “Beta Project Owners”) entered into a production handling, gathering and operating services agreement (“PHA”) with Ridgewood Claiborne, LLC, a wholly-owned entity of Ridgewood Energy Oil & Gas Fund II, L.P. (“Institutional Fund II”) and other third party working interest owners in the Claiborne Project (collectively, the “Producers”), whereby the Beta Project Owners will provide services related to the production handling and delivery of oil and natural gas production from the Claiborne Project via their owned Beta Project production facility. Institutional Fund II is an entity that is managed by the Fund’s Manager. The PHA was effective on December 12, 2016 and will continue in effect unless terminated by default, the Beta Project Owners or the Producers pursuant to the terms of the PHA (as amended on February 10, 2017, March 9, 2017, September 19, 2018 and November 30, 2018). Under the terms of the PHA, the Producers have agreed to pay the Beta Project Owners a fixed production handling fee for each barrel of oil and mcf of natural gas processed through the Beta Project production facility. Beginning in fourth quarter 2018, the Beta Project Owners commenced their production and handling services for the oil and natural gas produced from the Claiborne Project. As the control of oil and natural gas is never transferred, the Fund simply earns a fee for its services and recognizes these fees as revenue at the time its performance obligations are satisfied. During the year ended December 31, 2018, the Fund earned $0.1 million representing its proportionate share of the production handling fees earned from the production handling services, which are included within “Other revenue from affiliate” on its statements of operations and “Due from affiliate” on its balance sheets. The transactions are settled by issuance of a non-cash credit from the Beta Project operator to the Fund on behalf of the Producers when the operator performs the joint interest billing of the lease operating expenses due from the Fund. The revenue received from the PHA will be utilized by the Fund to repay a portion of the long-term debt outstanding under its credit agreement until the loan is repaid in full, in no event later than December 31, 2022. During the year ended December 31, 2018, the Fund recorded other income of $40 thousand related to a fee received upon execution of the PHA. There were no such amounts recorded during the year ended December 31, 2017. At times, short-term payables and receivables, which do not bear interest, arise from transactions with affiliates in the ordinary course of business. The Fund has working interest ownership in certain oil and natural gas projects, which are also owned by other entities that are likewise managed by the Manager. |
Credit Agreement - Beta Project
Credit Agreement - Beta Project Financing | 12 Months Ended |
Dec. 31, 2018 | |
Debt Disclosure [Abstract] | |
Credit Agreement - Beta Project Financing | 4. Credit Agreement – Beta Project Financing On June 1, 2018, the Fund and other participating funds managed by the Manager, and Rahr Energy Investments LLC, as administrative agent and lender (and other lenders that may become a party thereto, collectively “Lenders”), entered into a third amendment (the “Third Amendment”) effective as of September 1, 2018 to the credit agreement, dated as of November 27, 2012 (as amended by the first amendment to credit agreement, dated September 30, 2016, and the second amendment to credit agreement and reaffirmation of waiver, dated September 15, 2017 and as amended by the Third Amendment, the “Credit Agreement”). Subsequently, in conjunction with the sale of a portion of the Beta Project working interest and the repayment of a portion of amounts outstanding on the Credit Agreement, on August 10, 2018, the Fund and other participating funds managed by the Manager and the Lenders entered into a fourth amendment (the “Fourth Amendment”) to the Credit Agreement effective as of September 1, 2018. The Third Amendment extended the loan maturity from December 31, 2020 to December 31, 2022, revised the interest rate and required a monthly payment amount based on a fixed percentage of the Fund’s Net Revenue (as defined in the Credit Agreement) derived from the Beta Project. Previously, the annual interest rate of the loan was 8% compounded annually and the monthly principal and interest payments were based on the lesser of the monthly fixed amount of approximately $0.1 million or the Debt Service Cap amount, as defined in the old credit agreement. The Third Amendment also changed the overriding royalty interest (“ORRI”) in its working interest in the Beta Project conveyed to the Lenders to a fixed percentage of 10.81% from a tiered structure, and deferred the payment of such ORRI, which will not become payable to the Lenders until January 1, 2023. The Credit Agreement also required mandatory prepayment of excess cash flows received by the Fund from certain insurance reimbursements, platform related revenues, production handling fees and any additional revenues received with respect to the use of the Beta Project other than any revenues included in the calculation of Net Revenue, as well as proceeds from a sale or transfer of any interest in the Beta Project as permitted under the Credit Agreement. In August 2018, the proceeds from the sale of a portion of the working interest in the Beta Project were used to reduce the outstanding debt under the Credit Agreement. As a result, the Fourth Amendment principally reduced the fixed percentage for the calculation of the monthly payments and amended the interest calculation. Beginning on September 1, 2018 up to and including March 31, 2019, the Fund’s fixed percentage is 30%, which was based on the Fund’s ratio of outstanding debt to working interest ownership in the Beta Project determined on September 1, 2018, as scheduled in the Credit Agreement. Beginning on April 1, 2019 and each April 1st thereafter, the Fund’s fixed percentage will be the greater of (i) 30% or (ii) the Fixed Reassessment Percentage, as defined in the Credit Agreement. The Fixed Reassessment Percentage is determined annually and will be based on the Fund’s ratio of its outstanding debt as of the reassessment date relative to 80% of third-party reserve engineers’ proved plus probable future undiscounted cash flows attributable to the Beta Project through the maturity of the loan. Beginning on September 1, 2018 and thereafter until the loan is repaid in full, in no event later than December 31, 2022, the loan bears interest at a rate equal to 8.75% compounded monthly. The Fund reviewed the terms of the Third Amendment and determined that the conditions were met, pursuant to Accounting Standard Codification 470-50 Debt: Modification and Extinguishments (“ASC 470-50”) The Fund recognized a gain on debt extinguishment of $1.3 million during third quarter 2018, which is recorded within “Other income (loss)” in its statements of operations. The gain on debt extinguishment primarily represents non-cash gains associated with the change in the fair value of ORRI conveyed to the Lenders totaling $1.3 million and the difference between the fair value of the new debt and the carrying amount of the old debt totaling $16 thousand. The Fund estimated the fair value of the ORRI before and after the Fourth Amendment using a discounted cash flow method based on Level 3 inputs, which included future revenue from proved and probable oil and natural gas reserves from the Beta Project, future commodity pricing curves to derive future cash flows and a risk-adjusted discount rate of 9.0%. The change in the fair value of the ORRI of $1.3 million was recorded as an increase to property within “Total oil and gas properties, net” on the Fund’s balance sheet, which is being amortized to depletion expense using the units-of-production method over the life of the Beta Project. The Fund estimated the fair value of the amended debt by discounting future cash payments of principal and interest to a present value amount using a market yield for debt instruments with similar terms, maturities and credit ratings. The Fund used a market yield of 9.25% to estimate the fair value of the amended debt, which was determined to be $3.3 million. The discounted loan is being accreted to its face value over the remaining term of the amended debt. As of December 31, 2018 and 2017, the Fund had borrowings of $3.2 million and $7.2 million, respectively, under the Credit Agreement. The loan may be prepaid by the Fund without premium or penalty. As of December 31, 2018, the estimated fair value of the debt was $3.1 million. The unamortized debt discounts related to the amended debt of $15 thousand as of December 31, 2018 were presented as a reduction of “Long-term borrowings” on the balance sheet. There were no unamortized debt discounts and deferred financing costs as of December 31, 2017. Amortization expense during the years ended December 31, 2018 and 2017 of $1 thousand and $0.1 million, respectively, was expensed and included on the statements of operations within “Interest expense, net”. As of December 31, 2018 and 2017, there were no accrued interest costs outstanding. Interest costs incurred during the years ended December 31, 2018 and 2017 of $0.5 million and $0.6 million, respectively, were expensed and included on the statements of operations within “Interest expense, net. As of December 31, 2018, the estimated principal repayments of debt are as follows: $0.9 million in 2019, $1.1 million in 2020 and $1.2 million in 2021. The Credit Agreement contains customary covenants, with which the Fund was in compliance as of December 31, 2018 and 2017. |
Commitments and Contingencies
Commitments and Contingencies | 12 Months Ended |
Dec. 31, 2018 | |
Commitments and Contingencies Disclosure [Abstract] | |
Commitments and Contingencies | 5. Commitments and Contingencies Capital Commitments As of December 31, 2018, the Fund’s estimated capital commitments related to its oil and gas properties were $2.9 million (which include asset retirement obligations for the Fund’s projects of $1.9 million), of which $0.3 million is expected to be spent during the year ending December 31, 2019. As a result of continued development of the Beta Project as well as borrowing repayments, the Fund experienced negative cash flows during the year ended December 31, 2018. Future results of operations and cash flows are dependent on the continued successful development and the related production of oil and gas revenues from the Beta Project. Based upon its current cash position and its current reserve estimates, the Fund expects cash flow from operations to be sufficient to cover its commitments, borrowing repayments and ongoing operations. Reserve estimates are projections based on engineering data that cannot be measured with precision, require substantial judgment, and are subject to frequent revision. However, if cash flow from operations is not sufficient to meet the Fund’s commitments, the Manager will temporarily waive all or a portion of the management fee as well as provide short-term financing to accommodate the Fund’s short-term commitments if needed. Environmental and Governmental Regulations Many aspects of the oil and gas industry are subject to federal, state and local environmental laws and regulations. The Manager and operators of the Fund’s properties are continually taking action they believe appropriate to satisfy applicable federal, state and local environmental regulations. However, due to the significant public and governmental interest in environmental matters related to those activities, the Manager cannot predict the effects of possible future legislation, rule changes, or governmental or private claims. As of December 31, 2018 and 2017, there were no known environmental contingencies that required adjustment to, or disclosure in, the Fund’s financial statements. Oil and gas industry legislation and administrative regulations are periodically changed for a variety of political, economic, and other reasons. Any such future laws and regulations could result in increased compliance costs or additional operating restrictions, which could have a material adverse effect on the Fund’s operating results and cash flows. It is not possible at this time to predict whether such legislation or regulation, if proposed, will be adopted as initially written, if at all, or how legislation or new regulation that may be adopted would impact the Fund’s business. BOEM Notice to Lessees on Supplemental Bonding On July 14, 2016, the Bureau of Ocean Energy Management (“BOEM”) issued a Notice to Lessees (“NTL”) that discontinued and materially replaced existing policies and procedures regarding financial security (i.e. supplemental bonding) for decommissioning obligations of lessees of federal oil and gas leases and owners of pipeline rights-of-way, rights-of use and easements on the Outer Continental Shelf (“Lessees”). Generally, the NTL (i) ended the practice of excusing Lessees from providing such additional security where co-lessees had sufficient financial strength to meet such decommissioning obligations, (ii) established new criteria for determining financial strength and additional security requirements of such Lessees, (iii) provided acceptable forms of such additional security and (iv) replaced the waiver system with one of self-insurance. The rule became effective as of September 12, 2016; however on January 6, 2017, the BOEM announced that it was suspending the implementation timeline for six months in certain circumstances. On June 22, 2017, the BOEM announced that the implementation timeline extension will remain in effect pending the completion of its review of the NTL. However, as of December 31, 2018, the BOEM has not completed its review nor has the NTL been enforced. The impact of the NTL, if enforced without change or amendment, may require the Fund to fully secure all of its potential abandonment liabilities to the BOEM’s satisfaction using one or more of the enumerated methods for doing so. Potentially this could increase costs to the Fund if the Fund is required to obtain additional supplemental bonding, fund escrow accounts or obtain letters of credit. Insurance Coverage The Fund is subject to all risks inherent in the oil and natural gas business. Insurance coverage as is customary for entities engaged in similar operations is maintained, but losses may occur from uninsurable risks or amounts in excess of existing insurance coverage. The occurrence of an event that is not insured or not fully insured could have a material adverse impact upon earnings and financial position. Moreover, insurance is obtained as a package covering all of the entities managed by the Manager. Depending on the extent, nature and payment of claims made by the Fund or other entities managed by the Manager, yearly insurance coverage may be exhausted and become insufficient to cover a claim by the Fund in a given year. |
Information about Oil and Gas P
Information about Oil and Gas Producing Activities | 12 Months Ended |
Dec. 31, 2018 | |
Information About Oil And Gas Producing Activities [Abstract] | |
Information about Oil and Gas Producing Activities | Ridgewood Energy A-1 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 December 31, 2018 2017 (in thousands) Proved properties $ 20,663 $ 20,498 Accumulated depletion and amortization (9,405 ) (7,391 ) Oil and gas properties, net $ 11,258 $ 13,107 Table II - Costs Incurred in Oil and Gas Property Acquisition, Exploration, and Development Year ended December 31, 2018 2017 (in thousands) Exploration costs $ 8 $ 15 Development costs 2,294 2,269 $ 2,302 $ 2,284 Table III - Reserve Quantity Information Oil and gas reserves of the Fund have been estimated by independent petroleum engineers, Netherland, Sewell & Associates, Inc. at December 31, 2018 and 2017. These reserve disclosures have been prepared in compliance with the Securities and Exchange Commission rules. Due to inherent uncertainties and the limited nature of recovery data, estimates of reserve information are subject to change as additional information becomes available. December 31, 2018 December 31, 2017 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 261.6 20.6 132.4 304.3 175.1 8.1 220.4 219.9 Extensions and discoveries (b) - - - - 62.1 4.8 29.7 71.8 Revisions of previous estimates (c) 156.7 14.5 92.4 186.6 100.2 15.8 (63.4 ) 105.6 Production (73.3 ) (8.0 ) (53.6 ) (90.2 ) (75.8 ) (8.1 ) (54.3 ) (93.0 ) Sale of minerals in place (d) (40.8 ) (2.9 ) (19.2 ) (46.9 ) - - - - End of year 304.2 24.2 152.0 353.8 261.6 20.6 132.4 304.3 Proved developed reserves: Beginning of year 199.5 15.8 102.7 232.5 156.9 8.1 210.0 199.9 End of year 304.2 24.2 152.0 353.8 199.5 15.8 102.7 232.5 Proved undeveloped reserves: Beginning of year 62.1 4.8 29.7 71.8 18.2 - 10.4 20.0 End of year - - - - 62.1 4.8 29.7 71.8 (a) BOE refers to barrel of oil equivalent Barrel of oil equivalent is based on six MCF of natural gas to one barrel of oil or one barrel of NGL, which reflects an energy content equivalency and not a price or revenue equivalency. (b) Extensions and discoveries as of December 31, 2017 were attributable to extensions for the Beta Project. (c) Revisions of previous estimates were attributable to well performance. (d) On August 10, 2018, the Fund sold a portion of the Fund’s working interest in the Beta Project to third parties. Table IV - Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves Summarized in the following table is information for the Fund with respect to the standardized measure of discounted future net cash flows relating to proved oil and gas reserves. Future cash inflows were determined based on average first-of-the-month pricing for the prior twelve-month period. Future production and development costs are derived based on current costs assuming continuation of existing economic conditions. December 31, 2018 2017 (in thousands) Future cash inflows $ 20,066 $ 12,596 Future production costs (2,627 ) (2,867 ) Future development costs (2,631 ) (3,026 ) Future net cash flows 14,808 6,703 10% annual discount for estimated timing of cash flows (2,439 ) (970 ) Standardized measure of discounted future estimated net cash flows $ 12,369 $ 5,733 Table V - 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, 2018 2017 (in thousands) Net change in sales and transfer prices and in production costs $ 4,466 $ 2,458 Sales and transfers of oil and gas produced during the period (4,376 ) (3,293 ) Net change due to extensions, discoveries, and improved recovery - 1,489 Net change due to purchases and sales of minerals in place (787 ) - Changes in estimated future development costs 395 37 Net change due to revisions in quantities estimates 7,686 2,888 Accretion of discount 573 250 Other (1,321 ) (595 ) Aggregate change in the standardized measure of discounted future net cash $ 6,636 $ 3,234 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 (Policy) | 12 Months Ended |
Dec. 31, 2018 | |
Organization, Consolidation and Presentation of Financial Statements [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, the Manager reviews its estimates, including those related to the fair value of financial instruments, depletion and amortization, determination of proved reserves, impairment of long-lived assets and asset retirement obligations. Actual results may differ from those estimates. |
Fair Value Measurements | Fair Value Measurements The Fund follows the accounting guidance for fair value measurement for measuring fair value of assets and liabilities in its financial statements. The fair value measurement guidance provides a hierarchy that prioritizes and defines the types of inputs used to measure fair value. The fair value hierarchy gives the highest priority to Level 1 inputs, which consist of unadjusted quoted prices for identical instruments in active markets. Level 2 inputs consist of quoted prices for similar instruments. Level 3 inputs are unobservable inputs and include situations where there is little, if any, market activity for the instrument; hence, these inputs have the lowest priority. The Fund’s financial instruments consist of cash and cash equivalents, salvage fund, production receivable, due from affiliate, other current assets, due to operators, accrued expenses, other current liabilities and long-term debt. Except for long-term debt, the carrying amounts of these instruments approximate fair value due to their short-term nature. Mortgage-backed securities within the salvage fund are recorded based on Level 2 inputs, as such instruments trade in over-the-counter markets and the inputs are consistent with the Level 2 definition above. The Fund’s long-term debt is valued using an income approach and is classified as Level 3 in the fair value hierarchy. The fair value of the long-term debt is estimated by discounting future cash payments of principal and interest to a present value amount using a market yield for debt instruments with similar terms, maturities and credit ratings. The Fund also applies the provisions of the fair value measurement accounting guidance to its non-financial assets and liabilities, such as oil and gas properties and asset retirement obligations, on a non-recurring basis. |
Cash and Cash Equivalents | Cash and Cash Equivalents All highly liquid investments with maturities, when purchased, of three months or less, are considered cash equivalents. These balances, as well as cash on hand, are included in “Cash and cash equivalents” on the balance sheet. As of December 31, 2018, the Fund had no cash equivalents. At times, deposits may be in excess of federally insured limits, which are $250 thousand per insured financial institution. As of December 31, 2018, the Fund’s bank balances were maintained in uninsured bank accounts at Wells Fargo Bank, N.A. |
Salvage Fund | 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. As of December 31, 2018 and 2017, the Fund had investments in federal agency mortgage-backed securities as detailed in the following table, which are classified as available-for-sale. Available-for-sale securities are carried in the financial statements at fair value. Gross Amortized Unrealized Fair Cost Gains Value (in thousands) Government National Mortgage Association security (GNMA July 2041) December 31, 2018 $ 36 $ 1 $ 37 December 31, 2017 $ 46 $ 2 $ 48 The unrealized gains on the Fund's investments in federal agency mortgage-backed securities were the result of fluctuations in market interest rates. The contractual cash flows of those investments are guaranteed by an agency of the U.S. government. Unrealized gains or losses on available-for-sale debt securities are reported in other comprehensive income until realized. For all investments, interest income is accrued as earned and amortization of premium or discount, if any, is included in interest income. 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. |
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. Plug and abandonment costs associated with unsuccessful projects are expensed as dry-hole costs. Annually, or more frequently if an event occurs that would dictate a change in assumptions or estimates underlying the obligations, the Fund reassesses its asset retirement obligations to determine whether any revisions to the obligations are necessary. The Fund maintains a salvage fund to provide for the funding of future asset retirement obligations. The following table presents changes in asset retirement obligations during the years ended December 31, 2018 and 2017: December 31, 2018 2017 (in thousands) Balance, beginning of year $ 1,401 $ 1,675 Liabilities incurred 2 2 Liabilities settled/relieved (54 ) (82 ) Accretion expense 25 30 Revision of estimates 72 (224 ) Balance, end of year $ 1,446 $ 1,401 During the year ended December 31, 2017, the Fund recorded credits to depletion expense totaling $0.1 million, which related to an adjustment to the asset retirement obligation for a fully depleted property. |
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 The Fund adopted the new revenue standard on January 1, 2018 using the modified retrospective method for all new contracts entered into after January 1, 2018 and all existing contracts for which revenues have not been recognized under the previous revenue guidance as of December 31, 2017. Although the Fund did not identify changes to its revenue recognition that resulted in a cumulative adjustment to retained earnings on January 1, 2018, the adoption of the accounting guidance resulted in enhanced disclosures related to revenue recognition policies, the Fund’s performance obligations and significant judgments used in applying the new revenue standard as described below. Revenue from Contracts with Customers Oil and gas revenues are recognized at the point when control of oil and natural gas is transferred to the customers. Natural gas liquid (“NGL”) sales are included within gas sales. The Fund’s oil and natural gas generally is sold to its customers at prevailing market prices based on an index in which the prices are published, adjusted for pricing differentials, quality of the oil and pipeline allowances. Oil and Gas Revenue Generally, the Fund sells oil and natural gas under two types of agreements, which are common in the oil and gas industry. In the first type of agreement, a netback agreement, the Fund receives a price, net of pricing differentials as well as transportation expense incurred by the customer, and the Fund records revenue at the wellhead at the net price received where control transfers to the customer. In the second type of agreement, the Fund delivers oil and natural gas to the customer at a contractually agreed-upon delivery point where the customer takes control. The Fund pays a third-party to transport the oil and natural gas and receives a specific market price from the customer net of pricing adjustments. The Fund records the transportation expense within operating expenses in the statements of operations. Under the Fund’s natural gas processing contracts, the Fund delivers natural gas to a midstream processing company at the inlet of the midstream processing company’s facility. The midstream processing company gathers and processes the natural gas and remits the proceeds to the Fund for the sale of NGLs. In this type of arrangement, the Fund evaluates whether it is the principal or agent in the transaction. The Fund concluded that it is the principal and the ultimate third-party purchaser is the customer; therefore, the Fund recognizes revenue on a gross basis, with transportation, gathering and processing fees recorded as an expense within operating expenses in the statements of operations. In certain instances, the Fund may elect to take its residue gas and NGLs in-kind at the tailgate of the midstream company’s processing plant and subsequently market such volumes. Through its marketing process, the Fund delivers the residue gas and NGLs to the ultimate third-party customer at a contractually agreed-upon delivery point and receives a specified market price from the customer. In this arrangement, the Fund recognizes revenue when control transfers to the customer at the delivery point based on the market price received from the customer. The transportation, gathering and processing fees are recorded as expense within operating expenses in the statements of operations. The Fund assesses the performance obligations promised in its oil and natural gas contracts based on each unit of oil and natural gas that will be transferred to its customer because each unit is capable of being distinct. The Fund satisfies its performance obligation when control transfers at a point in time when its customer is able to direct the use of, and obtain substantially all of the benefits from, the oil and natural gas delivered. Under each of the Fund’s oil and natural gas contracts, contract prices are variable and based on an index in which the prices are published, which fluctuate as a result of related industry variables, adjusted for pricing differentials, quality of the oil and pipeline allowances. The use of index-based pricing with predictable differentials reduces the level of uncertainty related to oil and gas prices. Additionally, any variable consideration is not constrained. Payments are received in the month following the oil and natural gas production month. Adjustments that occur after delivery, such as quality bank adjustments, are reflected in revenue in the month payments are received. Transaction Price Allocated to Remaining Performance Obligations Under the Fund’s oil and natural gas contracts, each unit of oil and natural gas represents a separate performance obligation; therefore, future volumes are wholly unsatisfied and the transaction price related to the remaining performance obligations is the variable index-based price attributable to each unit of oil and natural gas that is transferred to the customer. Contract Balances The Fund invoices customers once its performance obligations have been satisfied, at which point the payment is unconditional. Accordingly, the Fund’s oil and natural gas contracts do not give rise to contract assets or liabilities under the new revenue standard. The receivables related to the Fund’s oil and gas revenue are included within “Production receivable” on the balance sheets. Prior Period Performance Obligations The Fund records oil and gas revenue in the month production is delivered to its customers. However, settlement statements for residue gas and NGLs sales may not be received for 30 to 60 days after the date production is delivered. As a result, the Fund is required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the residue gas and NGLs. The Fund records the differences between its estimates and the actual amounts received in the month that the payment is received from the customer. The Fund has an estimation process for revenue and related accruals, and any identified difference between its revenue estimates and actual revenue historically have not been significant. There was no material revenue recognized in the current period from performance obligations satisfied in previous periods. Other Revenue from Affiliate Other revenue is generated from the Fund’s production handling, gathering and operating services agreement with an affiliated entity. The Fund simply earns a fee for its services and recognizes these fees as revenue at the time its performance obligations are satisfied as the control of oil and natural gas is never transferred to the Fund. |
Impairment of Long-Lived Assets | Impairment of Long-Lived Assets The Fund reviews the carrying value of its oil and gas properties for impairment whenever events and circumstances indicate that the recorded carrying value of its oil and gas properties may not be recoverable. Impairments are determined by comparing estimated future net undiscounted cash flows to the carrying value of the assets at the time of the review. If the carrying value exceeds the estimated future net undiscounted cash flows, the carrying value of the asset is written down to fair value, which is determined using a valuation technique that considers both market and income approaches and uses Level 3 inputs. The fair value determinations require considerable judgment and are sensitive to change. Different pricing assumptions, reserve estimates or discount rates could result in a different calculated impairment There were no impairments of oil and gas properties during the years ended December 31, 2018 and 2017. Fluctuations in oil and natural gas commodity prices may impact the fair value of the Fund’s oil and gas properties. If oil and natural gas commodity prices decline, even if only for a short period of time, it is possible that impairments of oil and gas properties will occur. |
Depletion and Amortization | Depletion and Amortization 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 2015 through 2017 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. |
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% to shareholders and 1% to the Manager until the shareholders have received total distributions equal to their capital contributions. After shareholders have received distributions equal to their capital contributions, 85% of available cash from dispositions will be distributed to shareholders and 15% to the Manager. |
Recent Accounting Pronouncements | Recent Accounting Pronouncements In August 2018, the Financial Accounting Standards Board (“FASB”) issued accounting guidance on fair value measurement, which adds, among other things, disclosure requirements for the range and weighted average of significant unobservable inputs used to develop Level 3 fair value measurements. This accounting guidance is effective for the Fund in the first quarter 2020 with early adoption permitted. The Fund does not expect this accounting guidance will have a material impact on its financial statements upon adoption. In February 2016, the FASB issued accounting guidance on leases as amended on January 2018 and July 2018, which requires an entity to recognize all lease assets and liabilities with a term greater than one year on the balance sheet, disclose key quantitative and qualitative information about leasing arrangements, and permits an entity not to evaluate existing or expired land easements that were not previously assessed under the existing lease guidance. The accounting guidance does not apply to leases of mineral rights to explore for or use of oil and natural gas. The accounting guidance is effective for the Fund beginning January 1, 2019 with early adoption permitted. Although the Fund, as a non-operator, does not enter into lease agreements to support its operations, the Fund completed its evaluation of existing contracts that may have a lease impact and embedded lease features to determine the contracts to which the new guidance applies. Based on this evaluation, the Fund determined its existing contracts did not meet the definition of leases under the new accounting guidance and therefore, did not qualify for lease accounting. In May 2014, the FASB issued accounting guidance on revenue recognition (“New Revenue Standard”), which provides for a single five-step model to be applied to all revenue contracts with customers. In July 2015, the FASB issued a deferral of the effective date of the New Revenue Standard to 2018, with early adoption permitted in 2017. In March 2016, the FASB issued accounting guidance, which clarifies the implementation guidance on principal versus agent considerations in the New Revenue Standard. In April 2016, the FASB issued guidance on identifying performance obligations and licensing and in May 2016, the FASB issued final amendments which provided narrow scope improvements and practical expedients related to the implementation of the New Revenue Standard. The New Revenue Standard may be applied either retrospectively or through the use of a modified-retrospective method. Under the New Revenue Standard, the revenue associated with the Fund’s existing contracts will be recognized in the period that control of the related commodity is transferred to the customer, which is generally consistent with the Fund’s previous revenue recognition model. The Fund adopted the New Revenue Standard using the modified retrospective method on January 1, 2018. See “Revenue Recognition” above for the required disclosures related to the impact of adopting this guidance and a discussion of the Fund’s updated policies related to revenue recognition for revenue from contracts with customers. |
Organization and Summary of S_3
Organization and Summary of Significant Accounting Policies (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Schedule of Available-For-Sale Securities | Gross Amortized Unrealized Fair Cost Gains Value (in thousands) Government National Mortgage Association security (GNMA July 2041) December 31, 2018 $ 36 $ 1 $ 37 December 31, 2017 $ 46 $ 2 $ 48 |
Schedule of Changes in Asset Retirement Obligations | December 31, 2018 2017 (in thousands) Balance, beginning of year $ 1,401 $ 1,675 Liabilities incurred 2 2 Liabilities settled/relieved (54 ) (82 ) Accretion expense 25 30 Revision of estimates 72 (224 ) Balance, end of year $ 1,446 $ 1,401 |
Information about Oil and Gas_2
Information about Oil and Gas Producing Activities (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Information About Oil And Gas Producing Activities [Abstract] | |
Schedule of Capitalized Costs Relating to Oil and Gas Producing Activities | Table I - Capitalized Costs Relating to Oil and Gas Producing Activities December 31, 2018 2017 (in thousands) Proved properties $ 20,663 $ 20,498 Accumulated depletion and amortization (9,405 ) (7,391 ) Oil and gas properties, net $ 11,258 $ 13,107 |
Schedule of Costs Incurred in Oil and Gas Property Acquisition, Exploration, and Development | Table II - Costs Incurred in Oil and Gas Property Acquisition, Exploration, and Development Year ended December 31, 2018 2017 (in thousands) Exploration costs $ 8 $ 15 Development costs 2,294 2,269 $ 2,302 $ 2,284 |
Schedule of Reserve Quantity Information | Table III - Reserve Quantity Information Oil and gas reserves of the Fund have been estimated by independent petroleum engineers, Netherland, Sewell & Associates, Inc. at December 31, 2018 and 2017. These reserve disclosures have been prepared in compliance with the Securities and Exchange Commission rules. Due to inherent uncertainties and the limited nature of recovery data, estimates of reserve information are subject to change as additional information becomes available. December 31, 2018 December 31, 2017 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 261.6 20.6 132.4 304.3 175.1 8.1 220.4 219.9 Extensions and discoveries (b) - - - - 62.1 4.8 29.7 71.8 Revisions of previous estimates (c) 156.7 14.5 92.4 186.6 100.2 15.8 (63.4 ) 105.6 Production (73.3 ) (8.0 ) (53.6 ) (90.2 ) (75.8 ) (8.1 ) (54.3 ) (93.0 ) Sale of minerals in place (d) (40.8 ) (2.9 ) (19.2 ) (46.9 ) - - - - End of year 304.2 24.2 152.0 353.8 261.6 20.6 132.4 304.3 Proved developed reserves: Beginning of year 199.5 15.8 102.7 232.5 156.9 8.1 210.0 199.9 End of year 304.2 24.2 152.0 353.8 199.5 15.8 102.7 232.5 Proved undeveloped reserves: Beginning of year 62.1 4.8 29.7 71.8 18.2 - 10.4 20.0 End of year - - - - 62.1 4.8 29.7 71.8 (a) BOE refers to barrel of oil equivalent Barrel of oil equivalent is based on six MCF of natural gas to one barrel of oil or one barrel of NGL, which reflects an energy content equivalency and not a price or revenue equivalency. (b) Extensions and discoveries as of December 31, 2017 were attributable to extensions for the Beta Project. (c) Revisions of previous estimates were attributable to well performance. (d) On August 10, 2018, the Fund sold a portion of the Fund’s working interest in the Beta Project to third parties. |
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 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, 2018 2017 (in thousands) Future cash inflows $ 20,066 $ 12,596 Future production costs (2,627 ) (2,867 ) Future development costs (2,631 ) (3,026 ) Future net cash flows 14,808 6,703 10% annual discount for estimated timing of cash flows (2,439 ) (970 ) Standardized measure of discounted future estimated net cash flows $ 12,369 $ 5,733 |
Schedule of Changes in the Standardized Measure for Discounted Cash Flows | Table V - 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, 2018 2017 (in thousands) Net change in sales and transfer prices and in production costs $ 4,466 $ 2,458 Sales and transfers of oil and gas produced during the period (4,376 ) (3,293 ) Net change due to extensions, discoveries, and improved recovery - 1,489 Net change due to purchases and sales of minerals in place (787 ) - Changes in estimated future development costs 395 37 Net change due to revisions in quantities estimates 7,686 2,888 Accretion of discount 573 250 Other (1,321 ) (595 ) Aggregate change in the standardized measure of discounted future net cash $ 6,636 $ 3,234 |
Organization and Summary of S_4
Organization and Summary of Significant Accounting Policies (Narrative) (Details) $ in Thousands | 12 Months Ended |
Dec. 31, 2018USD ($) | |
Organization and Summary of Significant Accounting Policies [Abstract] | |
Cash insured amount | $ 250 |
Credits to depletion | $ (100) |
Percentage of cash from operations allocated to shareholders | 85.00% |
Percentage of cash from operations allocated to Fund Manager | 15.00% |
Percentage of cash from dispositions allocated to shareholders | 99.00% |
Percentage of cash from dispositions allocated to Fund Manager | 1.00% |
Percentage of cash from dispositions allocated to shareholders after distributions have equaled capital contributions | 85.00% |
Percentage of cash from dispositions allocated to Fund Manager after distributions have equaled capital contributions | 15.00% |
Organization and Summary of S_5
Organization and Summary of Significant Accounting Policies (Schedule of Available-For-Sale Securities) (Details) - GNMA July 2041 [Member] - USD ($) $ in Thousands | Dec. 31, 2018 | Dec. 31, 2017 |
Amortized Cost | $ 36 | $ 46 |
Gross Unrealized Gains | 1 | 2 |
Fair Value | $ 37 | $ 48 |
Organization and Summary of S_6
Organization and Summary of Significant Accounting Policies (Schedule of Changes in Asset Retirement Obligations) (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | ||
Balance, beginning of year | $ 1,401 | $ 1,675 |
Liabilities incurred | 2 | 2 |
Liabilities settled/relieved | (54) | (82) |
Accretion expense | 25 | 30 |
Revision of estimates | 72 | (224) |
Balance, end of year | $ 1,446 | $ 1,401 |
Oil and Gas Properties (Details
Oil and Gas Properties (Details) - USD ($) $ in Thousands | 1 Months Ended | 3 Months Ended | 12 Months Ended | ||
Aug. 10, 2018 | Dec. 31, 2018 | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Cash received | $ 3,065 | ||||
Gain on sale | $ 34 | 865 | |||
Asset retirement obligation | $ 1,446 | $ 1,446 | $ 1,401 | $ 1,675 | |
Beta Project [Member] | |||||
Working interest percentage | 2.00% | ||||
Working interest acquired by buyers | 0.364% | ||||
Total purchase price | $ 3,300 | ||||
Cash received | 3,100 | ||||
Carrying value | 2,200 | ||||
Asset retirement obligation | $ 40 |
Related Parties (Details)
Related Parties (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Annual management fee percentage rate | 2.50% | |
Annual management fees paid to Fund Manager | $ 373 | $ 374 |
Percentage of total distributions allocated to Fund Manager | 15.00% | |
Distributions | $ (473) | |
Other revenue from affiliate | 50 | |
Other income | 40 | |
Manager [Member] | ||
Distributions | $ (71) |
Credit Agreement - Beta Proje_2
Credit Agreement - Beta Project Financing (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Credit agreement, maturity date | Dec. 31, 2022 | |
Interest rate | 8.75% | |
Overriding royalty interest | 10.81% | |
Gain on debt extinguishment | $ 1,313 | |
Non-cash gains associated with the change in fair value | 1,300 | |
Change in fair value | $ 16 | |
Overriding royalty interest fair value measurement input | 9.00% | |
Long-term debt fair value measurement input | 9.25% | |
Fair value of debt | $ 3,100 | |
Long-term borrowings | 3,200 | 7,200 |
Unamortized debt discounts and deferred financing costs | 15 | |
Amortization of financing costs | 1 | 100 |
Accrued interest | ||
Interest expense | 500 | $ 600 |
Principal repayments - 2019 | 900 | |
Principal repayments - 2020 | 1,100 | |
Principal repayments - 2021 | $ 1,200 | |
Prior to Amendment [Member] | ||
Interest rate | 8.00% | |
Monthly payment | $ 100 | |
Fair value of debt | $ 3,300 |
Commitments and Contingencies (
Commitments and Contingencies (Details) $ in Thousands | 12 Months Ended |
Dec. 31, 2018USD ($) | |
Commitments and Contingencies Disclosure [Abstract] | |
Commitments for the drilling and development of investment properties | $ 2,900 |
Commitments for asset retirement obligations included in estimated capital commitments | 1,900 |
Commitments for the drilling and development of investment properties expected to be incurred in the next 12 months | $ 300 |
Information about Oil and Gas_3
Information about Oil and Gas Producing Activities (Schedule of Capitalized Costs Relating to Oil and Gas Producing Activities) (Details) - USD ($) $ in Thousands | Dec. 31, 2018 | Dec. 31, 2017 |
Information About Oil And Gas Producing Activities [Abstract] | ||
Proved properties | $ 20,663 | $ 20,498 |
Accumulated depletion and amortization | (9,405) | (7,391) |
Total oil and gas properties, net | $ 11,258 | $ 13,107 |
Information about Oil and Gas_4
Information about Oil and Gas Producing Activities (Schedule of Costs Incurred in Oil and Gas Property Acquisition, Exploration, and Development) (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Information About Oil And Gas Producing Activities [Abstract] | ||
Exploration costs | $ 8 | $ 15 |
Development costs | 2,294 | 2,269 |
Total costs | $ 2,302 | $ 2,284 |
Information about Oil and Gas_5
Information about Oil and Gas Producing Activities (Schedule of Reserve Quantity Information) (Details) | 12 Months Ended | ||
Dec. 31, 2018bblMcf | Dec. 31, 2017bblMcf | ||
Oil (BBLS) [Member] | |||
Proved developed and undeveloped reserves: | |||
Beginning of year | 261,600 | 175,100 | |
Extensions and discoveries | [1] | 62,100 | |
Revisions of previous estimates | [2] | 156,700 | 100,200 |
Production | (73,300) | (75,800) | |
Sale of minerals in place | [3] | (40,800) | |
End of year | 304,200 | 261,600 | |
Proved developed reserves: | |||
Beginning of year | 199,500 | 156,900 | |
End of year | 304,200 | 199,500 | |
Proved undeveloped reserves: | |||
Beginning of year | 62,100 | 18,200 | |
End of year | 62,100 | ||
NGL (BBLS) [Member] | |||
Proved developed and undeveloped reserves: | |||
Beginning of year | 20,600 | 8,100 | |
Extensions and discoveries | [1] | 4,800 | |
Revisions of previous estimates | [2] | 14,500 | 15,800 |
Production | (8,000) | (8,100) | |
Sale of minerals in place | [3] | (2,900) | |
End of year | 24,200 | 20,600 | |
Proved developed reserves: | |||
Beginning of year | 15,800 | 8,100 | |
End of year | 24,200 | 15,800 | |
Proved undeveloped reserves: | |||
Beginning of year | 4,800 | ||
End of year | 4,800 | ||
Gas (MCF) [Member] | |||
Proved developed and undeveloped reserves: | |||
Beginning of year | Mcf | 132,400 | 220,400 | |
Extensions and discoveries | Mcf | [1] | 29,700 | |
Revisions of previous estimates | Mcf | [2] | 92,400 | (63,400) |
Production | Mcf | (53,600) | (54,300) | |
Sale of minerals in place | Mcf | [3] | (19,200) | |
End of year | Mcf | 152,000 | 132,400 | |
Proved developed reserves: | |||
Beginning of year | Mcf | 102,700 | 210,000 | |
End of year | Mcf | 152,000 | 102,700 | |
Proved undeveloped reserves: | |||
Beginning of year | Mcf | 29,700 | 10,400 | |
End of year | Mcf | 29,700 | ||
Total (BOE) [Member] | |||
Proved developed and undeveloped reserves: | |||
Beginning of year | [4] | 304,300 | 219,900 |
Extensions and discoveries | [1],[4] | 71,800 | |
Revisions of previous estimates | [2],[4] | 186,600 | 105,600 |
Production | [4] | (90,200) | (93,000) |
Sale of minerals in place | [3],[4] | (46,900) | |
End of year | [4] | 353,800 | 304,300 |
Proved developed reserves: | |||
Beginning of year | [4] | 232,500 | 199,900 |
End of year | [4] | 353,800 | 232,500 |
Proved undeveloped reserves: | |||
Beginning of year | [4] | 71,800 | 20,000 |
End of year | [4] | 71,800 | |
[1] | Extensions and discoveries as of December 31, 2017 were attributable to extensions for the Beta Project. | ||
[2] | Revisions of previous estimates were attributable to well performance. | ||
[3] | On August 10, 2018, the Fund sold a portion of the Fund's working interest in the Beta Project to third parties. | ||
[4] | 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 (Schedule of Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves) (Details) - USD ($) $ in Thousands | Dec. 31, 2018 | Dec. 31, 2017 |
Information About Oil And Gas Producing Activities [Abstract] | ||
Future cash inflows | $ 20,066 | $ 12,596 |
Future production costs | (2,627) | (2,867) |
Future development costs | (2,631) | (3,026) |
Future net cash flows | 14,808 | 6,703 |
10% annual discount for estimated timing of cash flows | (2,439) | (970) |
Standardized measure of discounted future net cash flows | $ 12,369 | $ 5,733 |
Information about Oil and Gas_7
Information about Oil and Gas Producing Activities (Schedule of Changes in the Standardized Measure for Discounted Cash Flows) (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Information About Oil And Gas Producing Activities [Abstract] | ||
Net change in sales and transfer prices and in production costs related to future production | $ 4,466 | $ 2,458 |
Sales and transfers of oil and gas produced during the period | (4,376) | (3,293) |
Net change due to extensions, discoveries, and improved recovery | 1,489 | |
Net change due to puchases and sales of minerals in place | (787) | |
Changes in estimated future development costs | 395 | 37 |
Net change due to revisions in quantities estimates | 7,686 | 2,888 |
Accretion of discount | 573 | 250 |
Other | (1,321) | (595) |
Aggregate change in the standardized measure of discounted future net cash flows for the year | $ 6,636 | $ 3,234 |