| Document and Entity Information - shares | 9 Months Ended | |
| Sep. 30, 2016 | Nov. 10, 2016 | |
| Document And Entity Information Abstract | ||
| Document Type | 10-Q | |
| Amendment Flag | false | |
| Document Period End Date | Sep. 30, 2016 | |
| Entity Registrant Name | RIDGEWOOD ENERGY Q FUND LLC | |
| Entity Central Index Key | 1,338,474 | |
| Current Fiscal Year End Date | --12-31 | |
| Document Fiscal Year Focus | 2,016 | |
| Document Fiscal Period Focus | Q3 | |
| Entity Filer Category | Smaller Reporting Company | |
| Entity Common Stock, Shares Outstanding | 830.5577 |
| UNAUDITED CONDENSED BALANCE SHEETS - USD ($) $ in Thousands | Sep. 30, 2016 | Dec. 31, 2015 |
| Current assets: | ||
| Cash and cash equivalents | $ 535 | $ 2,728 |
| Salvage fund | 474 | 373 |
| Production receivable | 128 | |
| Other current assets | 81 | |
| Total current assets | 1,218 | 3,101 |
| Salvage fund | 800 | |
| Oil and gas properties: | ||
| Proved properties | 19,163 | 17,130 |
| Less: accumulated depletion and amortization | (3,172) | (2,957) |
| Total oil and gas properties, net | 15,991 | 14,173 |
| Total assets | 18,009 | 17,274 |
| Current liabilities: | ||
| Due to operators | 334 | 153 |
| Accrued expenses | 280 | 86 |
| Current portion of long-term borrowings | 736 | 135 |
| Asset retirement obligations | 474 | 766 |
| Total current liabilities | 1,824 | 1,140 |
| Long-term borrowings | 2,814 | 2,705 |
| Asset retirement obligations | 1,110 | 818 |
| Total liabilities | 5,748 | 4,663 |
| Commitments and contingencies (Note 4) | ||
| Members' capital: | ||
| Distributions | (7,081) | (7,081) |
| Retained earnings | 4,575 | 4,579 |
| Manager's total | (2,506) | (2,502) |
| Capital contributions (1,335 shares authorized; 830.5577 issued and outstanding) | 123,037 | 123,037 |
| Syndication costs | (14,070) | (14,070) |
| Distributions | (40,120) | (40,120) |
| Accumulated deficit | (54,080) | (53,734) |
| Shareholders' total | 14,767 | 15,113 |
| Total members' capital | 12,261 | 12,611 |
| Total liabilities and members' capital | $ 18,009 | $ 17,274 |
| UNAUDITED CONDENSED BALANCE SHEETS (Parenthetical) - shares | Sep. 30, 2016 | Dec. 31, 2015 |
| Statement of Financial Position [Abstract] | ||
| Shares authorized | 1,335 | 1,335 |
| Shares issued | 830.5577 | 830.5577 |
| Shares outstanding | 830.5577 | 830.5577 |
| UNAUDITED CONDENSED STATEMENTS OF OPERATIONS - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
| Sep. 30, 2016 | Sep. 30, 2015 | Sep. 30, 2016 | Sep. 30, 2015 | |
| Revenue | ||||
| Oil and gas revenue | $ 232 | $ 132 | $ 350 | $ 461 |
| Expenses | ||||
| Depletion and amortization | 171 | 42 | 247 | 103 |
| Operating expenses | 129 | 130 | 194 | 358 |
| General and administrative expenses | 60 | 61 | 174 | 170 |
| Total expenses | 360 | 233 | 615 | 631 |
| Loss from operations | (128) | (101) | (265) | (170) |
| Interest (expense) income, net | (86) | 1 | (85) | 5 |
| Net loss | (214) | (100) | (350) | (165) |
| Manager Interest | ||||
| Net Income (loss) | 4 | (9) | (4) | (3) |
| Shareholder Interest | ||||
| Net loss | $ (218) | $ (91) | $ (346) | $ (162) |
| Net loss per share | $ (263) | $ (110) | $ (416) | $ (196) |
| UNAUDITED CONDENSED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands | 9 Months Ended | |
| Sep. 30, 2016 | Sep. 30, 2015 | |
| Cash flows from operating activities | ||
| Net loss | $ (350) | $ (165) |
| Adjustments to reconcile net loss to net cash (used in) provided by operating activities: | ||
| Depletion and amortization | 247 | 103 |
| Accretion expense | 55 | |
| Amortization of debt discounts and deferred financing costs | 20 | |
| Changes in assets and liabilities: | ||
| (Increase) decrease in production receivable | (148) | 120 |
| (Increase) decrease in other current assets | (81) | 24 |
| Increase (decrease) in due to operators | 16 | (96) |
| Increase in accrued expenses | 93 | 61 |
| Net cash (used in) provided by operating activities | (203) | 102 |
| Cash flows from investing activities | ||
| Capital expenditures for oil and gas properties | (1,739) | (2,186) |
| Investments in salvage fund | (901) | (4) |
| Net cash used in investing activities | (2,640) | (2,190) |
| Cash flows from financing activities | ||
| Long-term borrowings | 650 | |
| Distributions | (208) | |
| Net cash provided by (used in) financing activities | 650 | (208) |
| Net decrease in cash and cash equivalents | (2,193) | (2,296) |
| Cash and cash equivalents, beginning of period | 2,728 | 3,951 |
| Cash and cash equivalents, end of period | $ 535 | $ 1,655 |
| Organization and Summary of Significant Accounting Policies | 9 Months Ended |
| Sep. 30, 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 Q Fund, LLC (the "Fund"), a Delaware limited liability company, was formed on August 16, 2005 and operates pursuant to a limited liability company agreement (the “LLC Agreement") dated as of September 6, 2005 by and among Ridgewood Energy Corporation (the "Manager") and the shareholders of the Fund, 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. In addition, the Manager provides office space, equipment and facilities and other services necessary for Fund operations. The Manager also engages and manages the contractual relations with unaffiliated custodians, depositories, accountants, attorneys, broker-dealers, corporate fiduciaries, insurers, banks and others as required. See Notes 2, 3 and 4. Basis of Presentation These unaudited interim condensed financial statements have been prepared by the Fund’s management in accordance with accounting principles generally accepted in the United States of America (“GAAP”) and in the opinion of management, contain all adjustments (consisting of only normal recurring adjustments) necessary to present fairly the Fund’s financial position, results of operations and cash flows for the periods presented. Certain information and note disclosures normally included in annual financial statements prepared in accordance with GAAP have been omitted in these unaudited interim condensed financial statements. The results of operations, financial position, and cash flows for the periods presented herein are not necessarily indicative of future financial results. These unaudited interim condensed financial statements should be read in conjunction with the Fund’s December 31, 2015 financial statements and notes thereto included in the Fund’s Annual Report on Form 10-K filed with the Securities and Exchange Commission (“SEC”). The year-end condensed balance sheet data was derived from audited financial statements for the year ended December 31, 2015, but does not include all disclosures required by GAAP. Use of Estimates The preparation of financial statements in accordance with 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 consists 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. 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 September 30, 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 September 30, 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. 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 were $0.1 million as of September 30, 2016 and $0.2 million as of December 31, 2015 and 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”. Amortization expense of $40 thousand during the nine months ended September 30, 2016 and $20 thousand and $60 thousand during the three and nine months ended September 30, 2015, respectively, 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 three months ended September 30, 2016 of $20 thousand was expensed and is included on the statement of operations within “Interest (expense) income, net”. 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. Exploration, development and acquisition 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 September 30, 2016 and December 31, 2015, amounts recorded in due to operators totaling $0.3 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 of a property to be 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. As indicated above, the Fund maintains a salvage fund to provide for the funding of 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, when 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 declines 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 continue to 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 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 are effective for fiscal years, and interim periods within those years, beginning after December 15, 2015, with early adoption permitted. 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 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 2015, the FASB issued a deferral of the effective date of the guidance to 2018, with early adoption permitted in 2017. In May 2016, the FASB issued final amendments which provided narrow scope improvements and practical expedients related to the implementation of the guidance. The Fund is currently evaluating the impact of this guidance on its financial statements. |
| Related Parties | 9 Months Ended |
| Sep. 30, 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. During 2009, the Manager waived its management fee for the remaining life of the Fund. Upon the waiver of the management fee, the Fund began recording costs, totaling $20 thousand per quarter, representing reimbursements to the Manager, related to services provided by the Manager for accounting and investor relations. Such costs are included within general and administrative expenses. Management reimbursement costs during each of the three and nine months ended September 30, 2016 and 2015 were $20 thousand and $60 thousand, 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 three and nine months ended September 30, 2016 and during the three months ended September 30, 2015. Distributions paid to the Manager during the nine months ended September 30, 2015 were $32 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 & 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 (the “Agreement”) with Beta S&T in which Beta S&T will 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. Beta S&T is a pass-through entity such that it receives no benefit or compensation for the services provided under the Agreement or under any other agreements it enters into with regards to the oil and gas acquired from the Ridgewood Beta Funds. The Ridgewood Beta Funds indemnify, defend and hold harmless Beta S&T from and against all claims, liabilities, losses, causes of action, costs and expenses asserted against as a result of or arising from any act or omission, breach and claims for losses or damages arising out of Beta S&T’s dealing with third parties with respect to the transportation, processing or sale of oil and gas from the Beta Project. The revenues from the sale of oil and gas to third party purchasers are recorded as oil and gas revenue in the statements of operations and expenses are recorded as operating expenses in the statements of operations. 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 Financing | 9 Months Ended |
| Sep. 30, 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 $5.4 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. The Fund anticipates it will borrow approximately $5.4 million over the development period of the Beta Project. The Loan bears interest at 8% compounded annually and accrues only on Loan proceeds as they are drawn. Principal and interest will be repaid at 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, in no event later than December 31, 2020. The Loan may be prepaid by the Fund without premium or penalty. As of September 30, 2016 and December 31, 2015, the Fund had borrowings of $3.7 million and $3.0 million, respectively, under the Credit Agreement. The unamortized debt discounts and deferred financing costs of $0.1 million as of September 30, 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”). 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 Credit Agreement contains customary covenants, for which the Fund believes it was in compliance as of September 30, 2016 and December 31, 2015. |
| Commitments and Contingencies | 9 Months Ended |
| Sep. 30, 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 September 30, 2016, the Fund’s estimated capital commitments related to its oil and gas properties were $5.5 million (which include asset retirement obligations for the Fund’s projects of $2.2 million), of which $3.8 million is expected to be spent during the next twelve months. These expected capital commitments exceed available working capital and salvage fund by $4.8 million as of September 30, 2016. The Fund has entered into the Credit Agreement to provide capital for funding of the Beta Project. See Note 3. “Credit Agreement – Beta Project Financing” for additional information. Based upon its current cash position, its current reserve estimates and its current development plan of the Beta Project, the Fund expects cash flow from operations and borrowings 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. 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 September 30, 2016 and December 31, 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. 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. Claims made by other funds managed by the Manager can reduce or eliminate insurance for the Fund. |
| Organization and Summary of Significant Accounting Policies (Policy) | 9 Months Ended |
| Sep. 30, 2016 | |
| Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
| Basis of Presentation | Basis of Presentation These unaudited interim condensed financial statements have been prepared by the Fund’s management in accordance with accounting principles generally accepted in the United States of America (“GAAP”) and in the opinion of management, contain all adjustments (consisting of only normal recurring adjustments) necessary to present fairly the Fund’s financial position, results of operations and cash flows for the periods presented. Certain information and note disclosures normally included in annual financial statements prepared in accordance with GAAP have been omitted in these unaudited interim condensed financial statements. The results of operations, financial position, and cash flows for the periods presented herein are not necessarily indicative of future financial results. These unaudited interim condensed financial statements should be read in conjunction with the Fund’s December 31, 2015 financial statements and notes thereto included in the Fund’s Annual Report on Form 10-K filed with the Securities and Exchange Commission (“SEC”). The year-end condensed balance sheet data was derived from audited financial statements for the year ended December 31, 2015, but does not include all disclosures required by GAAP. |
| Use of Estimates | Use of Estimates The preparation of financial statements in accordance with 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 consists 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. |
| 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 September 30, 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 September 30, 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. 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 were $0.1 million as of September 30, 2016 and $0.2 million as of December 31, 2015 and 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”. Amortization expense of $40 thousand during the nine months ended September 30, 2016 and $20 thousand and $60 thousand during the three and nine months ended September 30, 2015, respectively, 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 three months ended September 30, 2016 of $20 thousand was expensed and is included on the statement of operations within “Interest (expense) income, net”. |
| 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. Exploration, development and acquisition 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 September 30, 2016 and December 31, 2015, amounts recorded in due to operators totaling $0.3 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 of a property to be 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. As indicated above, the Fund maintains a salvage fund to provide for the funding of 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, when 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 declines 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 continue to 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 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 are effective for fiscal years, and interim periods within those years, beginning after December 15, 2015, with early adoption permitted. The Fund adopted the accounting guidance in first quarter 2016, resulting in a one-time reclassification of $0.2 million of unamortized debt discounts and deferred financing costs from "Other assets" to "Long-term borrowings" on the balance sheet as of December 31, 2015. The adoption of these pronouncements did not impact the Fund’s results of operations or cash flows. In 2014, the FASB issued accounting guidance on revenue recognition, which provides for a single five-step model to be applied to all revenue contracts with customers. In 2015, the FASB issued a deferral of the effective date of the guidance to 2018, with early adoption permitted in 2017. In May 2016, the FASB issued final amendments which provided narrow scope improvements and practical expedients related to the implementation of the guidance. The Fund is currently evaluating the impact of this guidance on its financial statements. |
| Organization and Summary of Significant Accounting Policies (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | |||
| Sep. 30, 2016 | Sep. 30, 2015 | Sep. 30, 2016 | Sep. 30, 2015 | Dec. 31, 2015 | |
| Organization, Consolidation and Presentation of Financial Statements [Abstract] | |||||
| Maximum cash balance federally insured per financial institution | $ 250 | $ 250 | |||
| Unamortized debt discounts and deferred financing costs | 100 | 100 | $ 200 | ||
| Amortization of financing costs | 20 | $ 20 | 40 | $ 60 | |
| Value of capital expenditures for oil and gas properties owed to operators | $ 300 | $ 300 | $ 100 | ||
| Percentage of cash from operations allocated to shareholders | 85.00% | 85.00% | |||
| Percentage of cash from operations allocated to fund manager | 15.00% | 15.00% | |||
| Percentage of available cash from dispositions allocated to shareholders | 99.00% | 99.00% | |||
| Percentage of available cash from dispositions allocated to fund manager | 1.00% | 1.00% | |||
| Percentage of available cash from dispositions allocated to shareholders after distributions have equaled capital contributions | 85.00% | 85.00% | |||
| Percentage of available cash from dispositions allocated to fund manager after distributions have equaled capital contributions | 15.00% | 15.00% | |||
| Reclassification of unamortized debt discounts and deferred financing costs | $ 200 | ||||
| Related Parties (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | ||
| Sep. 30, 2016 | Sep. 30, 2015 | Sep. 30, 2016 | Sep. 30, 2015 | |
| Related Party Transaction [Line Items] | ||||
| Annual management fee percentage rate | 2.50% | 2.50% | ||
| Cost of services provided by Manager, quarterly amount | $ 20 | $ 20 | ||
| Cost of services provided by Manager | $ 20 | $ 20 | $ 60 | $ 60 |
| Percentage of total distributions allocated to Fund Manager | 15.00% | 15.00% | ||
| Fund Manager [Member] | ||||
| Related Party Transaction [Line Items] | ||||
| Distributions | $ 32 | |||
| Credit Agreement - Beta Project Financing (Details) - USD ($) $ in Thousands | 3 Months Ended | 9 Months Ended | 12 Months Ended |
| Sep. 30, 2016 | Sep. 30, 2016 | Dec. 31, 2015 | |
| Debt Disclosure [Abstract] | |||
| Credit agreement, maximum borrowing capacity | $ 5,400 | $ 5,400 | |
| Credit agreement, interest rate | 8.00% | 8.00% | |
| Credit agreement, contingency repayment rate, first seven months of production | 1.25% | 1.25% | |
| Credit agreement, contingency repayment rate, after first seven months of production | 4.50% | 4.50% | |
| Credit agreement, maturity date | Dec. 31, 2020 | ||
| Long-term borrowings | $ 3,700 | $ 3,700 | $ 3,000 |
| Deferred financing cost | 100 | 100 | 200 |
| Capitalized interest | $ 100 | $ 15 | |
| Interest expense | $ 100 |
| Commitments and Contingencies (Details) $ in Thousands | 9 Months Ended |
| Sep. 30, 2016USD ($) | |
| Commitments and Contingencies Disclosure [Abstract] | |
| Commitments for the drilling and development of investment properties | $ 5,500 |
| Commitments for asset retirement obligations included in estimated capital commitments | 2,200 |
| Commitments for the drilling and development of investment properties expected to be incurred in the next 12 months | 3,800 |
| Commitments for the drilling and development of investment properties in excess of working capital | $ 4,800 |
