Document and Entity Information
Document and Entity Information - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2016 | Mar. 02, 2017 | |
Document And Entity Information [Abstract] | ||
Document Type | 10-K | |
Amendment Flag | false | |
Document Period End Date | Dec. 31, 2016 | |
Entity Registrant Name | RIDGEWOOD ENERGY X FUND, LLC | |
Entity Central Index Key | 1,455,741 | |
Current Fiscal Year End Date | --12-31 | |
Document Fiscal Period Focus | FY | |
Document Fiscal Year Focus | 2,016 | |
Entity Filer Category | Smaller Reporting Company | |
Entity Units Outstanding | 477.8874 | |
Entity Current Reporting Status | Yes | |
Entity Well-known Seasoned Issuer | No | |
Entity Voluntary Filers | No | |
Entity Public Float | $ 0 |
BALANCE SHEETS
BALANCE SHEETS - USD ($) $ in Thousands | Dec. 31, 2016 | Dec. 31, 2015 |
Current assets: | ||
Cash and cash equivalents | $ 7,337 | $ 6,950 |
Salvage fund | 664 | 1,185 |
Production receivable | 419 | 343 |
Other current assets | 108 | 3 |
Total current assets | 8,528 | 8,481 |
Salvage fund | 2,881 | 2,736 |
Investment in Delta House | 119 | 572 |
Oil and gas properties: | ||
Proved properties | 17,031 | 17,096 |
Less: accumulated depletion and amortization | (10,541) | (8,524) |
Total oil and gas properties, net | 6,490 | 8,572 |
Total assets | 18,018 | 20,361 |
Current liabilities: | ||
Due to operators | 348 | 356 |
Accrued expenses | 82 | 119 |
Asset retirement obligations | 664 | 1,185 |
Total current liabilities | 1,094 | 1,660 |
Asset retirement obligations | 1,373 | 1,340 |
Total liabilities | 2,467 | 3,000 |
Commitments and contingencies (Note 3) | ||
Members' capital: | ||
Distributions | (5,066) | (4,936) |
Retained earnings | 4,106 | 3,943 |
Manager's total | (960) | (993) |
Capital contributions (500 shares authorized; 477.8874 issued and outstanding) | 94,698 | 94,698 |
Syndication costs | (11,080) | (11,080) |
Distributions | (30,884) | (30,146) |
Accumulated deficit | (36,223) | (35,118) |
Shareholders' total | 16,511 | 18,354 |
Total members' capital | 15,551 | 17,361 |
Total liabilities and members' capital | $ 18,018 | $ 20,361 |
BALANCE SHEETS (Parenthetical)
BALANCE SHEETS (Parenthetical) - shares | Dec. 31, 2016 | Dec. 31, 2015 |
Statement of Financial Position [Abstract] | ||
Shares authorized | 500 | 500 |
Shares issued | 477.8874 | 477.8874 |
Shares outstanding | 477.8874 | 477.8874 |
STATEMENTS OF OPERATIONS
STATEMENTS OF OPERATIONS - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Revenue | ||
Oil and gas revenue | $ 5,045 | $ 3,512 |
Expenses | ||
Depletion and amortization | 2,017 | 1,833 |
Management fees to affiliate (Note 2) | 1,083 | 1,082 |
Operating expenses | 2,819 | 1,951 |
General and administrative expenses | 154 | 152 |
Total expenses | 6,073 | 5,018 |
Loss from operations | (1,028) | (1,506) |
Other (loss) income | ||
Loss on investment in Delta House | (114) | |
Dividend income | 191 | 75 |
Interest income | 9 | 11 |
Total other income | 86 | 86 |
Net loss | (942) | (1,420) |
Manager Interest | ||
Net income | 163 | 59 |
Shareholder Interest | ||
Net loss | $ (1,105) | $ (1,479) |
Net loss per share | $ (2,312) | $ (3,095) |
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, 2014 | $ (968) | $ 20,311 | $ 19,343 | |
Balances, shares at Dec. 31, 2014 | 477.8874 | |||
Distributions | (84) | (478) | (562) | |
Net income (loss) | 59 | (1,479) | (1,420) | |
Balances at Dec. 31, 2015 | (993) | 18,354 | $ 17,361 | |
Balances, shares at Dec. 31, 2015 | 477.8874 | 477.8874 | ||
Distributions | (130) | (738) | $ (868) | |
Net income (loss) | 163 | (1,105) | (942) | |
Balances at Dec. 31, 2016 | $ (960) | $ 16,511 | $ 15,551 | |
Balances, shares at Dec. 31, 2016 | 477.8874 | 477.8874 |
STATEMENTS OF CASH FLOWS
STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Cash flows from operating activities | ||
Net loss | $ (942) | $ (1,420) |
Adjustments to reconcile net loss to net cash provided by operating activities: | ||
Depletion and amortization | 2,017 | 1,833 |
Accretion expense | 64 | 140 |
Loss on investment in Delta House | 114 | |
Changes in assets and liabilities: | ||
Increase in production receivable | (129) | (120) |
(Increase) decrease in other current assets | (107) | 42 |
Decrease in due to operators | (8) | (59) |
Increase in accrued expenses | 16 | 75 |
Settlement of asset retirement obligations | (521) | |
Net cash provided by operating activities | 504 | 491 |
Cash flows from investing activities | ||
Credits (capital expenditures) for oil and gas properties and investment in Delta House | 36 | (3,175) |
Proceeds from sale of investment in Delta House | 339 | |
Decrease (increase) in salvage fund | 376 | (2,388) |
Net cash provided by (used in) investing activities | 751 | (5,563) |
Cash flows from financing activities | ||
Distributions | (868) | (562) |
Net cash used in financing activities | (868) | (562) |
Net increase (decrease) in cash and cash equivalents | 387 | (5,634) |
Cash and cash equivalents, beginning of year | 6,950 | 12,584 |
Cash and cash equivalents, end of year | 7,337 | 6,950 |
Supplemental disclosure of non-cash investing activities | ||
Advances used for capital expenditures in oil and gas properties reclassified to proved properties | $ 589 |
Organization and Summary of Sig
Organization and Summary of Significant Accounting Policies | 12 Months Ended |
Dec. 31, 2016 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Organization and Summary of Significant Accounting Policies | 1. Organization and Summary of Significant Accounting Policies Organization The Ridgewood Energy X Fund, LLC (the “Fund”), a Delaware limited liability company, was formed on August 30, 2007 and operates pursuant to a limited liability company agreement (the “LLC Agreement”) dated as of January 2, 2008 by and among Ridgewood Energy Corporation (the “Manager”) and the shareholders of the Fund, which addresses matters such as the authority and voting rights of the Manager and shareholders, capitalization, transferability of membership interests, participation in costs and revenues, distribution of assets and dissolution and winding up. The Fund was organized to primarily acquire interests in oil and gas properties located in the United States offshore waters of Texas, Louisiana and Alabama in the Gulf of Mexico. The Manager has direct and exclusive control over the management of the Fund’s operations. With respect to project investments, the Manager locates potential projects, conducts due diligence and negotiates and completes the transactions. The Manager performs, or arranges for the performance of, the management, advisory and administrative services required for Fund operations. Such services include, without limitation, the administration of shareholder accounts, shareholder relations and the preparation, review and dissemination of tax and other financial information and the management of the Fund’s investments in projects. In addition, the Manager provides office space, equipment and facilities and other services necessary for Fund operations. The Manager also engages and manages contractual relations with unaffiliated custodians, depositories, accountants, attorneys, corporate fiduciaries, insurers, banks and others as required. See Notes 2 and 3. Use of Estimates The preparation of financial statements in accordance with accounting principles generally accepted in the United States of America (“GAAP”) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities as of the date of the financial statements and the reported amounts of revenue and expense during the reporting period. On an ongoing basis, 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, 2016, the Fund had no cash equivalents. At times, deposits may be in excess of federally insured limits, which are $250 thousand per insured financial institution. As of December 31, 2016, the Fund’s bank balances were maintained in uninsured bank accounts at Wells Fargo Bank, N.A. Salvage Fund The Fund deposits in a separate interest-bearing account, or salvage fund, cash to provide for the dismantling and removal of production platforms and facilities and plugging and abandoning its wells at the end of their useful lives in accordance with applicable federal and state laws and regulations. Interest earned on the account will become part of the salvage fund. There are no restrictions on withdrawals from the salvage fund. Investment in Delta House The Fund has investments in Delta House Oil and Gas Lateral, LLC and Delta House FPS, LLC (collectively “Delta House”), legal entities that own interests in a deepwater floating production system operated by LLOG Exploration Company. The Fund accounts for its investment in Delta House using the cost method of accounting for investments as it does not have the ability to exercise significant influence over such investment. Under the cost method, the Fund recognizes an investment in the equity of an investee at cost. The Fund recognizes as income dividends received that are distributed from net accumulated earnings of the investee since the date of acquisition by the Fund. Dividends received in excess of earnings subsequent to the date of investment are considered a return of investment and are recorded as reductions of cost of the investment. The Fund reviews its cost method investment for impairment at each reporting period and when an event or change in circumstances has occurred that may have a significant adverse effect on the fair value of the investment. Losses on cost method investments including impairments that are deemed to be other than temporary are classified as non-operating losses in the Fund’s statements of operations. As of December 31, 2016, the Fund invested a total of $0.6 million in Delta House and has received cash from its investment totaling $0.6 million, of which $0.3 million relates to dividends received and $0.3 million relates to cash proceeds from the sale of approximately 74% of its investment, pursuant to a unit purchase agreement with D-Day Offshore Holdings, LLC dated October 31, 2016. Certain other funds managed by the Manager were also parties to this unit purchase agreement. The Fund adjusted the carrying value of its investment in Delta House in third quarter 2016 to fair value, which was determined based on the third party sale and recorded a loss on investment during the year ended December 31, 2016 of $0.1 million. The loss was included on the Fund’s statement of operations within “Loss on investment in Delta House”. Inputs used to estimate fair value of the investment in Delta House are categorized as Level 3 in the fair value hierarchy. As of December 31, 2016, the Fund’s remaining carrying value for the investment in Delta House was $0.1 million. Oil and Gas Properties The Fund invests in oil and gas properties, which are operated by unaffiliated entities that are responsible for drilling, administering and producing activities pursuant to the terms of the applicable operating agreements with working interest owners. The Fund’s portion of exploration, drilling, operating and capital equipment expenditures is billed by operators. Acquisition, exploration and development costs are accounted for using the successful efforts method. Costs of acquiring unproved and proved oil and natural gas leasehold acreage, including lease bonuses, brokers’ fees and other related costs are capitalized. Costs of drilling and equipping productive wells and related production facilities are capitalized. The costs of exploratory wells are capitalized pending determination of whether proved reserves have been found. If proved commercial reserves are not found, exploratory well costs are expensed as dry-hole costs. At times, the Fund receives adjustments to certain wells from their respective operators upon review and audit of the wells’ costs. Annual lease rentals and exploration expenses are expensed as incurred. All costs related to production activity, transportation expense and workover efforts are expensed as incurred. Once a well has been determined to be fully depleted or upon the sale, retirement or abandonment of a property, the cost and related accumulated depletion and amortization, if any, is eliminated from the property accounts, and the resultant gain or loss is recognized. As of December 31, 2016 and 2015, amounts recorded in due to operators totaling $37 thousand related to capital expenditures for oil and gas properties. Advances to Operators for Working Interests and Expenditures The Fund may be required to advance its share of the estimated succeeding month’s expenditures to the operator for its oil and gas properties. As the costs are incurred, the advances are reclassified to proved properties. Asset Retirement Obligations For oil and gas properties, there are obligations to perform removal and remediation activities when the properties are retired. Upon the determination that a property is either proved or dry, a retirement obligation is incurred. The Fund recognizes the fair value of a liability for an asset retirement obligation in the period incurred. Plug and abandonment costs associated with unsuccessful projects are expensed as dry-hole costs. At least bi-annually, or more frequently if an event occurs that would dictate a change in assumptions or estimates underlying the obligations, the Fund reassesses all of its asset retirement obligations to determine whether any revisions to the obligations are necessary. The following table presents changes in asset retirement obligations during the years ended December 31, 2016 and 2015. 2016 2015 (in thousands) Balance, beginning of year $ 2,525 $ 1,571 Liabilities incurred - 36 Liabilities settled (521 ) - Accretion expense 64 140 Revision of estimates (31 ) 778 Balance, end of year $ 2,037 $ 2,525 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. Impairment of Long-Lived Assets The Fund reviews the carrying value of its oil and gas properties annually and when management determines that events and circumstances indicate that the recorded carrying value of properties may not be recoverable. Impairments are determined by comparing estimated future net undiscounted cash flows to the carrying value at the time of the review. If the carrying value exceeds the estimated future net undiscounted cash flows, the carrying value of the asset is written down to fair value, which is determined using estimated future net discounted cash flows from the asset. The fair value determinations require considerable judgment and are sensitive to change. Different pricing assumptions, reserve estimates or discount rates could result in a different calculated impairment. Given the volatility of oil and natural gas prices, it is reasonably possible that the Fund’s estimate of discounted future net cash flows from proved oil and natural gas reserves could change in the near term. Significant and consistent fluctuations in oil and natural gas prices since fourth quarter 2014 have impacted the fair value of the Fund’s oil and gas properties. If oil and natural gas prices decline, even if only for a short period of time, it is possible that impairments of oil and gas properties will occur. Depletion and Amortization Depletion and amortization of the cost of proved oil and gas properties are calculated using the units-of-production method. Proved developed reserves are used as the base for depleting capitalized costs associated with successful exploratory well costs, development costs and related facilities. The sum of proved developed and proved undeveloped reserves is used as the base for depleting or amortizing leasehold acquisition costs. During the year ended December 31, 2015, the Fund recorded $0.4 million of depletion expense related to adjustments to asset retirement obligations for fully depleted properties. Income Taxes No provision is made for income taxes in the financial statements. The Fund is a limited liability company, and as such, the Fund’s income or loss is passed through and included in the tax returns of the Fund’s shareholders. The Fund files U.S. Federal and State tax returns and the 2013 through 2015 tax returns remain open for examination by tax authorities. Income and Expense Allocation Profits and losses are allocated to shareholders and the Manager in accordance with the LLC Agreement. Distributions Distributions to shareholders are allocated in proportion to the number of shares held. The Manager determines whether available cash from operations, as defined in the LLC Agreement, will be distributed. Such distributions are allocated 85% to the shareholders and 15% to the Manager, as required by the LLC Agreement. Available cash from dispositions, as defined in the LLC Agreement, will be paid 99% to shareholders and 1% to the Manager until the shareholders have received total distributions equal to their capital contributions. After shareholders have received distributions equal to their capital contributions, 85% of available cash from dispositions will be distributed to shareholders and 15% to the Manager. Recent Accounting Pronouncements In January 2016, the Financial Accounting Standards Board (“FASB”) issued accounting guidance that requires, among other things, companies to measure investments in other entities, except those accounted for under the equity method, at fair value and recognize any changes in fair value in net income unless an election is made to record the investment at cost, less impairment and plus or minus subsequent adjustments for observable price changes with change in basis reported in current earnings. This pronouncement is effective for fiscal years beginning after December 15, 2017 and interim periods within those fiscal years, with early adoption not permitted. The Fund is currently evaluating the impact of this guidance on its financial statements. In May 2014, the FASB issued accounting guidance on revenue recognition, which provides for a single five-step model to be applied to all revenue contracts with customers. In July 2015, the FASB issued a deferral of the effective date of the guidance to 2018, with early adoption permitted in 2017. In March 2016, the FASB issued accounting guidance, which clarifies the implementation guidance on principal versus agent considerations in the new revenue recognition standard. In April 2016, the FASB issued guidance on identifying performance obligations and licensing and in May 2016, the FASB issued final amendments which provided narrow scope improvements and practical expedients related to the implementation of the guidance. The accounting guidance may be applied either retrospectively or through the use of a modified-retrospective method. Based on the Fund’s initial assessment of the accounting guidance, the Fund currently does not expect it will have a material impact on its results of operations or cash flows in the period after adoption. Under the accounting guidance, revenue is recognized as control transfers to the customer, as such the Fund expects the application of the accounting guidance to its existing contracts to be generally consistent with its current revenue recognition model. The Fund will continue the evaluation of the provisions of this accounting guidance, as well as new or emerging interpretations, as it relates to new contracts the Fund receives and in particular as it relates to disclosure requirements through the date of adoption, which is currently expected to be January 1, 2018. |
Related Parties
Related Parties | 12 Months Ended |
Dec. 31, 2016 | |
Related Party Transactions [Abstract] | |
Related Parties | 2. Related Parties Pursuant to the terms of the LLC Agreement, the Manager renders management, administrative and advisory services to the Fund. For such services, the Manager is entitled to an annual management fee, payable monthly, of 2.5% of total capital contributions, net of cumulative dry-hole and related well costs incurred by the Fund. In addition, pursuant to the terms of the LLC Agreement, the Manager is also permitted to waive the management fee at its own discretion. Such fee may be temporarily waived to accommodate the Fund’s short-term capital commitments. Management fees during each of the years ended December 31, 2016 and 2015 were $1.1 million. The Manager is entitled to receive a 15% interest in cash distributions from operations made by the Fund. Distributions paid to the Manager during each of the None of the amounts paid to the Manager have been derived as a result of arm’s length negotiations. In February 2015, DH Sales and Transport, LLC (“DH 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 Delta House Funds”) to facilitate the transportation and sale of oil and gas produced from the Diller and Marmalard projects. On April 11, 2016, the Ridgewood Delta House Funds entered into a master agreement with DH S&T pursuant to which DH S&T is obligated to purchase from Ridgewood Delta House Funds all of their interests in oil and gas produced at the Diller and Marmalard projects and sell such volumes to unrelated third party purchasers. Pursuant to the master agreement, DH S&T is a pass-through entity such that it receives no benefit or compensation for the services provided under the master agreement or under any other agreements it enters into with regard to the oil and gas purchased from the Ridgewood Delta House Funds. Ridgewood Delta House Funds have agreed to indemnify, defend and hold harmless DH S&T from and against all claims, liabilities, losses, causes of action, costs and expenses asserted against it as a result of or arising from any act or omission, breach and claims for losses or damages arising out of its dealing with third parties with respect to the transportation, processing or sale of oil and gas from the Diller and Marmalard projects. The revenues and expenses from the sale of oil and natural gas to third party purchasers are recorded as oil and gas revenue and operating expenses in the Fund’s statements of operations. These revenues and operating expenses allocable to the Fund are based on the Fund’s working interest ownership in the Diller and Marmalard projects. At times, short-term payables and receivables, which do not bear interest, arise from transactions with affiliates in the ordinary course of business. The Fund has working interest ownership in certain projects to acquire and develop oil and natural gas projects with other entities that are likewise managed by the Manager. |
Commitments and Contingencies
Commitments and Contingencies | 12 Months Ended |
Dec. 31, 2016 | |
Commitments and Contingencies Disclosure [Abstract] | |
Commitments and Contingencies | 3. Commitments and Contingencies Capital Commitments The Fund has entered into multiple agreements for the acquisition, drilling and development of its oil and gas properties. The estimated capital expenditures associated with these agreements vary depending on the stage of development on a property-by-property basis. As of December 31, 2016, the Fund’s estimated capital commitments related to its oil and gas properties were $6.6 million (which include asset retirement obligations for the Fund’s projects of $3.2 million), of which $0.6 million is expected to be spent during the year ending December 31, 2017. 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, 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 December 31, 2016 and 2015, there were no known environmental contingencies that required adjustment to, or disclosure in, the Fund’s financial statements. During the past several years, the United States Congress, as well as certain regulatory agencies with jurisdiction over the Fund’s business, have considered or proposed legislation or regulation relating to the upstream oil and gas industry both onshore and offshore. If any such proposals were to be enacted or adopted they could potentially materially impact the Fund’s operations. It is not possible at this time to predict whether such legislation or regulation, if proposed, will be adopted as initially written, if at all, or how legislation or new regulation that may be adopted would impact the Fund’s business. Any such future laws and regulations could result in increased compliance costs or additional operating restrictions, which could have a material adverse effect on the Fund’s operating results and cash flows. BOEM Notice to Lessees on Supplemental Bonding On July 14, 2016, the Bureau of Ocean Energy Management (“BOEM”) issued a Notice to Lessees (“NTL”) that discontinued and materially replaced existing policies and procedures regarding financial security (i.e. supplemental bonding) for decommissioning obligations of lessees of federal oil and gas leases and owners of pipeline rights-of-way, rights-of use and easements on the Outer Continental Shelf (“Lessees”) . Insurance Coverage The Fund is subject to all risks inherent in the exploration for and development of oil and natural gas. Insurance coverage as is customary for entities engaged in similar operations is maintained, but losses may occur from uninsurable risks or amounts in excess of existing insurance coverage. The occurrence of an event that is not insured or not fully insured could have a material adverse impact upon earnings and financial position. Moreover, insurance is obtained as a package covering all of the funds managed by the Manager. Depending on the extent, nature and payment of claims made by the Fund or other funds managed by the Manager, yearly insurance coverage may be exhausted and become insufficient to cover a claim by the Fund in a given year. |
Information about Oil and Gas P
Information about Oil and Gas Producing Activities | 12 Months Ended |
Dec. 31, 2016 | |
Information About Oil And Gas Producing Activities [Abstract] | |
Information about Oil and Gas Producing Activities | Ridgewood Energy X Fund, LLC Supplementary Financial Information Information about Oil and Gas Producing Activities – Unaudited In accordance with the FASB guidance on disclosures of oil and gas producing activities, this section provides supplementary information on oil and gas exploration and producing activities of the Fund. The Fund is engaged solely in oil and gas activities, all of which are located in the United States offshore waters of Louisiana in the Gulf of Mexico. Table I - Capitalized Costs Relating to Oil and Gas Producing Activities December 31, 2016 2015 (in thousands) Proved properties $ 17,031 $ 17,096 Total oil and gas properties 17,031 17,096 Accumulated depletion and amortization (10,541 ) (8,524 ) Oil and gas properties, net $ 6,490 $ 8,572 Table II - Costs Incurred in Oil and Gas Property Acquisition, Exploration, and Development Year ended December 31, 2016 2015 (in thousands) Exploration costs $ 20 $ 5 Development costs (4 ) 3,655 $ 16 $ 3,660 Table III - Reserve Quantity Information Oil and gas reserves of the Fund have been estimated by independent petroleum engineers, Netherland, Sewell & Associates, Inc. at December 31, 2016 and 2015. These reserve disclosures have been prepared in compliance with the Securities and Exchange Commission rules. Due to inherent uncertainties and the limited nature of recovery data, estimates of reserve information are subject to change as additional information becomes available. December 31, 2016 December 31, 2015 United States Oil (BBLS) NGL (BBLS) Gas (MCF) Oil (BBLS) NGL (BBLS) Gas (MCF) Proved developed and undeveloped reserves: Beginning of year 583,481 108,454 1,237,695 546,116 28,486 1,578,796 Revisions of previous estimates (a) 5,860 83,909 434,552 103,223 90,272 (228,885 ) Production (106,251 ) (9,842 ) (193,266 ) (65,858 ) (10,304 ) (112,216 ) End of year 483,090 182,521 1,478,981 583,481 108,454 1,237,695 Proved developed reserves: Beginning of year 374,821 63,311 788,355 69,495 28,486 406,564 End of year 367,710 115,471 988,551 374,821 63,311 788,355 Proved undeveloped reserves: Beginning of year 208,660 45,143 449,340 476,621 - 1,172,232 End of year 115,380 67,050 490,430 208,660 45,143 449,340 (a) Revisions of previous estimates were attributable to well performance. Table IV - Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves Summarized in the following table is information for the Fund with respect to the standardized measure of discounted future net cash flows relating to proved oil and gas reserves. Future cash inflows were determined based on average first-of-the-month pricing for the prior twelve-month period. Future production and development costs are derived based on current costs assuming continuation of existing economic conditions. December 31, 2016 2015 (in thousands) Future cash inflows $ 23,263 $ 32,530 Future production costs (9,266 ) (11,944 ) Future development costs (5,581 ) (7,150 ) Future net cash flows 8,416 13,436 10% annual discount for estimated timing of cash flows (1,230 ) (4,043 ) Standardized measure of discounted future net cash flows $ 7,186 $ 9,393 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, 2016 2015 (in thousands) Net change in sales and transfer prices and in production costs $ (4,683 ) $ (16,013 ) Sales and transfers of oil and gas produced during the period (2,399 ) (1,613 ) Changes in estimated future development costs 1,569 (786 ) Net change due to revisions in quantities estimates 2,125 2,489 Accretion of discount 939 2,404 Other 242 (1,124 ) Aggregate change in the standardized measure of discounted future net $ (2,207 ) $ (14,643 ) 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 S11
Organization and Summary of Significant Accounting Policies (Policy) | 12 Months Ended |
Dec. 31, 2016 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Use of Estimates | Use of Estimates The preparation of financial statements in accordance with accounting principles generally accepted in the United States of America (“GAAP”) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities as of the date of the financial statements and the reported amounts of revenue and expense during the reporting period. On an ongoing basis, the Manager reviews its estimates, including those related to the fair value of financial instruments, depletion and amortization, determination of proved reserves, impairment of long-lived assets and asset retirement obligations. Actual results may differ from those estimates. |
Fair Value Measurements | Fair Value Measurements The fair value measurement guidance provides a hierarchy that prioritizes and defines the types of inputs used to measure fair value. The fair value hierarchy gives the highest priority to Level 1 inputs, which consist of unadjusted quoted prices for identical instruments in active markets. Level 2 inputs consist of quoted prices for similar instruments. Level 3 inputs are unobservable inputs and include situations where there is little, if any, market activity for the instrument; hence, these inputs have the lowest priority. |
Cash and Cash Equivalents | Cash and Cash Equivalents All highly liquid investments with maturities, when purchased, of three months or less, are considered cash equivalents. These balances, as well as cash on hand, are included in “Cash and cash equivalents” on the balance sheet. As of December 31, 2016, the Fund had no cash equivalents. At times, deposits may be in excess of federally insured limits, which are $250 thousand per insured financial institution. As of December 31, 2016, the Fund’s bank balances were maintained in uninsured bank accounts at Wells Fargo Bank, N.A. |
Salvage Fund | Salvage Fund The Fund deposits in a separate interest-bearing account, or salvage fund, cash to provide for the dismantling and removal of production platforms and facilities and plugging and abandoning its wells at the end of their useful lives in accordance with applicable federal and state laws and regulations. Interest earned on the account will become part of the salvage fund. There are no restrictions on withdrawals from the salvage fund. |
Investment in Delta House | Investment in Delta House The Fund has investments in Delta House Oil and Gas Lateral, LLC and Delta House FPS, LLC (collectively “Delta House”), legal entities that own interests in a deepwater floating production system operated by LLOG Exploration Company. The Fund accounts for its investment in Delta House using the cost method of accounting for investments as it does not have the ability to exercise significant influence over such investment. Under the cost method, the Fund recognizes an investment in the equity of an investee at cost. The Fund recognizes as income dividends received that are distributed from net accumulated earnings of the investee since the date of acquisition by the Fund. Dividends received in excess of earnings subsequent to the date of investment are considered a return of investment and are recorded as reductions of cost of the investment. The Fund reviews its cost method investment for impairment at each reporting period and when an event or change in circumstances has occurred that may have a significant adverse effect on the fair value of the investment. Losses on cost method investments including impairments that are deemed to be other than temporary are classified as non-operating losses in the Fund’s statements of operations. As of December 31, 2016, the Fund invested a total of $0.6 million in Delta House and has received cash from its investment totaling $0.6 million, of which $0.3 million relates to dividends received and $0.3 million relates to cash proceeds from the sale of approximately 74% of its investment, pursuant to a unit purchase agreement with D-Day Offshore Holdings, LLC dated October 31, 2016. Certain other funds managed by the Manager were also parties to this unit purchase agreement. The Fund adjusted the carrying value of its investment in Delta House in third quarter 2016 to fair value, which was determined based on the third party sale and recorded a loss on investment during the year ended December 31, 2016 of $0.1 million. The loss was included on the Fund’s statement of operations within “Loss on investment in Delta House”. Inputs used to estimate fair value of the investment in Delta House are categorized as Level 3 in the fair value hierarchy. As of December 31, 2016, the Fund’s remaining carrying value for the investment in Delta House was $0.1 million. |
Oil and Gas Properties | Oil and Gas Properties The Fund invests in oil and gas properties, which are operated by unaffiliated entities that are responsible for drilling, administering and producing activities pursuant to the terms of the applicable operating agreements with working interest owners. The Fund’s portion of exploration, drilling, operating and capital equipment expenditures is billed by operators. Acquisition, exploration and development costs are accounted for using the successful efforts method. Costs of acquiring unproved and proved oil and natural gas leasehold acreage, including lease bonuses, brokers’ fees and other related costs are capitalized. Costs of drilling and equipping productive wells and related production facilities are capitalized. The costs of exploratory wells are capitalized pending determination of whether proved reserves have been found. If proved commercial reserves are not found, exploratory well costs are expensed as dry-hole costs. At times, the Fund receives adjustments to certain wells from their respective operators upon review and audit of the wells’ costs. Annual lease rentals and exploration expenses are expensed as incurred. All costs related to production activity, transportation expense and workover efforts are expensed as incurred. Once a well has been determined to be fully depleted or upon the sale, retirement or abandonment of a property, the cost and related accumulated depletion and amortization, if any, is eliminated from the property accounts, and the resultant gain or loss is recognized. As of December 31, 2016 and 2015, amounts recorded in due to operators totaling $37 thousand related to capital expenditures for oil and gas properties. |
Advances to Operators for Working Interests and Expenditures | Advances to Operators for Working Interests and Expenditures The Fund may be required to advance its share of the estimated succeeding month’s expenditures to the operator for its oil and gas properties. As the costs are incurred, the advances are reclassified to proved properties. |
Asset Retirement Obligations | Asset Retirement Obligations For oil and gas properties, there are obligations to perform removal and remediation activities when the properties are retired. Upon the determination that a property is either proved or dry, a retirement obligation is incurred. The Fund recognizes the fair value of a liability for an asset retirement obligation in the period incurred. Plug and abandonment costs associated with unsuccessful projects are expensed as dry-hole costs. At least bi-annually, or more frequently if an event occurs that would dictate a change in assumptions or estimates underlying the obligations, the Fund reassesses all of its asset retirement obligations to determine whether any revisions to the obligations are necessary. The following table presents changes in asset retirement obligations during the years ended December 31, 2016 and 2015. 2016 2015 (in thousands) Balance, beginning of year $ 2,525 $ 1,571 Liabilities incurred - 36 Liabilities settled (521 ) - Accretion expense 64 140 Revision of estimates (31 ) 778 Balance, end of year $ 2,037 $ 2,525 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. |
Impairment of Long-Lived Assets | Impairment of Long-Lived Assets The Fund reviews the carrying value of its oil and gas properties annually and when management determines that events and circumstances indicate that the recorded carrying value of properties may not be recoverable. Impairments are determined by comparing estimated future net undiscounted cash flows to the carrying value at the time of the review. If the carrying value exceeds the estimated future net undiscounted cash flows, the carrying value of the asset is written down to fair value, which is determined using estimated future net discounted cash flows from the asset. The fair value determinations require considerable judgment and are sensitive to change. Different pricing assumptions, reserve estimates or discount rates could result in a different calculated impairment. Given the volatility of oil and natural gas prices, it is reasonably possible that the Fund’s estimate of discounted future net cash flows from proved oil and natural gas reserves could change in the near term. Significant and consistent fluctuations in oil and natural gas prices since fourth quarter 2014 have impacted the fair value of the Fund’s oil and gas properties. If oil and natural gas prices decline, even if only for a short period of time, it is possible that impairments of oil and gas properties will occur. |
Depletion and Amortization | Depletion and Amortization Depletion and amortization of the cost of proved oil and gas properties are calculated using the units-of-production method. Proved developed reserves are used as the base for depleting capitalized costs associated with successful exploratory well costs, development costs and related facilities. The sum of proved developed and proved undeveloped reserves is used as the base for depleting or amortizing leasehold acquisition costs. During the year ended December 31, 2015, the Fund recorded $0.4 million of depletion expense related to adjustments to asset retirement obligations for fully depleted properties. |
Income Taxes | Income Taxes No provision is made for income taxes in the financial statements. The Fund is a limited liability company, and as such, the Fund’s income or loss is passed through and included in the tax returns of the Fund’s shareholders. The Fund files U.S. Federal and State tax returns and the 2013 through 2015 tax returns remain open for examination by tax authorities. |
Income and Expense Allocation | Income and Expense Allocation Profits and losses are allocated to shareholders and the Manager in accordance with the LLC Agreement. |
Distributions | Distributions Distributions to shareholders are allocated in proportion to the number of shares held. The Manager determines whether available cash from operations, as defined in the LLC Agreement, will be distributed. Such distributions are allocated 85% to the shareholders and 15% to the Manager, as required by the LLC Agreement. Available cash from dispositions, as defined in the LLC Agreement, will be paid 99% to shareholders and 1% to the Manager until the shareholders have received total distributions equal to their capital contributions. After shareholders have received distributions equal to their capital contributions, 85% of available cash from dispositions will be distributed to shareholders and 15% to the Manager. |
Recent Accounting Pronouncements | Recent Accounting Pronouncements In January 2016, the Financial Accounting Standards Board (“FASB”) issued accounting guidance that requires, among other things, companies to measure investments in other entities, except those accounted for under the equity method, at fair value and recognize any changes in fair value in net income unless an election is made to record the investment at cost, less impairment and plus or minus subsequent adjustments for observable price changes with change in basis reported in current earnings. This pronouncement is effective for fiscal years beginning after December 15, 2017 and interim periods within those fiscal years, with early adoption not permitted. The Fund is currently evaluating the impact of this guidance on its financial statements. In May 2014, the FASB issued accounting guidance on revenue recognition, which provides for a single five-step model to be applied to all revenue contracts with customers. In July 2015, the FASB issued a deferral of the effective date of the guidance to 2018, with early adoption permitted in 2017. In March 2016, the FASB issued accounting guidance, which clarifies the implementation guidance on principal versus agent considerations in the new revenue recognition standard. In April 2016, the FASB issued guidance on identifying performance obligations and licensing and in May 2016, the FASB issued final amendments which provided narrow scope improvements and practical expedients related to the implementation of the guidance. The accounting guidance may be applied either retrospectively or through the use of a modified-retrospective method. Based on the Fund’s initial assessment of the accounting guidance, the Fund currently does not expect it will have a material impact on its results of operations or cash flows in the period after adoption. Under the accounting guidance, revenue is recognized as control transfers to the customer, as such the Fund expects the application of the accounting guidance to its existing contracts to be generally consistent with its current revenue recognition model. The Fund will continue the evaluation of the provisions of this accounting guidance, as well as new or emerging interpretations, as it relates to new contracts the Fund receives and in particular as it relates to disclosure requirements through the date of adoption, which is currently expected to be January 1, 2018. |
Organization and Summary of S12
Organization and Summary of Significant Accounting Policies (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Schedule of Changes in Asset Retirement Obligations | 2016 2015 (in thousands) Balance, beginning of year $ 2,525 $ 1,571 Liabilities incurred - 36 Liabilities settled (521 ) - Accretion expense 64 140 Revision of estimates (31 ) 778 Balance, end of year $ 2,037 $ 2,525 |
Information about Oil and Gas13
Information about Oil and Gas Producing Activities (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Information About Oil And Gas Producing Activities [Abstract] | |
Schedule of Capitalized Costs Relating to Oil and Gas Producing Activities | Table I - Capitalized Costs Relating to Oil and Gas Producing Activities December 31, 2016 2015 (in thousands) Proved properties $ 17,031 $ 17,096 Total oil and gas properties 17,031 17,096 Accumulated depletion and amortization (10,541 ) (8,524 ) Oil and gas properties, net $ 6,490 $ 8,572 |
Schedule of Costs Incurred in Oil and Gas Property Acquisition, Exploration, and Development | Table II - Costs Incurred in Oil and Gas Property Acquisition, Exploration, and Development Year ended December 31, 2016 2015 (in thousands) Exploration costs $ 20 $ 5 Development costs (4 ) 3,655 $ 16 $ 3,660 |
Schedule of Reserve Quantity Information | Table III - Reserve Quantity Information Oil and gas reserves of the Fund have been estimated by independent petroleum engineers, Netherland, Sewell & Associates, Inc. at December 31, 2016 and 2015. These reserve disclosures have been prepared in compliance with the Securities and Exchange Commission rules. Due to inherent uncertainties and the limited nature of recovery data, estimates of reserve information are subject to change as additional information becomes available. December 31, 2016 December 31, 2015 United States Oil (BBLS) NGL (BBLS) Gas (MCF) Oil (BBLS) NGL (BBLS) Gas (MCF) Proved developed and undeveloped reserves: Beginning of year 583,481 108,454 1,237,695 546,116 28,486 1,578,796 Revisions of previous estimates (a) 5,860 83,909 434,552 103,223 90,272 (228,885 ) Production (106,251 ) (9,842 ) (193,266 ) (65,858 ) (10,304 ) (112,216 ) End of year 483,090 182,521 1,478,981 583,481 108,454 1,237,695 Proved developed reserves: Beginning of year 374,821 63,311 788,355 69,495 28,486 406,564 End of year 367,710 115,471 988,551 374,821 63,311 788,355 Proved undeveloped reserves: Beginning of year 208,660 45,143 449,340 476,621 - 1,172,232 End of year 115,380 67,050 490,430 208,660 45,143 449,340 (a) Revisions of previous estimates were attributable to well performance. |
Schedule of Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves | Table IV - Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves Summarized in the following table is information for the Fund with respect to the standardized measure of discounted future net cash flows relating to proved oil and gas reserves. Future cash inflows were determined based on average first-of-the-month pricing for the prior twelve-month period. Future production and development costs are derived based on current costs assuming continuation of existing economic conditions. December 31, 2016 2015 (in thousands) Future cash inflows $ 23,263 $ 32,530 Future production costs (9,266 ) (11,944 ) Future development costs (5,581 ) (7,150 ) Future net cash flows 8,416 13,436 10% annual discount for estimated timing of cash flows (1,230 ) (4,043 ) Standardized measure of discounted future net cash flows $ 7,186 $ 9,393 |
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, 2016 2015 (in thousands) Net change in sales and transfer prices and in production costs $ (4,683 ) $ (16,013 ) Sales and transfers of oil and gas produced during the period (2,399 ) (1,613 ) Changes in estimated future development costs 1,569 (786 ) Net change due to revisions in quantities estimates 2,125 2,489 Accretion of discount 939 2,404 Other 242 (1,124 ) Aggregate change in the standardized measure of discounted future net $ (2,207 ) $ (14,643 ) |
Organization and Summary of S14
Organization and Summary of Significant Accounting Policies (Narrative) (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Organization and Summary of Significant Accounting Policies [Abstract] | ||
Maximum cash balance federally insured per financial institution | $ 250 | |
Cash proceeds from sale of investment in Delta House | 339 | |
Loss on investment in Delta House | (114) | |
Investment in Delta House | 119 | 572 |
Value of capital expenditures for oil and gas properties owed to operators | $ 37 | 37 |
Depletion | $ 400 | |
Percentage of cash from operations allocated to shareholders | 85.00% | |
Percentage of cash from operations allocated to fund manager | 15.00% | |
Percentage of available cash from dispositions allocated to shareholders | 99.00% | |
Percentage of available cash from dispositions allocated to fund manager | 1.00% | |
Percentage of available cash from dispositions allocated to shareholders after distributions have equaled capital contributions | 85.00% | |
Percentage of available cash from dispositions allocated to fund manager after distributions have equaled capital contributions | 15.00% | |
Delta House [Member] | ||
Organization and Summary of Significant Accounting Policies [Abstract] | ||
Total investment in Delta House | $ 600 | |
Dividends on investment in Delta House | 300 | |
Cash proceeds from sale of investment in Delta House | $ 339 | |
Ownership percentage prior to sale | 74.00% |
Organization and Summary of S15
Organization and Summary of Significant Accounting Policies (Schedule of Changes in Asset Retirement Obligations) (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | ||
Balance, beginning of year | $ 2,525 | $ 1,571 |
Liabilities incurred | 36 | |
Liabilities settled | (521) | |
Accretion expense | 64 | 140 |
Revision of estimates | (31) | 778 |
Balance, end of year | $ 2,037 | $ 2,525 |
Related Parties (Details)
Related Parties (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Related Party Transaction [Line Items] | ||
Annual management fee percentage rate | 2.50% | |
Annual management fees paid to Fund Manager | $ 1,083 | $ 1,082 |
Percentage of total distributions allocated to Fund Manager | 15.00% | |
Distributions | $ (868) | (562) |
Manager [Member] | ||
Related Party Transaction [Line Items] | ||
Distributions | $ (130) | $ (84) |
Commitments and Contingencies (
Commitments and Contingencies (Details) $ in Thousands | 12 Months Ended |
Dec. 31, 2016USD ($) | |
Commitments and Contingencies Disclosure [Abstract] | |
Commitments for the drilling and development of investment properties | $ 6,600 |
Commitments for asset retirement obligations included in estimated capital commitments | 3,200 |
Commitments for the drilling and development of investment properties expected to be incurred in the next 12 months | $ 600 |
Information about Oil and Gas18
Information about Oil and Gas Producing Activities (Schedule of Capitalized Costs Relating to Oil and Gas Producing Activities) (Details) - USD ($) $ in Thousands | Dec. 31, 2016 | Dec. 31, 2015 |
Information About Oil And Gas Producing Activities [Abstract] | ||
Proved properties | $ 17,031 | $ 17,096 |
Total oil and gas properties | 17,031 | 17,096 |
Accumulated depletion and amortization | (10,541) | (8,524) |
Total oil and gas properties, net | $ 6,490 | $ 8,572 |
Information about Oil and Gas19
Information about Oil and Gas Producing Activities (Schedule of Costs Incurred in Oil and Gas Property Acquisition, Exploration, and Development) (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Information About Oil And Gas Producing Activities [Abstract] | ||
Exploration costs | $ 20 | $ 5 |
Development costs | (4) | 3,655 |
Total costs | $ 16 | $ 3,660 |
Information about Oil and Gas20
Information about Oil and Gas Producing Activities (Schedule of Reserve Quantity Information) (Details) | 12 Months Ended | ||
Dec. 31, 2016bblMcf | Dec. 31, 2015bblMcf | ||
Oil (BBLS) [Member] | |||
Proved developed and undeveloped reserves: | |||
Beginning of year | 583,481 | 546,116 | |
Revisions of previous estimates | [1] | 5,860 | 103,223 |
Production | (106,251) | (65,858) | |
End of year | 483,090 | 583,481 | |
Proved developed reserves: | |||
Beginning of year | 374,821 | 69,495 | |
End of year | 367,710 | 374,821 | |
Proved undeveloped reserves: | |||
Beginning of year | 208,660 | 476,621 | |
End of year | 115,380 | 208,660 | |
NGL (BBLS) [Member] | |||
Proved developed and undeveloped reserves: | |||
Beginning of year | 108,454 | 28,486 | |
Revisions of previous estimates | [1] | 83,909 | 90,272 |
Production | (9,842) | (10,304) | |
End of year | 182,521 | 108,454 | |
Proved developed reserves: | |||
Beginning of year | 63,311 | 28,486 | |
End of year | 115,471 | 63,311 | |
Proved undeveloped reserves: | |||
Beginning of year | 45,143 | ||
End of year | 67,050 | 45,143 | |
Gas (MCF) [Member] | |||
Proved developed and undeveloped reserves: | |||
Beginning of year | Mcf | 1,237,695 | 1,578,796 | |
Revisions of previous estimates | Mcf | [1] | 434,552 | (228,885) |
Production | Mcf | (193,266) | (112,216) | |
End of year | Mcf | 1,478,981 | 1,237,695 | |
Proved developed reserves: | |||
Beginning of year | Mcf | 788,355 | 406,564 | |
End of year | Mcf | 988,551 | 788,355 | |
Proved undeveloped reserves: | |||
Beginning of year | Mcf | 449,340 | 1,172,232 | |
End of year | Mcf | 490,430 | 449,340 | |
[1] | Revisions of previous estimates were attributable to well performance. |
Information about Oil and Gas21
Information about Oil and Gas Producing Activities (Schedule of Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves) (Details) - USD ($) $ in Thousands | Dec. 31, 2016 | Dec. 31, 2015 |
Information About Oil And Gas Producing Activities [Abstract] | ||
Future cash inflows | $ 23,263 | $ 32,530 |
Future production costs | (9,266) | (11,944) |
Future development costs | (5,581) | (7,150) |
Future net cash flows | 8,416 | 13,436 |
10% annual discount for estimated timing of cash flows | (1,230) | (4,043) |
Standardized measure of discounted future net cash flows | $ 7,186 | $ 9,393 |
Information about Oil and Gas22
Information about Oil and Gas Producing Activities (Schedule of Changes in the Standardized Measure for Discounted Cash Flows) (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2016 | Dec. 31, 2015 | |
Information About Oil And Gas Producing Activities [Abstract] | ||
Net change in sales and transfer prices and in production costs related to future production | $ (4,683) | $ (16,013) |
Sales and transfers of oil and gas produced during the period | (2,399) | (1,613) |
Changes in estimated future development costs | 1,569 | (786) |
Net change due to revisions in quantities estimates | 2,125 | 2,489 |
Accretion of discount | 939 | 2,404 |
Other | 242 | (1,124) |
Aggregate change in the standardized measure of discounted future net cash flows for the year | $ (2,207) | $ (14,643) |