Document and Entity Information
Document and Entity Information - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2016 | Mar. 02, 2017 | |
Document And Entity Information [Abstract] | ||
Document Type | 10-K | |
Amendment Flag | false | |
Document Period End Date | Dec. 31, 2016 | |
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 | 2,016 | |
Entity Filer Category | Smaller Reporting Company | |
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, 2016 | Dec. 31, 2015 |
Current assets: | ||
Cash and cash equivalents | $ 3,458 | $ 1,444 |
Salvage fund | 266 | 474 |
Production receivable | 324 | 7 |
Other current assets | 119 | |
Total current assets | 4,167 | 1,925 |
Salvage fund | 1,286 | 1,310 |
Oil and gas properties: | ||
Proved properties | 18,056 | 15,754 |
Less: accumulated depletion and amortization | (3,804) | (2,958) |
Total oil and gas properties, net | 14,252 | 12,796 |
Total assets | 19,705 | 16,031 |
Current liabilities: | ||
Due to operators | 462 | 153 |
Accrued expenses | 566 | 215 |
Current portion of long-term borrowings | 690 | |
Asset retirement obligations | 266 | 474 |
Total current liabilities | 1,984 | 842 |
Long-term borrowings | 6,453 | 2,656 |
Asset retirement obligations | 1,409 | 1,645 |
Other liabilities | 40 | 127 |
Total liabilities | 9,886 | 5,270 |
Commitments and contingencies (Note 4) | ||
Members' capital: | ||
Distributions | (5,058) | (5,058) |
Retained earnings | 5,117 | 5,097 |
Manager's total | 59 | 39 |
Capital contributions (250 shares authorized; 207.7026 issued and outstanding) | 41,143 | 41,143 |
Syndication costs | (4,804) | (4,804) |
Distributions | (35,427) | (35,427) |
Retained earnings | 8,845 | 9,807 |
Shareholders' total | 9,757 | 10,719 |
Accumulated other comprehensive income | 3 | 3 |
Total members' capital | 9,819 | 10,761 |
Total liabilities and members' capital | $ 19,705 | $ 16,031 |
BALANCE SHEETS (Parenthetical)
BALANCE SHEETS (Parenthetical) - shares | Dec. 31, 2016 | Dec. 31, 2015 |
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 LOSS - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Revenue | ||
Oil and gas revenue | $ 944 | $ 487 |
Expenses | ||
Depletion and amortization | 846 | 676 |
Management fees to affiliate (Note 2) | 349 | 380 |
Operating expenses | 296 | 377 |
General and administrative expenses | 152 | 142 |
Total expenses | 1,643 | 1,575 |
Loss from operations | (699) | (1,088) |
Interest (expense) income, net | (243) | 10 |
Net loss | (942) | (1,078) |
Other comprehensive loss | ||
Unrealized loss on marketable securities | (1) | |
Total comprehensive loss | (942) | (1,079) |
Manager Interest | ||
Net income (loss) | 20 | (55) |
Shareholder Interest | ||
Net loss | $ (962) | $ (1,023) |
Net loss per share | $ (4,631) | $ (4,928) |
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, 2014 | $ 107 | $ 11,818 | $ 4 | $ 11,929 | |
Balances, shares at Dec. 31, 2014 | 207.7026 | ||||
Distributions | (13) | (76) | (89) | ||
Net income (loss) | (55) | (1,023) | (1,078) | ||
Other comprehensive loss | (1) | (1) | |||
Balances at Dec. 31, 2015 | 39 | 10,719 | 3 | $ 10,761 | |
Balances, shares at Dec. 31, 2015 | 207.7026 | 207.7026 | |||
Net income (loss) | 20 | (962) | $ (942) | ||
Other comprehensive loss | |||||
Balances at Dec. 31, 2016 | $ 59 | $ 9,757 | $ 3 | $ 9,819 | |
Balances, shares at Dec. 31, 2016 | 207.7026 | 207.7026 |
STATEMENTS OF CASH FLOWS
STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Cash flows from operating activities | ||
Net loss | $ (942) | $ (1,078) |
Adjustments to reconcile net loss to net cash used in operating activities: | ||
Depletion and amortization | 846 | 676 |
Accretion expense | 50 | 83 |
Amortization of debt discounts and deferred financing costs | 61 | |
Changes in assets and liabilities: | ||
(Increase) decrease in production receivable | (337) | 91 |
(Increase) decrease in other current assets | (79) | 21 |
Decrease in due to operators | (124) | |
Increase in accrued expenses | 204 | 37 |
Settlement of asset retirement obligations | (208) | |
Net cash used in operating activities | (405) | (294) |
Cash flows from investing activities | ||
Capital expenditures for oil and gas properties | (2,178) | (4,313) |
Decrease (increase) in salvage fund | 232 | (5) |
Net cash used in investing activities | (1,946) | (4,318) |
Cash flows from financing activities | ||
Long-term borrowings | 4,365 | 1,100 |
Distributions | (89) | |
Net cash provided by financing activities | 4,365 | 1,011 |
Net increase (decrease) in cash and cash equivalents | 2,014 | (3,601) |
Cash and cash equivalents, beginning of year | 1,444 | 5,045 |
Cash and cash equivalents, end of year | $ 3,458 | $ 1,444 |
Organization and Summary of Sig
Organization and Summary of Significant Accounting Policies | 12 Months Ended |
Dec. 31, 2016 | |
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. With respect to project investments, the Manager locates potential projects, conducts due diligence, and negotiates and completes the transactions. The Manager performs, or arranges for the performance of, the management, advisory and administrative services required for Fund operations. Such services include, without limitation, the administration of shareholder accounts, shareholder relations and the preparation, review and dissemination of tax and other financial information and the management of the Fund’s investments in projects. In addition, the Manager provides office space, equipment and facilities and other services necessary for Fund operations. The Manager also engages and manages contractual relations with unaffiliated custodians, depositories, accountants, attorneys, corporate fiduciaries, insurers, banks and others as required. See Notes 2, 3 and 4. Use of Estimates The preparation of financial statements in accordance with accounting principles generally accepted in the United States of America (“GAAP”) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities as of the date of the financial statements and the reported amounts of revenue and expense during the reporting period. On an ongoing basis, the Manager reviews its estimates, including those related to the fair value of financial instruments, depletion and amortization, determination of proved reserves, impairment of long-lived assets and asset retirement obligations. Actual results may differ from those estimates. Fair Value Measurements The fair value measurement guidance provides a hierarchy that prioritizes and defines the types of inputs used to measure fair value. The fair value hierarchy gives the highest priority to Level 1 inputs, which consist of unadjusted quoted prices for identical instruments in active markets. Level 2 inputs consist of quoted prices for similar instruments. Level 3 inputs are unobservable inputs and include situations where there is little, if any, market activity for the instrument; hence, these inputs have the lowest priority. Mortgage-backed securities within the salvage fund are recorded based on Level 2 inputs, as such instruments trade in over-the-counter markets. 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, 2016, 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, 2016, the Fund’s bank balances were maintained in uninsured bank accounts at Wells Fargo Bank, N.A. Salvage Fund The Fund deposits in a separate interest-bearing account, or salvage fund, cash 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. At December 31, 2016 and 2015, 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, 2016 $ 64 $ 3 $ 67 December 31, 2015 $ 75 $ 3 $ 78 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 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. Debt Discounts and Deferred Financing Costs Debt discounts and deferred financing costs include lender fees and other costs of acquiring debt (see Note 3. “Credit Agreement – Beta Project Financing”) such as the conveyance of override royalty interests related to the Beta Project. These costs are deferred and amortized over the term of the debt period or until the redemption of the debt. Unamortized debt discounts and deferred financing costs are presented as a reduction of “Long-term borrowings” on the balance sheets (see Note 1. “Organization and Summary of Significant Accounting Policies - Recent Accounting Pronouncements”). During the period of asset construction, amortization expense, as a component of interest, is capitalized and included on the balance sheet within “Oil and gas properties” (see Note 3. “Credit Agreement – Beta Project Financing”). Oil and Gas Properties The Fund invests in oil and gas properties, which are operated by unaffiliated entities that are responsible for drilling, administering and producing activities pursuant to the terms of the applicable operating agreements with working interest owners. The Fund’s portion of exploration, drilling, operating and capital equipment expenditures is billed by operators. Acquisition, exploration and development costs are accounted for using the successful efforts method. Costs of acquiring unproved and proved oil and natural gas leasehold acreage, including lease bonuses, brokers’ fees and other related costs are capitalized. Costs of drilling and equipping productive wells and related production facilities are capitalized. The costs of exploratory wells are capitalized pending determination of whether proved reserves have been found. If proved commercial reserves are not found, exploratory well costs are expensed as dry-hole costs. At times, the Fund receives adjustments to certain wells from their respective operators upon review and audit of the wells’ costs. Interest costs related to the Credit Agreement (see Note 3. “Credit Agreement – Beta Project Financing”) are capitalized during the period of asset construction. Annual lease rentals and exploration expenses are expensed as incurred. All costs related to production activity, transportation expense and workover efforts are expensed as incurred. Once a well 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. As of December 31, 2016 and 2015, amounts recorded in due to operators totaling $0.4 million and $0.1 million, respectively, related to capital expenditures for oil and gas properties. Advances to Operators for Working Interests and Expenditures 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. At least bi-annually, or more frequently if an event occurs that would dictate a change in assumptions or estimates underlying the obligations, the Fund reassesses all of its asset retirement obligations to determine whether any revisions to the obligations are necessary. The following table presents changes in asset retirement obligations during the years ended December 31, 2016 and 2015. 2016 2015 (in thousands) Balance, beginning of year $ 2,119 $ 965 Liabilities incurred 2 404 Liabilities settled (208 ) - Accretion expense 50 83 Revision of estimates (288 ) 667 Balance, end of year $ 1,675 $ 2,119 As indicated above, the Fund maintains a salvage fund to provide for the funding of future asset retirement obligations. Syndication Costs Syndication costs are direct costs incurred by the Fund in connection with the offering of the Fund’s shares, including professional fees, selling expenses and administrative costs payable to the Manager, an affiliate of the Manager and unaffiliated broker-dealers, which are reflected on the Fund’s balance sheet as a reduction of shareholders’ capital. Revenue Recognition and Imbalances Oil and gas revenues are recognized when oil and gas is sold to a purchaser at a fixed or determinable price, delivery has occurred and title has transferred, and collectability of the revenue is reasonably assured. The Fund uses the sales method of accounting for gas production imbalances. The volumes of gas sold may differ from the volumes to which the Fund is entitled based on its interests in the properties. These differences create imbalances that are recognized as a liability only when the properties’ estimated remaining reserves net to the Fund will not be sufficient to enable the underproduced owner to recoup its entitled share through production. The Fund’s recorded liability, if any, would be reflected in other liabilities. No receivables are recorded for those wells where the Fund has taken less than its share of production. Impairment of Long-Lived Assets The Fund reviews the carrying value of its oil and gas properties annually and when management determines that events and circumstances indicate that the recorded carrying value of properties may not be recoverable. Impairments are determined by comparing estimated future net undiscounted cash flows to the carrying value at the time of the review. If the carrying value exceeds the estimated future net undiscounted cash flows, the carrying value of the asset is written down to fair value, which is determined using estimated future net discounted cash flows from the asset. The fair value determinations require considerable judgment and are sensitive to change. Different pricing assumptions, reserve estimates or discount rates could result in a different calculated impairment. Given the volatility of oil and natural gas prices, it is reasonably possible that the Fund’s estimate of discounted future net cash flows from proved oil and natural gas reserves could change in the near term. Significant and consistent fluctuations in oil and natural gas prices since fourth quarter 2014 have impacted the fair value of the Fund’s oil and gas properties. If oil and natural gas 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. During the year ended December 31, 2015, the Fund recorded $0.6 million of depletion expense related to adjustments to asset retirement obligations for fully depleted properties. 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 2013 through 2015 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 April 2015, the Financial Accounting Standards Board (“FASB”) issued accounting guidance related to the presentation of debt issuance costs on the balance sheet as a direct reduction from the carrying amount of the debt liability, consistent with debt discounts, rather than as an asset. Amortization of debt issuance costs will continue to be reported as interest expense. In August 2015, the FASB issued accounting guidance related to the presentation and subsequent measurement of debt issuance costs associated with line-of-credit arrangements which clarifies that companies may continue to present unamortized debt issuance costs associated with line of credit arrangements as an asset. These pronouncements became effective for fiscal years, and interim periods within those years, beginning after December 15, 2015. The Fund adopted the accounting guidance in first quarter 2016, resulting in a one-time reclassification of $0.2 million of unamortized debt discounts and deferred financing costs from "Other assets" to "Long-term borrowings" on the balance sheet as of December 31, 2015. The adoption of these pronouncements did not impact the Fund’s results of operations or cash flows. In May 2014, the FASB issued accounting guidance on revenue recognition, which provides for a single five-step model to be applied to all revenue contracts with customers. In July 2015, the FASB issued a deferral of the effective date of the guidance to 2018, with early adoption permitted in 2017. In March 2016, the FASB issued accounting guidance, which clarifies the implementation guidance on principal versus agent considerations in the new revenue recognition standard. In April 2016, the FASB issued guidance on identifying performance obligations and licensing and in May 2016, the FASB issued final amendments which provided narrow scope improvements and practical expedients related to the implementation of the guidance. The accounting guidance may be applied either retrospectively or through the use of a modified-retrospective method. Based on the Fund’s initial assessment of the accounting guidance, the Fund currently does not expect it will have a material impact on its results of operations or cash flows in the period after adoption. Under the accounting guidance, revenue is recognized as control transfers to the customer, as such the Fund expects the application of the accounting guidance to its existing contracts to be generally consistent with its current revenue recognition model. The Fund will continue the evaluation of the provisions of this accounting guidance, as well as new or emerging interpretations, as it relates to new contracts the Fund receives and in particular as it relates to disclosure requirements through the date of adoption, which is currently expected to be January 1, 2018. |
Related Parties
Related Parties | 12 Months Ended |
Dec. 31, 2016 | |
Related Party Transactions [Abstract] | |
Related Parties | 2. Related Parties Pursuant to the terms of the LLC Agreement, the Manager renders management, administrative and advisory services to the Fund. For such services, the Manager is entitled to an annual management fee, payable monthly, of 2.5% of total capital contributions, net of cumulative dry-hole and related well costs incurred by the Fund. In addition, pursuant to the terms of the LLC Agreement, the Manager is also permitted to waive the management fee at its own discretion. Such fee may be temporarily waived to accommodate the Fund’s short-term capital commitments. Management fees during the years ended December 31, 2016 and 2015 were $0.3 million and $0.4 million, respectively. The Manager is entitled to receive a 15% interest in cash distributions from operations made by the Fund. The Fund did not pay distributions during the year ended December 31, 2016. Distributions paid to the Manager during the year ended December 31, 2015 were $13 thousand. None of the amounts paid to the Manager have been derived as a result of arm’s length negotiations. In May 2015, Beta Sales and Transport, LLC (“Beta S&T”), a wholly-owned subsidiary of the Manager, was formed to act as an aggregator to and as an accommodation for the Fund and other funds managed by the Manager (the “Ridgewood Beta Funds”) to facilitate the transportation and sale of oil and gas produced from the Beta Project. On June 1, 2016, the Ridgewood Beta Funds entered into a master agreement with Beta S&T pursuant to which Beta S&T is obligated to purchase from Ridgewood Beta Funds all of their interests in oil and gas produced at 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 agreement it enters into with regard to the oil and gas purchased from the Ridgewood Beta Funds. Ridgewood Beta Funds 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 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. These revenues and operating expenses allocable to the Fund are based on the Fund’s working interest ownership in the Beta Project. At times, short-term payables and receivables, which do not bear interest, arise from transactions with affiliates in the ordinary course of business. The Fund has working interest ownership in certain projects to acquire and develop oil and natural gas projects with other entities that are likewise managed by the Manager. |
Credit Agreement - Beta Project
Credit Agreement - Beta Project Financing | 12 Months Ended |
Dec. 31, 2016 | |
Debt Disclosure [Abstract] | |
Credit Agreement - Beta Project Financing | 3. Credit Agreement – Beta Project Financing In November 2012, the Fund entered into a credit agreement (as amended on September 30, 2016, the “Credit Agreement”) with Rahr Energy Investments LLC, as Administrative Agent and Lender (and any other banks or financial institutions that may in the future become a party thereto, collectively “Lenders”) that provides for an aggregate loan commitment to the Fund of approximately $8.3 million (“Loan”), to provide capital toward the funding of the Fund’s share of development costs on the Beta Project. Except in cases of fraud and breach of certain representations, the Loan is non-recourse to the Fund’s other assets and secured solely by the Fund’s interests in the Beta Project. Certain other funds managed by Ridgewood (“Ridgewood Funds”, and when used with the Fund the “Ridgewood Participating Funds”) have also executed the Credit Agreement. Pursuant to the Credit Agreement, each Ridgewood Participating Fund has a separate loan commitment from the Lenders and amounts borrowed are not joint and several obligations. Each of the Ridgewood Participating Funds’ borrowings is secured solely by its separate interest in the Beta Project. Therefore, the Fund is liable for the repayment of its Loan and is not liable to the Lenders to repay any loan made to any other Ridgewood Funds. The Manager serves as the manager for each of the Ridgewood Participating Funds. As of December 31, 2016, in accordance with the terms of the Credit Agreement, there will be no additional borrowings available to the Ridgewood Participating Funds. As of December 31, 2016 and 2015, the Fund had borrowings of $7.3 million and $2.9 million, respectively, under the Credit Agreement. The Loan bears interest at 8% compounded annually. Principal and interest are repaid at the lesser of (i) a monthly rate of 1.25% of the Fund’s total principal outstanding as of July 31, 2016 for the first seven months beginning October 2016, and increases to a monthly rate of 4.5% thereafter until the Loan is repaid in full, and (ii) debt service amount as defined in the Credit Agreement, in no event later than December 31, 2020. The Loan may be prepaid by the Fund without premium or penalty. The unamortized debt discounts and deferred financing costs of $0.1 million as of December 31, 2016 and $0.2 million as of December 31, 2015 are presented as a reduction of “Long-term borrowings” on the balance sheets (see Note 1. “Organization and Summary of Significant Accounting Policies - Recent Accounting Pronouncements”). Amortization expense of $0.1 million during each of the years ended December 31, 2016 and 2015 were capitalized and included on the balance sheet within “Oil and gas properties”. As a result of the Beta Project’s commencement of production in third quarter 2016, amortization expense during the year ended December 31, 2016 of $0.1 million was expensed and is included on the statement of operations within “Interest (expense) income, net”. As of December 31, 2016 and 2015, interest costs of $0.4 million and $0.3 million, respectively, were capitalized and included on the balance sheet within “Oil and gas properties”. Such amounts were accrued on the balance sheet within “Accrued expenses” as of December 31, 2016 and “Accrued expenses” and “Other liabilities” as of December 31, 2015. As a result of the Beta Project’s commencement of production in third quarter 2016, interest costs during the year ended December 31, 2016 of $0.2 million were expensed and are included on the statement of operations within “Interest (expense) income, net”. Such amounts are accrued on the balance sheet within “Accrued expenses”. Interest payments on the Loan of $0.1 million as of December 31, 2016 related to capitalized interest costs. Such amounts are included within cash flows from investing activities on the statements of cash flows. As additional consideration to the Lenders, the Fund has agreed to convey an overriding royalty interest (“ORRI”) in its working interest in the Beta Project to the Lenders. The Fund’s share of the Lender’s aggregate ORRI is directly proportionate to its level of borrowing as a percentage of total borrowings of all Ridgewood Participating Funds. Such ORRI will not accrue or become payable to the Lenders until after the Loan is repaid in full. The Credit Agreement contains customary covenants, with which the Fund was in compliance as of December 31, 2016 and 2015. |
Commitments and Contingencies
Commitments and Contingencies | 12 Months Ended |
Dec. 31, 2016 | |
Commitments and Contingencies Disclosure [Abstract] | |
Commitments and Contingencies | 4. Commitments and Contingencies Capital Commitments The Fund has entered into multiple agreements for the acquisition, drilling and development of its oil and gas properties. The estimated capital expenditures associated with these agreements vary depending on the stage of development on a property-by-property basis. As of December 31, 2016, the Fund’s estimated capital commitments related to its oil and gas properties were $5.0 million (which include asset retirement obligations for the Fund’s projects of $2.4 million), of which $2.4 million is expected to be spent during the year ending December 31, 2017, which is primarily related to complete the final phase of the Beta Project. 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, as well as 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 capital 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 capital commitments if needed. Environmental Considerations The exploration for and development of oil and natural gas involves the extraction, production and transportation of materials which, under certain conditions, can be hazardous or cause environmental pollution problems. 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 and do not currently anticipate that compliance with federal, state and local environmental regulations will have a material adverse effect upon capital expenditures, results of operations or the competitive position of the Fund in the oil and gas industry. 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, 2016 and 2015, there were no known environmental contingencies that required adjustment to, or disclosure in, the Fund’s financial statements. During the past several years, the United States Congress, as well as certain regulatory agencies with jurisdiction over the Fund’s business, have considered or proposed legislation or regulation relating to the upstream oil and gas industry both onshore and offshore. If any such proposals were to be enacted or adopted they could potentially materially impact the Fund’s operations. 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. 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. BOEM Notice to Lessees on Supplemental Bonding On July 14, 2016, the Bureau of Ocean Energy Management (“BOEM”) issued a Notice to Lessees (“NTL”) that discontinued and materially replaced existing policies and procedures regarding financial security (i.e. supplemental bonding) for decommissioning obligations of lessees of federal oil and gas leases and owners of pipeline rights-of-way, rights-of use and easements on the Outer Continental Shelf (“Lessees”). Generally, the new NTL (i) ended the practice of excusing Lessees from providing such additional security where co-lessees had sufficient financial strength to meet such decommissioning obligations, (ii) established new criteria for determining financial strength and additional security requirements of such Lessees, (iii) provided acceptable forms of such additional security and (iv) replaced the waiver system with one of self-insurance. The new rule became effective as of September 12, 2016; however on January 6, 2017, the BOEM announced that it was suspending the implementation timeline for six months in certain circumstances. The Fund, as well as other industry participants, are working with the BOEM, its operators and working interest partners to determine and agree upon the correct level of decommissioning obligations to which they may be liable and the manner in which such obligations will be secured. The impact of the NTL, if enforced without change or amendment, may require the Fund to fully secure all of its potential abandonment liabilities to the BOEM 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 exploration for and development of oil and natural gas. Insurance coverage as is customary for entities engaged in similar operations is maintained, but losses may occur from uninsurable risks or amounts in excess of existing insurance coverage. The occurrence of an event that is not insured or not fully insured could have a material adverse impact upon earnings and financial position. Moreover, insurance is obtained as a package covering all of the funds managed by the Manager. Depending on the extent, nature and payment of claims made by the Fund or other funds managed by the Manager, yearly insurance coverage may be exhausted and become insufficient to cover a claim by the Fund in a given year. |
Information about Oil and Gas P
Information about Oil and Gas Producing Activities | 12 Months Ended |
Dec. 31, 2016 | |
Information About Oil And Gas Producing Activities [Abstract] | |
Information about Oil and Gas Producing Activities | Ridgewood Energy A-1 Fund, LLC Supplementary Financial Information Information about Oil and Gas Producing Activities – Unaudited In accordance with the FASB guidance on disclosures of oil and gas producing activities, this section provides supplementary information on oil and gas exploration and producing activities of the Fund. The Fund is engaged solely in oil and gas activities, all of which are located in the United States offshore waters of Louisiana in the Gulf of Mexico. Table I - Capitalized Costs Relating to Oil and Gas Producing Activities December 31, 2016 2015 (in thousands) Proved properties $ 18,056 $ 15,754 Total oil and gas properties 18,056 15,754 Accumulated depletion and amortization (3,804 ) (2,958 ) Oil and gas properties, net $ 14,252 $ 12,796 Table II - Costs Incurred in Oil and Gas Property Acquisition, Exploration, and Development Year ended December 31, 2016 2015 (in thousands) Exploration costs $ 20 $ 4 Development costs 2,266 4,983 $ 2,286 $ 4,987 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, 2016 and 2015. 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, 2016 December 31, 2015 United States Oil (BBLS) NGL (BBLS) Gas (MCF) Oil (BBLS) NGL (BBLS) Gas (MCF) Proved developed and undeveloped reserves: Beginning of year 291,911 3,964 311,221 306,783 11,395 371,865 Revisions of previous estimates (a) (96,926 ) 5,575 (70,683 ) (6,217 ) (6,212 ) (40,625 ) Production (19,885 ) (1,479 ) (20,178 ) (8,655 ) (1,219 ) (20,019 ) End of year 175,100 8,060 220,360 291,911 3,964 311,221 Proved developed reserves: Beginning of year 14,355 3,964 103,054 27,798 11,395 162,625 End of year 156,860 8,060 209,960 14,355 3,964 103,054 Proved undeveloped reserves: Beginning of year 277,556 - 208,167 278,985 - 209,240 End of year 18,240 - 10,400 277,556 - 208,167 (a) 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. December 31, 2016 2015 (in thousands) Future cash inflows $ 6,862 $ 14,095 Future production costs (2,132 ) (2,086 ) Future development costs (2,436 ) (7,029 ) Future net cash flows 2,294 4,980 10% annual discount for estimated timing of cash flows 205 (1,605 ) Standardized measure of discounted future estimated net cash flows $ 2,499 $ 3,375 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, 2016 2015 (in thousands) Net change in sales and transfer prices and in production costs $ (2,890 ) $ (9,551 ) Sales and transfers of oil and gas produced during the period (719 ) (183 ) Changes in estimated future development costs 4,593 1,825 Net change due to revisions in quantities estimates (2,417 ) (449 ) Accretion of discount 338 1,233 Other 219 (1,827 ) Aggregate change in the standardized measure of discounted future net cash $ (876 ) $ (8,952 ) 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 S12
Organization and Summary of Significant Accounting Policies (Policy) | 12 Months Ended |
Dec. 31, 2016 | |
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 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. Mortgage-backed securities within the salvage fund are recorded based on Level 2 inputs, as such instruments trade in over-the-counter markets. |
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, 2016, 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, 2016, the Fund’s bank balances were maintained in uninsured bank accounts at Wells Fargo Bank, N.A. |
Salvage Fund | Salvage Fund The Fund deposits in a separate interest-bearing account, or salvage fund, cash 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. At December 31, 2016 and 2015, 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, 2016 $ 64 $ 3 $ 67 December 31, 2015 $ 75 $ 3 $ 78 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 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. |
Debt Discounts and Deferred Financing Costs | Debt Discounts and Deferred Financing Costs Debt discounts and deferred financing costs include lender fees and other costs of acquiring debt (see Note 3. “Credit Agreement – Beta Project Financing”) such as the conveyance of override royalty interests related to the Beta Project. These costs are deferred and amortized over the term of the debt period or until the redemption of the debt. Unamortized debt discounts and deferred financing costs are presented as a reduction of “Long-term borrowings” on the balance sheets (see Note 1. “Organization and Summary of Significant Accounting Policies - Recent Accounting Pronouncements”). During the period of asset construction, amortization expense, as a component of interest, is capitalized and included on the balance sheet within “Oil and gas properties” (see Note 3. “Credit Agreement – Beta Project Financing”). |
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. Interest costs related to the Credit Agreement (see Note 3. “Credit Agreement – Beta Project Financing”) are capitalized during the period of asset construction. Annual lease rentals and exploration expenses are expensed as incurred. All costs related to production activity, transportation expense and workover efforts are expensed as incurred. Once a well 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. As of December 31, 2016 and 2015, amounts recorded in due to operators totaling $0.4 million and $0.1 million, respectively, related to capital expenditures for oil and gas properties. |
Advances to Operators for Working Interests and Expenditures | Advances to Operators for Working Interests and Expenditures 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. At least bi-annually, or more frequently if an event occurs that would dictate a change in assumptions or estimates underlying the obligations, the Fund reassesses all of its asset retirement obligations to determine whether any revisions to the obligations are necessary. The following table presents changes in asset retirement obligations during the years ended December 31, 2016 and 2015. 2016 2015 (in thousands) Balance, beginning of year $ 2,119 $ 965 Liabilities incurred 2 404 Liabilities settled (208 ) - Accretion expense 50 83 Revision of estimates (288 ) 667 Balance, end of year $ 1,675 $ 2,119 As indicated above, the Fund maintains a salvage fund to provide for the funding of future asset retirement obligations. |
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 and Imbalances | Revenue Recognition and Imbalances Oil and gas revenues are recognized when oil and gas is sold to a purchaser at a fixed or determinable price, delivery has occurred and title has transferred, and collectability of the revenue is reasonably assured. The Fund uses the sales method of accounting for gas production imbalances. The volumes of gas sold may differ from the volumes to which the Fund is entitled based on its interests in the properties. These differences create imbalances that are recognized as a liability only when the properties’ estimated remaining reserves net to the Fund will not be sufficient to enable the underproduced owner to recoup its entitled share through production. The Fund’s recorded liability, if any, would be reflected in other liabilities. No receivables are recorded for those wells where the Fund has taken less than its share of production. |
Impairment of Long-Lived Assets | Impairment of Long-Lived Assets The Fund reviews the carrying value of its oil and gas properties annually and when management determines that events and circumstances indicate that the recorded carrying value of properties may not be recoverable. Impairments are determined by comparing estimated future net undiscounted cash flows to the carrying value at the time of the review. If the carrying value exceeds the estimated future net undiscounted cash flows, the carrying value of the asset is written down to fair value, which is determined using estimated future net discounted cash flows from the asset. The fair value determinations require considerable judgment and are sensitive to change. Different pricing assumptions, reserve estimates or discount rates could result in a different calculated impairment. Given the volatility of oil and natural gas prices, it is reasonably possible that the Fund’s estimate of discounted future net cash flows from proved oil and natural gas reserves could change in the near term. Significant and consistent fluctuations in oil and natural gas prices since fourth quarter 2014 have impacted the fair value of the Fund’s oil and gas properties. If oil and natural gas 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. During the year ended December 31, 2015, the Fund recorded $0.6 million of depletion expense related to adjustments to asset retirement obligations for fully depleted properties. |
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 2013 through 2015 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 April 2015, the Financial Accounting Standards Board (“FASB”) issued accounting guidance related to the presentation of debt issuance costs on the balance sheet as a direct reduction from the carrying amount of the debt liability, consistent with debt discounts, rather than as an asset. Amortization of debt issuance costs will continue to be reported as interest expense. In August 2015, the FASB issued accounting guidance related to the presentation and subsequent measurement of debt issuance costs associated with line-of-credit arrangements which clarifies that companies may continue to present unamortized debt issuance costs associated with line of credit arrangements as an asset. These pronouncements became effective for fiscal years, and interim periods within those years, beginning after December 15, 2015. The Fund adopted the accounting guidance in first quarter 2016, resulting in a one-time reclassification of $0.2 million of unamortized debt discounts and deferred financing costs from "Other assets" to "Long-term borrowings" on the balance sheet as of December 31, 2015. The adoption of these pronouncements did not impact the Fund’s results of operations or cash flows. In May 2014, the FASB issued accounting guidance on revenue recognition, which provides for a single five-step model to be applied to all revenue contracts with customers. In July 2015, the FASB issued a deferral of the effective date of the guidance to 2018, with early adoption permitted in 2017. In March 2016, the FASB issued accounting guidance, which clarifies the implementation guidance on principal versus agent considerations in the new revenue recognition standard. In April 2016, the FASB issued guidance on identifying performance obligations and licensing and in May 2016, the FASB issued final amendments which provided narrow scope improvements and practical expedients related to the implementation of the guidance. The accounting guidance may be applied either retrospectively or through the use of a modified-retrospective method. Based on the Fund’s initial assessment of the accounting guidance, the Fund currently does not expect it will have a material impact on its results of operations or cash flows in the period after adoption. Under the accounting guidance, revenue is recognized as control transfers to the customer, as such the Fund expects the application of the accounting guidance to its existing contracts to be generally consistent with its current revenue recognition model. The Fund will continue the evaluation of the provisions of this accounting guidance, as well as new or emerging interpretations, as it relates to new contracts the Fund receives and in particular as it relates to disclosure requirements through the date of adoption, which is currently expected to be January 1, 2018. |
Organization and Summary of S13
Organization and Summary of Significant Accounting Policies (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
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, 2016 $ 64 $ 3 $ 67 December 31, 2015 $ 75 $ 3 $ 78 |
Schedule of Changes in Asset Retirement Obligations | 2016 2015 (in thousands) Balance, beginning of year $ 2,119 $ 965 Liabilities incurred 2 404 Liabilities settled (208 ) - Accretion expense 50 83 Revision of estimates (288 ) 667 Balance, end of year $ 1,675 $ 2,119 |
Information about Oil and Gas14
Information about Oil and Gas Producing Activities (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
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, 2016 2015 (in thousands) Proved properties $ 18,056 $ 15,754 Total oil and gas properties 18,056 15,754 Accumulated depletion and amortization (3,804 ) (2,958 ) Oil and gas properties, net $ 14,252 $ 12,796 |
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, 2016 2015 (in thousands) Exploration costs $ 20 $ 4 Development costs 2,266 4,983 $ 2,286 $ 4,987 |
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, 2016 and 2015. 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, 2016 December 31, 2015 United States Oil (BBLS) NGL (BBLS) Gas (MCF) Oil (BBLS) NGL (BBLS) Gas (MCF) Proved developed and undeveloped reserves: Beginning of year 291,911 3,964 311,221 306,783 11,395 371,865 Revisions of previous estimates (a) (96,926 ) 5,575 (70,683 ) (6,217 ) (6,212 ) (40,625 ) Production (19,885 ) (1,479 ) (20,178 ) (8,655 ) (1,219 ) (20,019 ) End of year 175,100 8,060 220,360 291,911 3,964 311,221 Proved developed reserves: Beginning of year 14,355 3,964 103,054 27,798 11,395 162,625 End of year 156,860 8,060 209,960 14,355 3,964 103,054 Proved undeveloped reserves: Beginning of year 277,556 - 208,167 278,985 - 209,240 End of year 18,240 - 10,400 277,556 - 208,167 (a) Revisions of previous estimates were attributable to well performance. |
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, 2016 2015 (in thousands) Future cash inflows $ 6,862 $ 14,095 Future production costs (2,132 ) (2,086 ) Future development costs (2,436 ) (7,029 ) Future net cash flows 2,294 4,980 10% annual discount for estimated timing of cash flows 205 (1,605 ) Standardized measure of discounted future estimated net cash flows $ 2,499 $ 3,375 |
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, 2016 2015 (in thousands) Net change in sales and transfer prices and in production costs $ (2,890 ) $ (9,551 ) Sales and transfers of oil and gas produced during the period (719 ) (183 ) Changes in estimated future development costs 4,593 1,825 Net change due to revisions in quantities estimates (2,417 ) (449 ) Accretion of discount 338 1,233 Other 219 (1,827 ) Aggregate change in the standardized measure of discounted future net cash $ (876 ) $ (8,952 ) |
Organization and Summary of S15
Organization and Summary of Significant Accounting Policies (Narrative) (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Organization and Summary of Significant Accounting Policies [Abstract] | ||
Maximum cash balance federally insured per financial institution | $ 250 | |
Value of capital expenditures for oil and gas properties owed to operators | $ 400 | $ 100 |
Depletion | $ 600 | |
Percentage of cash from operations allocated to shareholders | 85.00% | |
Percentage of cash from operations allocated to fund manager | 15.00% | |
Percentage of available cash from dispositions allocated to shareholders | 99.00% | |
Percentage of available cash from dispositions allocated to fund manager | 1.00% | |
Percentage of available cash from dispositions allocated to shareholders after distributions have equaled capital contributions | 85.00% | |
Percentage of available cash from dispositions allocated to fund manager after distributions have equaled capital contributions | 15.00% | |
Reclassification of unamortized debt discounts and deferred financing costs | $ 200 |
Organization and Summary of S16
Organization and Summary of Significant Accounting Policies (Schedule of Available-For-Sale Securities) (Details) - GNMA July 2041 [Member] - USD ($) $ in Thousands | Dec. 31, 2016 | Dec. 31, 2015 |
Amortized Cost | $ 64 | $ 75 |
Gross Unrealized Gains | 3 | 3 |
Fair Value | $ 67 | $ 78 |
Organization and Summary of S17
Organization and Summary of Significant Accounting Policies (Schedule of Changes in Asset Retirement Obligations) (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | ||
Balance, beginning of year | $ 2,119 | $ 965 |
Liabilities incurred | 2 | 404 |
Liabilities settled | (208) | |
Accretion expense | 50 | 83 |
Revision of estimates | (288) | 667 |
Balance, end of year | $ 1,675 | $ 2,119 |
Related Parties (Details)
Related Parties (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Related Party Transaction [Line Items] | ||
Annual management fee percentage rate | 2.50% | |
Annual management fees paid to Fund Manager | $ 349 | $ 380 |
Percentage of total distributions allocated to Fund Manager | 15.00% | |
Distributions | (89) | |
Manager [Member] | ||
Related Party Transaction [Line Items] | ||
Distributions | $ (13) |
Credit Agreement - Beta Proje19
Credit Agreement - Beta Project Financing (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Debt Disclosure [Abstract] | ||
Credit agreement, maximum borrowing capacity | $ 8,300 | |
Long-term borrowings | $ 7,300 | $ 2,900 |
Credit agreement, interest rate | 8.00% | |
Credit agreement, contingency repayment rate, first seven months of production | 1.25% | |
Credit agreement, contingency repayment rate, after first seven months of production | 4.50% | |
Credit agreement, maturity date | Dec. 31, 2020 | |
Unamortized debt discounts and deferred financing costs | $ 100 | 200 |
Accumulated amortization | 100 | 100 |
Amortization of financing costs | 100 | |
Capitalized interest | 400 | $ 300 |
Interest expense | 200 | |
Interest paid | $ 100 |
Commitments and Contingencies (
Commitments and Contingencies (Details) $ in Thousands | 12 Months Ended |
Dec. 31, 2016USD ($) | |
Commitments and Contingencies Disclosure [Abstract] | |
Commitments for the drilling and development of investment properties | $ 5,000 |
Commitments for asset retirement obligations included in estimated capital commitments | 2,400 |
Commitments for the drilling and development of investment properties expected to be incurred in the next 12 months | $ 2,400 |
Information about Oil and Gas21
Information about Oil and Gas Producing Activities (Schedule of Capitalized Costs Relating to Oil and Gas Producing Activities) (Details) - USD ($) $ in Thousands | Dec. 31, 2016 | Dec. 31, 2015 |
Information About Oil And Gas Producing Activities [Abstract] | ||
Proved properties | $ 18,056 | $ 15,754 |
Total oil and gas properties | 18,056 | 15,754 |
Accumulated depletion and amortization | (3,804) | (2,958) |
Total oil and gas properties, net | $ 14,252 | $ 12,796 |
Information about Oil and Gas22
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, 2016 | Dec. 31, 2015 | |
Information About Oil And Gas Producing Activities [Abstract] | ||
Exploration costs | $ 20 | $ 4 |
Development costs | 2,266 | 4,983 |
Total costs | $ 2,286 | $ 4,987 |
Information about Oil and Gas23
Information about Oil and Gas Producing Activities (Schedule of Reserve Quantity Information) (Details) | 12 Months Ended | ||
Dec. 31, 2016bblMcf | Dec. 31, 2015bblMcf | ||
Oil (BBLS) [Member] | |||
Proved developed and undeveloped reserves: | |||
Beginning of year | 291,911 | 306,783 | |
Revisions of previous estimates | [1] | (96,926) | (6,217) |
Production | (19,885) | (8,655) | |
End of year | 175,100 | 291,911 | |
Proved developed reserves: | |||
Beginning of year | 14,355 | 27,798 | |
End of year | 156,860 | 14,355 | |
Proved undeveloped reserves: | |||
Beginning of year | 277,556 | 278,985 | |
End of year | 18,240 | 277,556 | |
NGL (BBLS) [Member] | |||
Proved developed and undeveloped reserves: | |||
Beginning of year | 3,964 | 11,395 | |
Revisions of previous estimates | [1] | 5,575 | (6,212) |
Production | (1,479) | (1,219) | |
End of year | 8,060 | 3,964 | |
Proved developed reserves: | |||
Beginning of year | 3,964 | 11,395 | |
End of year | 8,060 | 3,964 | |
Proved undeveloped reserves: | |||
Beginning of year | |||
End of year | |||
Gas (MCF) [Member] | |||
Proved developed and undeveloped reserves: | |||
Beginning of year | Mcf | 311,221 | 371,865 | |
Revisions of previous estimates | Mcf | [1] | (70,683) | (40,625) |
Production | Mcf | (20,178) | (20,019) | |
End of year | Mcf | 220,360 | 311,221 | |
Proved developed reserves: | |||
Beginning of year | Mcf | 103,054 | 162,625 | |
End of year | Mcf | 209,960 | 103,054 | |
Proved undeveloped reserves: | |||
Beginning of year | Mcf | 208,167 | 209,240 | |
End of year | Mcf | 10,400 | 208,167 | |
[1] | Revisions of previous estimates were attributable to well performance. |
Information about Oil and Gas24
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, 2016 | Dec. 31, 2015 |
Information About Oil And Gas Producing Activities [Abstract] | ||
Future cash inflows | $ 6,862 | $ 14,095 |
Future production costs | (2,132) | (2,086) |
Future development costs | (2,436) | (7,029) |
Future net cash flows | 2,294 | 4,980 |
10% annual discount for estimated timing of cash flows | 205 | (1,605) |
Standardized measure of discounted future net cash flows | $ 2,499 | $ 3,375 |
Information about Oil and Gas25
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, 2016 | Dec. 31, 2015 | |
Information About Oil And Gas Producing Activities [Abstract] | ||
Net change in sales and transfer prices and in production costs related to future production | $ (2,890) | $ (9,551) |
Sales and transfers of oil and gas produced during the period | (719) | (183) |
Changes in estimated future development costs | 4,593 | 1,825 |
Net change due to revisions in quantities estimates | (2,417) | (449) |
Accretion of discount | 338 | 1,233 |
Other | 219 | (1,827) |
Aggregate change in the standardized measure of discounted future net cash flows for the year | $ (876) | $ (8,952) |