Ridgewood Energy Q Fund (RDWQS) 10-K 9 Mar 18 2017 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Mar. 09, 2018
Document And Entity Information [Abstract]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2017
Entity Registrant Name	RIDGEWOOD ENERGY Q FUND LLC
Entity Central Index Key	1,338,474
Current Fiscal Year End Date	--12-31
Document Fiscal Period Focus	FY
Document Fiscal Year Focus	2,017
Entity Filer Category	Smaller Reporting Company
Entity Units Outstanding		830.5577
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, 2017	Dec. 31, 2016
Current assets:
Cash and cash equivalents	$ 1,026	$ 1,780
Salvage fund	588	557
Production receivable	532	353
Other current assets	60	131
Total current assets	2,206	2,821
Salvage fund	435	481
Oil and gas properties:
Proved properties	22,433	19,669
Less: accumulated depletion and amortization	(7,921)	(3,897)
Total oil and gas properties, net	14,512	15,772
Total assets	17,153	19,074
Current liabilities:
Due to operators	682	525
Accrued expenses	54	267
Current portion of long-term borrowings	1,620	1,033
Asset retirement obligations	588	557
Other current liabilities	45
Total current liabilities	2,989	2,382
Long-term borrowings	3,218	4,302
Asset retirement obligations	236	549
Other liabilities		45
Total liabilities	6,443	7,278
Commitments and contingencies (Note 4)
Members' capital:
Distributions	(7,081)	(7,081)
Retained earnings	5,093	4,631
Manager's total	(1,988)	(2,450)
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	(56,149)	(54,601)
Shareholders' total	12,698	14,246
Total members' capital	10,710	11,796
Total liabilities and members' capital	$ 17,153	$ 19,074

BALANCE SHEETS (Parenthetical)

BALANCE SHEETS (Parenthetical) - shares	Dec. 31, 2017	Dec. 31, 2016
Statement of Financial Position [Abstract]
Shares authorized	1,335	1,335
Shares issued	830.5577	830.5577
Shares outstanding	830.5577	830.5577

STATEMENTS OF OPERATIONS

STATEMENTS OF OPERATIONS - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Revenue
Oil and gas revenue	$ 4,290	$ 977
Expenses
Depletion and amortization	3,882	973
Operating expenses	702	395
General and administrative expenses	260	231
Total expenses	4,844	1,599
Loss from operations	(554)	(622)
Interest expense, net	(532)	(193)
Net loss	(1,086)	(815)
Manager Interest
Net income	462	52
Shareholder Interest
Net loss	$ (1,548)	$ (867)
Net loss per share	$ (1,863)	$ (1,044)

STATEMENTS OF CHANGES IN PARTNE

STATEMENTS OF CHANGES IN PARTNERS CAPITAL - USD ($) $ in Thousands	# of Shares [Member]	Manager [Member]	Shareholders [Member]	Total
Balances at Dec. 31, 2015		$ (2,502)	$ 15,113	$ 12,611
Balances, shares at Dec. 31, 2015	830.5577
Net income (loss)		52	(867)	(815)
Balances at Dec. 31, 2016		(2,450)	14,246	$ 11,796
Balances, shares at Dec. 31, 2016	830.5577			830.5577
Net income (loss)		462	(1,548)	$ (1,086)
Balances at Dec. 31, 2017		$ (1,988)	$ 12,698	$ 10,710
Balances, shares at Dec. 31, 2017	830.5577			830.5577

STATEMENTS OF CASH FLOWS

STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Cash flows from operating activities
Net loss	$ (1,086)	$ (815)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Depletion and amortization	3,882	973
Accretion expense	31	54
Amortization of debt discounts and deferred financing costs	80	40
Changes in assets and liabilities:
Increase in production receivable	(179)	(373)
Decrease (increase) in other current assets	71	(86)
Increase in due to operators	62	25
(Decrease) increase in accrued expenses	(170)	173
Settlement of asset retirement obligations	(96)	(208)
Net cash provided by (used in) operating activities	2,595	(217)
Cash flows from investing activities
Capital expenditures for oil and gas properties	(2,787)	(2,481)
Decrease (increase) in salvage fund	15	(665)
Net cash used in investing activities	(2,772)	(3,146)
Cash flows from financing activities
Long-term borrowings		2,415
Repayment of long-term borrowings	(577)
Net cash (used in) provided by financing activities	(577)	2,415
Net decrease in cash and cash equivalents	(754)	(948)
Cash and cash equivalents, beginning of year	1,780	2,728
Cash and cash equivalents, end of year	1,026	1,780
Supplemental disclosure of cash flow information
Cash paid for interest, net of amounts capitalized	610
Supplemental disclosure of non-cash investing activities
Due to operators for accrued capital expenditures for oil and gas properties	$ 563	$ 468

Organization and Summary of Sig

Organization and Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2017
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. 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, 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. 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, 2017, 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, 2017, the Fund’s bank balances were maintained in uninsured bank accounts at Wells Fargo Bank, N.A. Salvage Fund The Fund deposits cash in a separate interest-bearing account, or salvage fund, to provide for the dismantling and removal of production platforms and facilities and plugging and abandoning its wells at the end of their useful lives in accordance with applicable federal and state laws and regulations. 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 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. 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” for additional information. 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 property has been determined to be fully depleted or upon the sale, retirement or abandonment of a property, the cost and related accumulated depletion and amortization, if any, is eliminated from the property accounts, and the resultant gain or loss is recognized. The Fund may be required to advance its share of the estimated succeeding month’s expenditures to the operator for its oil and gas properties. As the costs are incurred, the advances are reclassified to proved properties. Asset Retirement Obligations For oil and gas properties, there are obligations to perform removal and remediation activities when the properties are retired. Upon the determination that a property is either proved or dry, a retirement obligation is incurred. The Fund recognizes the fair value of a liability for an asset retirement obligation in the period incurred. Plug and abandonment costs associated with unsuccessful projects are expensed as dry-hole costs. Bi-annually, or more frequently if an event occurs that would dictate a change in assumptions or estimates underlying the obligations, the Fund reassesses its asset retirement obligations to determine whether any revisions to the obligations are necessary. The following table presents changes in asset retirement obligations during the years ended December 31, 2017 and 2016. 2017 2016 (in thousands) Balance, beginning of year $ 1,106 $ 1,584 Liabilities incurred 2 2 Liabilities settled (96 ) (208 ) Accretion expense 31 54 Revision of estimates (219 ) (326 ) Balance, end of year $ 824 $ 1,106 During the year ended December 31, 2017, the Fund recorded credits to depletion expense totaling $0.1 million, which related to an adjustment to the asset retirement obligation for a fully depleted property. 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 future net discounted cash flows from proved oil and natural gas reserves could change in the near term. Fluctuations in oil and natural gas prices may impact 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. 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 2014 through 2016 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 May 2014, the Financial Accounting Standards Board (“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. Under the new accounting guidance, the revenue associated with the Fund’s existing contracts will be recognized in the period that control of the related commodity is transferred to the customer, which is generally consistent with its current revenue recognition model. The Fund adopted the new accounting guidance using the modified retrospective method on January 1, 2018. Although the Fund did not identify changes to its revenue recognition that resulted in a material cumulative adjustment to retained earnings on January 1, 2018, the adoption of the accounting guidance will result in enhanced disclosures related to revenue recognition policies, the Fund’s performance obligations and significant judgments used in applying the new revenue recognition accounting guidance.

Related Parties

Related Parties	12 Months Ended
	Dec. 31, 2017
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 years ended December 31, 2017 and 2016 were $80 thousand. The Manager is also entitled to receive a 15% interest in cash distributions from operations made by the Fund. The Fund did not pay distributions during the years ended December 31, 2017 and 2016. Beta Sales and Transport, LLC (“Beta S&T”), a wholly-owned subsidiary of the Manager, acts as an aggregator to and as an accommodation for the Fund and other funds managed by the Manager to facilitate the transportation and sale of oil and natural gas produced from the Beta Project. In 2016, the Fund entered into a master agreement with Beta S&T pursuant to which Beta S&T is obligated to purchase from the Fund all of its interests in oil and natural gas produced from the Beta Project and sell such volumes to unrelated third party purchasers. Pursuant to the master agreement, Beta S&T is a pass-through entity such that it receives no benefit or compensation for the services provided under the master agreement or under any other agreements it enters into with regard to the oil and natural gas purchased from the Fund. The Fund and other funds managed by the Manager have agreed to indemnify, defend and hold harmless Beta S&T from and against all claims, liabilities, losses, causes of action, costs and expenses asserted against it as a result of or arising from any act or omission, breach and claims for losses or damages arising out of its dealing with third parties with respect to the transportation, processing or sale of oil and natural gas from the Beta Project. The revenues and expenses from the sale of oil and natural gas to third party purchasers are recorded as oil and gas revenue and operating expenses in the Fund’s statements of operations, and are allocable to the Fund based on the Fund’s working interest ownership in the Beta Project. 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 develop oil and gas projects, which are also owned by other entities that are likewise managed by the Manager.

Credit Agreement - Beta Project

Credit Agreement - Beta Project Financing	12 Months Ended
	Dec. 31, 2017
Debt Disclosure [Abstract]
Credit Agreement - Beta Project Financing	In November 2012, the Fund entered into a credit agreement (as amended on September 30, 2016 and September 15, 2017, 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 provided 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. Certain other funds managed by the Manager (“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. 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. 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. As of December 31, 2016, in accordance with the terms of the Credit Agreement, there were no additional borrowings available to the Ridgewood Participating Funds. As of December 31, 2017 and 2016, the Fund had borrowings of $4.8 million and $5.4 million, respectively, under the Credit Agreement. The Loan bears interest at 8% compounded annually. Principal and interest are repaid at the lesser of the monthly fixed amount of approximately $0.1 million or the Debt Service Cap 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. On September 15, 2017, the Ridgewood Participating Funds entered into the second amendment to the Credit Agreement, which principally amended the definition of the net revenues, which is the basis for the calculation of the Debt Service Cap amount. There were no unamortized debt discounts and deferred financing costs as of December 31, 2017. Unamortized debt discounts and deferred financing costs of $0.1 million as of December 31, 2016 are presented as a reduction of “Long-term borrowings” on the balance sheet. Amortization expense during the years ended December 31, 2017 and 2016 of $0.1 million and $40 thousand, respectively, were expensed and included on the statements of operations within “Interest expense, net”. Amortization expense during the year ended December 31, 2016 of $40 thousand was capitalized and included on the balance sheet within “Oil and gas properties”. As of December 31, 2017, there were no accrued interest costs outstanding. As of December 31, 2016, accrued interest costs of $0.2 million, were included on the balance sheets within “Accrued expenses”. Interest costs incurred during the years ended December 31, 2017 and 2016 of $0.5 million and $0.2 million, respectively, were expensed and included on the statements of operations within “Interest expense, net”. Interest costs incurred during the year ended December 31, 2016 of $0.1 million were capitalized and included on the balance sheet within “Oil and gas properties”. During the years ended December 31, 2017 and 2016, the Fund made payments on the loan of $43 thousand and $0.1 million, respectively, which related to capitalized interest costs. 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 Lenders’ 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 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, 2017 and 2016.

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2017
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	4. Commitments and Contingencies Capital Commitments As of December 31, 2017, the Fund’s estimated capital commitments related to its oil and gas properties were $3.0 million (which include asset retirement obligations for the Fund’s projects of $1.6 million), of which $1.2 million is expected to be spent during the year ending December 31, 2018, related to the continued development of the Beta Project and the settlement of asset retirement obligations for certain of the Fund’s projects. As a result of continued development of the Beta Project, the Fund has experienced negative cash flows Based upon its current cash position and its current reserve estimates, the Fund expects cash flow from operations to be sufficient to cover its commitments, borrowing repayments and ongoing operations. Reserve estimates are projections based on engineering data that cannot be measured with precision, require substantial judgment, and are subject to frequent revision. However, if cash flow from operations is not sufficient to meet the Fund’s commitments, the Manager will provide short-term financing to accommodate the Fund’s short-term commitments if needed. Environmental and Governmental Regulations Many aspects of the oil and gas industry are subject to federal, state and local environmental laws and regulations. The Manager and operators of the Fund’s properties are continually taking action they believe appropriate to satisfy applicable federal, state and local environmental regulations. However, due to the significant public and governmental interest in environmental matters related to those activities, the Manager cannot predict the effects of possible future legislation, rule changes, or governmental or private claims. As of December 31, 2017 and 2016, there were no known environmental contingencies that required adjustment to, or disclosure in, the Fund’s financial statements. Oil and gas industry legislation and administrative regulations are periodically changed for a variety of political, economic, and other reasons. Any such future laws and regulations could result in increased compliance costs or additional operating restrictions, which could have a material adverse effect on the Fund’s operating results and cash flows. It is not possible at this time to predict whether such legislation or regulation, if proposed, will be adopted as initially written, if at all, or how legislation or new regulation that may be adopted would impact the Fund’s business. BOEM Notice to Lessees on Supplemental Bonding On July 14, 2016, the Bureau of Ocean Energy Management (“BOEM”) issued a Notice to Lessees (“NTL”) that discontinued and materially replaced existing policies and procedures regarding financial security (i.e. supplemental bonding) for decommissioning obligations of lessees of federal oil and gas leases and owners of pipeline rights-of-way, rights-of use and easements on the Outer Continental Shelf (“Lessees”). Generally, the 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. On June 22, 2017, the BOEM announced that the implementation timeline extension will remain in effect pending the completion of its review of the new NTL. 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’s satisfaction using one or more of the enumerated methods for doing so. Potentially this could increase costs to the Fund if the Fund is required to obtain additional supplemental bonding, fund escrow accounts or obtain letters of credit. Insurance Coverage The Fund is subject to all risks inherent in the oil and natural gas business. Insurance coverage as is customary for entities engaged in similar operations is maintained, but losses may occur from uninsurable risks or amounts in excess of existing insurance coverage. The occurrence of an event that is not insured or not fully insured could have a material adverse impact upon earnings and financial position. Moreover, insurance is obtained as a package covering all of the 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, 2017
Information About Oil And Gas Producing Activities [Abstract]
Information about Oil and Gas Producing Activities	Ridgewood Energy Q Fund, LLC Supplementary Financial Information Information about Oil and Gas Producing Activities - Unaudited In accordance with the FASB guidance on disclosures of oil and gas producing activities, this section provides supplementary information on oil and gas exploration and producing activities of the Fund. The Fund is engaged solely in oil and gas activities, all of which are located in the United States offshore waters of the Gulf of Mexico. Table I - Capitalized Costs Relating to Oil and Gas Producing Activities December 31, 2017 2016 (in thousands) Proved properties $ 22,433 $ 19,669 Accumulated depletion and amortization (7,921 ) (3,897 ) Oil and gas properties, net $ 14,512 $ 15,772 Table II - Costs Incurred in Oil and Gas Property Acquisition, Exploration, and Development Year ended December 31, 2017 2016 (in thousands) Exploration costs $ 16 $ 22 Development costs 2,589 2,564 $ 2,605 $ 2,586 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, 2017 and 2016. 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, 2017 December 31, 2016 United States Oil (BBLS) NGL (BBLS) Gas (MCF) Total (BOE) (a) Oil (BBLS) NGL (BBLS) Gas (MCF) Total (BOE) (a) Proved developed and undeveloped reserves: Beginning of year 195,320 8,060 233,340 242,270 326,606 3,964 337,242 386,777 Extensions and discoveries (b) 69,820 5,370 33,430 80,762 - - - - Revisions of previous estimates (c) 112,885 18,616 (59,921 ) 121,514 (109,722 ) 5,652 (82,812 ) (117,872 ) Production (84,345 ) (8,981 ) (59,088 ) (103,174 ) (21,564 ) (1,556 ) (21,090 ) (26,635 ) End of year 293,680 23,065 147,761 341,372 195,320 8,060 233,340 242,270 Proved developed reserves: Beginning of year 174,800 8,060 221,640 219,800 14,355 3,964 103,054 35,495 End of year 223,860 17,695 114,331 260,610 174,800 8,060 221,640 219,800 Proved undeveloped reserves: Beginning of year 20,520 - 11,700 22,470 312,251 - 234,188 351,282 End of year 69,820 5,370 33,430 80,762 20,520 - 11,700 22,470 (a) BOE refers to barrel of oil . (b) Extensions and discoveries were attributable to extensions for the Beta Project. (c) 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, 2017 2016 (in thousands) Future cash inflows $ 14,135 $ 7,620 Future production costs (3,219 ) (2,345 ) Future development costs (2,631 ) (1,940 ) Future net cash flows 8,285 3,335 10% annual discount for estimated timing of cash flows (1,166 ) 176 Standardized measure of discounted future net cash flows $ 7,119 $ 3,511 Table V - Changes in the Standardized Measure for Discounted Cash Flows The changes in present values between years, which can be significant, reflect changes in estimated proved reserve quantities and prices and assumptions used in forecasting production volumes and costs. Year ended December 31, 2017 2016 (in thousands) Net change in sales and transfer prices and in production costs $ 2,554 $ (3,446 ) Sales and transfers of oil and gas produced during the period (3,664 ) (667 ) Net change due to extensions, discoveries, and improved recovery 1,675 - Changes in estimated future development costs 15 5,163 Net change due to revisions in quantities estimates 3,339 (2,701 ) Accretion of discount 351 446 Other (662 ) 257 Aggregate change in the standardized measure of discounted future $ 3,608 $ (948 ) 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, 2017
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.
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, 2017, 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, 2017, the Fund’s bank balances were maintained in uninsured bank accounts at Wells Fargo Bank, N.A.
Salvage Fund	Salvage Fund The Fund deposits cash in a separate interest-bearing account, or salvage fund, to provide for the dismantling and removal of production platforms and facilities and plugging and abandoning its wells at the end of their useful lives in accordance with applicable federal and state laws and regulations. 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 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. 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” for additional information.
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 property has been determined to be fully depleted or upon the sale, retirement or abandonment of a property, the cost and related accumulated depletion and amortization, if any, is eliminated from the property accounts, and the resultant gain or loss is recognized. The Fund may be required to advance its share of the estimated succeeding month’s expenditures to the operator for its oil and gas properties. As the costs are incurred, the advances are reclassified to proved properties.
Asset Retirement Obligations	Asset Retirement Obligations For oil and gas properties, there are obligations to perform removal and remediation activities when the properties are retired. Upon the determination that a property is either proved or dry, a retirement obligation is incurred. The Fund recognizes the fair value of a liability for an asset retirement obligation in the period incurred. Plug and abandonment costs associated with unsuccessful projects are expensed as dry-hole costs. Bi-annually, or more frequently if an event occurs that would dictate a change in assumptions or estimates underlying the obligations, the Fund reassesses its asset retirement obligations to determine whether any revisions to the obligations are necessary. The following table presents changes in asset retirement obligations during the years ended December 31, 2017 and 2016. 2017 2016 (in thousands) Balance, beginning of year $ 1,106 $ 1,584 Liabilities incurred 2 2 Liabilities settled (96 ) (208 ) Accretion expense 31 54 Revision of estimates (219 ) (326 ) Balance, end of year $ 824 $ 1,106 During the year ended December 31, 2017, the Fund recorded credits to depletion expense totaling $0.1 million, which related to an adjustment to the asset retirement obligation for a fully depleted property. 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 future net discounted cash flows from proved oil and natural gas reserves could change in the near term. Fluctuations in oil and natural gas prices may impact 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.
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 2014 through 2016 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 May 2014, the Financial Accounting Standards Board (“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. Under the new accounting guidance, the revenue associated with the Fund’s existing contracts will be recognized in the period that control of the related commodity is transferred to the customer, which is generally consistent with its current revenue recognition model. The Fund adopted the new accounting guidance using the modified retrospective method on January 1, 2018. Although the Fund did not identify changes to its revenue recognition that resulted in a material cumulative adjustment to retained earnings on January 1, 2018, the adoption of the accounting guidance will result in enhanced disclosures related to revenue recognition policies, the Fund’s performance obligations and significant judgments used in applying the new revenue recognition accounting guidance.

Organization and Summary of S13

Organization and Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2017
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Schedule of Changes in Asset Retirement Obligations	2017 2016 (in thousands) Balance, beginning of year $ 1,106 $ 1,584 Liabilities incurred 2 2 Liabilities settled (96 ) (208 ) Accretion expense 31 54 Revision of estimates (219 ) (326 ) Balance, end of year $ 824 $ 1,106

Information about Oil and Gas14

Information about Oil and Gas Producing Activities (Tables)	12 Months Ended
	Dec. 31, 2017
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, 2017 2016 (in thousands) Proved properties $ 22,433 $ 19,669 Accumulated depletion and amortization (7,921 ) (3,897 ) Oil and gas properties, net $ 14,512 $ 15,772
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, 2017 2016 (in thousands) Exploration costs $ 16 $ 22 Development costs 2,589 2,564 $ 2,605 $ 2,586
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, 2017 and 2016. 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, 2017 December 31, 2016 United States Oil (BBLS) NGL (BBLS) Gas (MCF) Total (BOE) (a) Oil (BBLS) NGL (BBLS) Gas (MCF) Total (BOE) (a) Proved developed and undeveloped reserves: Beginning of year 195,320 8,060 233,340 242,270 326,606 3,964 337,242 386,777 Extensions and discoveries (b) 69,820 5,370 33,430 80,762 - - - - Revisions of previous estimates (c) 112,885 18,616 (59,921 ) 121,514 (109,722 ) 5,652 (82,812 ) (117,872 ) Production (84,345 ) (8,981 ) (59,088 ) (103,174 ) (21,564 ) (1,556 ) (21,090 ) (26,635 ) End of year 293,680 23,065 147,761 341,372 195,320 8,060 233,340 242,270 Proved developed reserves: Beginning of year 174,800 8,060 221,640 219,800 14,355 3,964 103,054 35,495 End of year 223,860 17,695 114,331 260,610 174,800 8,060 221,640 219,800 Proved undeveloped reserves: Beginning of year 20,520 - 11,700 22,470 312,251 - 234,188 351,282 End of year 69,820 5,370 33,430 80,762 20,520 - 11,700 22,470 (a) BOE refers to barrel of oil . (b) Extensions and discoveries were attributable to extensions for the Beta Project. (c) 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, 2017 2016 (in thousands) Future cash inflows $ 14,135 $ 7,620 Future production costs (3,219 ) (2,345 ) Future development costs (2,631 ) (1,940 ) Future net cash flows 8,285 3,335 10% annual discount for estimated timing of cash flows (1,166 ) 176 Standardized measure of discounted future net cash flows $ 7,119 $ 3,511
Schedule of Changes in the Standardized Measure for Discounted Cash Flows	Table V - Changes in the Standardized Measure for Discounted Cash Flows The changes in present values between years, which can be significant, reflect changes in estimated proved reserve quantities and prices and assumptions used in forecasting production volumes and costs. Year ended December 31, 2017 2016 (in thousands) Net change in sales and transfer prices and in production costs $ 2,554 $ (3,446 ) Sales and transfers of oil and gas produced during the period (3,664 ) (667 ) Net change due to extensions, discoveries, and improved recovery 1,675 - Changes in estimated future development costs 15 5,163 Net change due to revisions in quantities estimates 3,339 (2,701 ) Accretion of discount 351 446 Other (662 ) 257 Aggregate change in the standardized measure of discounted future $ 3,608 $ (948 )

Organization and Summary of S15

Organization and Summary of Significant Accounting Policies (Narrative) (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2017USD ($)
Organization and Summary of Significant Accounting Policies [Abstract]
Cash insured amount	$ 250
Credits to depletion	$ (100)
Percentage of cash from operations allocated to shareholders	85.00%
Percentage of cash from operations allocated to Fund Manager	15.00%
Percentage of cash from dispositions allocated to shareholders	99.00%
Percentage of cash from dispositions allocated to Fund Manager	1.00%
Percentage of cash from dispositions allocated to shareholders after distributions have equaled capital contributions	85.00%
Percentage of cash from dispositions allocated to Fund Manager after distributions have equaled capital contributions	15.00%

Organization and Summary of S16

Organization and Summary of Significant Accounting Policies (Schedule of Changes in Asset Retirement Obligations) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Balance, beginning of year	$ 1,106	$ 1,584
Liabilities incurred	2	2
Liabilities settled	(96)	(208)
Accretion expense	31	54
Revision of estimates	(219)	(326)
Balance, end of year	$ 824	$ 1,106

Related Parties (Details)

Related Parties (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Related Party Transactions [Abstract]
Annual management fee percentage rate	2.50%
Cost of services provided by Manager, quarterly amount	$ 20
Cost of services provided by Manager	$ 80	$ 80
Percentage of total distributions allocated to Fund Manager	15.00%

Credit Agreement - Beta Proje18

Credit Agreement - Beta Project Financing (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Debt Disclosure [Abstract]
Credit agreement, maximum borrowing capacity	$ 5,400
Long-term borrowings	$ 4,800	$ 5,400
Credit agreement, interest rate	8.00%
Monthly fixed repayment amount	$ 100
Credit agreement, maturity date	Dec. 31, 2020
Unamortized debt discounts and deferred financing costs		100
Amortization of financing costs	100	40
Amortization capitalized		40
Accrued interest		200
Interest expense	500	200
Capitalized interest		100
Interest paid	$ 43	$ 100

Commitments and Contingencies (

Commitments and Contingencies (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2017USD ($)
Commitments and Contingencies Disclosure [Abstract]
Commitments for the drilling and development of investment properties	$ 3,000
Commitments for asset retirement obligations included in estimated capital commitments	1,600
Commitments for the drilling and development of investment properties expected to be incurred in the next 12 months	$ 1,200

Information about Oil and Gas20

Information about Oil and Gas Producing Activities (Schedule of Capitalized Costs Relating to Oil and Gas Producing Activities) (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Information About Oil And Gas Producing Activities [Abstract]
Proved properties	$ 22,433	$ 19,669
Accumulated depletion and amortization	(7,921)	(3,897)
Total oil and gas properties, net	$ 14,512	$ 15,772

Information about Oil and Gas21

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, 2017	Dec. 31, 2016
Information About Oil And Gas Producing Activities [Abstract]
Exploration costs	$ 16	$ 22
Development costs	2,589	2,564
Total costs	$ 2,605	$ 2,586

Information about Oil and Gas22

Information about Oil and Gas Producing Activities (Schedule of Reserve Quantity Information) (Details)		12 Months Ended
		Dec. 31, 2017bblMcf	Dec. 31, 2016bblMcf
Oil (BBLS) [Member]
Proved developed and undeveloped reserves:
Beginning of year		195,320	326,606
Extensions and discoveries	[1]	69,820
Revisions of previous estimates	[2]	112,885	(109,722)
Production		(84,345)	(21,564)
End of year		293,680	195,320
Proved developed reserves:
Beginning of year		174,800	14,355
End of year		223,860	174,800
Proved undeveloped reserves:
Beginning of year		20,520	312,251
End of year		69,820	20,520
NGL (BBLS) [Member]
Proved developed and undeveloped reserves:
Beginning of year		8,060	3,964
Extensions and discoveries	[1]	5,370
Revisions of previous estimates	[2]	18,616	5,652
Production		(8,981)	(1,556)
End of year		23,065	8,060
Proved developed reserves:
Beginning of year		8,060	3,964
End of year		17,695	8,060
Proved undeveloped reserves:
Beginning of year
End of year		5,370
Gas (MCF) [Member]
Proved developed and undeveloped reserves:
Beginning of year | Mcf		233,340	337,242
Extensions and discoveries | Mcf	[1]	33,430
Revisions of previous estimates | Mcf	[2]	(59,921)	(82,812)
Production | Mcf		(59,088)	(21,090)
End of year | Mcf		147,761	233,340
Proved developed reserves:
Beginning of year | Mcf		221,640	103,054
End of year | Mcf		114,331	221,640
Proved undeveloped reserves:
Beginning of year | Mcf		11,700	234,188
End of year | Mcf		33,430	11,700
Total (BOE) [Member]
Proved developed and undeveloped reserves:
Beginning of year	[3]	242,270	386,777
Extensions and discoveries	[1],[3]	80,762
Revisions of previous estimates	[2],[3]	121,514	(117,872)
Production	[3]	(103,174)	(26,635)
End of year	[3]	341,372	242,270
Proved developed reserves:
Beginning of year	[3]	219,800	35,495
End of year	[3]	260,610	219,800
Proved undeveloped reserves:
Beginning of year	[3]	22,470	351,282
End of year	[3]	80,762	22,470
[1]	Extensions and discoveries were attributable to extensions for the Beta Project.
[2]	Revisions of previous estimates were attributable to well performance.
[3]	BOE refers to barrel of oil equivalent. Barrel of oil equivalent is based on six MCF of natural gas to one barrel of oil or one barrel of NGL, which reflects an energy content equivalency and not a price or revenue equivalency.

Information about Oil and Gas23

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, 2017	Dec. 31, 2016
Information About Oil And Gas Producing Activities [Abstract]
Future cash inflows	$ 14,135	$ 7,620
Future production costs	(3,219)	(2,345)
Future development costs	(2,631)	(1,940)
Future net cash flows	8,285	3,335
10% annual discount for estimated timing of cash flows	(1,166)	176
Standardized measure of discounted future net cash flows	$ 7,119	$ 3,511

Information about Oil and Gas24

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, 2017	Dec. 31, 2016
Information About Oil And Gas Producing Activities [Abstract]
Net change in sales and transfer prices and in production costs related to future production	$ 2,554	$ (3,446)
Sales and transfers of oil and gas produced during the period	(3,664)	(667)
Net change due to extensions, discoveries, and improved recovery	1,675
Changes in estimated future development costs	15	5,163
Net change due to revisions in quantities estimates	3,339	(2,701)
Accretion of discount	351	446
Other	(662)	257
Aggregate change in the standardized measure of discounted future net cash flows for the year	$ 3,608	$ (948)