Document_and_Entity_Informatio
Document and Entity Information (USD $) | 12 Months Ended | |
Dec. 31, 2014 | Feb. 24, 2015 | |
Document And Entity Information [Abstract] | ||
Document Type | 10-K | |
Amendment Flag | FALSE | |
Document Period End Date | 31-Dec-14 | |
Entity Registrant Name | RIDGEWOOD ENERGY A-1 FUND LLC | |
Entity Central Index Key | 1457919 | |
Current Fiscal Year End Date | -19 | |
Document Fiscal Period Focus | FY | |
Document Fiscal Year Focus | 2014 | |
Entity Filer Category | Smaller Reporting Company | |
Entity Units Outstanding | 207.7026 | |
Entity Current Reporting Status | Yes | |
Entity Well-known Seasoned Issuer | No | |
Entity Voluntary Filers | No | |
Entity Public Float | $0 |
BALANCE_SHEETS
BALANCE SHEETS (USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
In Thousands, unless otherwise specified | ||
Current assets: | ||
Cash and cash equivalents | $5,045 | $4,690 |
Production receivable | 98 | 962 |
Asset held for sale | 1,266 | |
Other current assets | 21 | 72 |
Total current assets | 5,164 | 6,990 |
Salvage fund | 1,780 | 1,763 |
Other assets | 366 | 488 |
Oil and gas properties: | ||
Advances to operators for working interests and expenditures | 68 | |
Proved properties | 9,763 | 15,735 |
Equipment and facilities - in progress | 4,934 | 1,842 |
Less: accumulated depletion, depreciation and amortization | -6,318 | -11,547 |
Total oil and gas properties, net | 8,379 | 6,098 |
Total assets | 15,689 | 15,339 |
Current liabilities: | ||
Due to operators | 914 | 1,241 |
Accrued expenses | 33 | 39 |
Liability held for sale | 684 | |
Total current liabilities | 947 | 1,964 |
Asset retirement obligations | 965 | 946 |
Long-term borrowings | 1,800 | |
Other liabilities | 48 | |
Total liabilities | 3,760 | 2,910 |
Commitments and contingencies (Note 5) | ||
Members' capital: | ||
Distributions | -5,045 | -4,480 |
Retained earnings | 5,152 | 4,844 |
Manager's total | 107 | 364 |
Capital contributions (250 shares authorized; 207.7026 issued and outstanding) | 41,143 | 41,143 |
Syndication costs | -4,804 | -4,804 |
Distributions | -35,351 | -25,389 |
Retained earnings | 10,830 | 1,118 |
Shareholders' total | 11,818 | 12,068 |
Accumulated other comprehensive income (loss) | 4 | -3 |
Total members' capital | 11,929 | 12,429 |
Total liabilities and members' capital | $15,689 | $15,339 |
BALANCE_SHEETS_Parenthetical
BALANCE SHEETS (Parenthetical) | Dec. 31, 2014 | Dec. 31, 2013 |
BALANCE SHEETS [Abstract] | ||
Shares authorized | 250 | 250 |
Shares issued | 207.7026 | 207.7026 |
Shares outstanding | 207.7026 | 207.7026 |
STATEMENTS_OF_OPERATIONS_AND_C
STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME (USD $) | 12 Months Ended | |
In Thousands, except Per Share data, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 |
Revenue | ||
Oil and gas revenue | $3,045 | $12,337 |
Expenses | ||
Depletion, depreciation and amortization | 1,198 | 3,336 |
Impairment of oil and gas properties | 646 | |
Management fees to affiliate (Note 3) | 632 | 929 |
Operating expenses | 788 | 2,450 |
General and administrative expenses | 173 | 278 |
Total expenses | 3,437 | 6,993 |
Gain on sale of oil and gas properties | 10,396 | |
Income from operations | 10,004 | 5,344 |
Interest income | 16 | 16 |
Net income | 10,020 | 5,360 |
Other comprehensive income (loss) | ||
Unrealized gain (loss) on marketable securities | 7 | -18 |
Total comprehensive income | 10,027 | 5,342 |
Manager Interest | ||
Net income | 308 | 1,274 |
Shareholder Interest | ||
Net income | $9,712 | $4,086 |
Net income per share | $46,762 | $19,671 |
STATEMENTS_OF_CHANGES_IN_MEMBE
STATEMENTS OF CHANGES IN MEMBERS' CAPITAL (USD $) | 12 Months Ended | |
In Thousands, except Share data, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 |
Balances | $12,429 | $15,312 |
Balances, shares | 207.7026 | |
Distributions | -10,527 | -8,225 |
Net income | 10,020 | 5,360 |
Other comprehensive income (loss) | 7 | -18 |
Balances | 11,929 | 12,429 |
Balances, shares | 207.7026 | 207.7026 |
# of Shares [Member] | ||
Balances, shares | 207.7026 | 207.7026 |
Distributions | ||
Net income | ||
Other comprehensive income (loss) | ||
Balances, shares | 207.7026 | 207.7026 |
Fund Manager [Member] | ||
Balances | 364 | 324 |
Distributions | -565 | -1,234 |
Net income | 308 | 1,274 |
Other comprehensive income (loss) | ||
Balances | 107 | 364 |
Shareholders [Member] | ||
Balances | 12,068 | 14,973 |
Distributions | -9,962 | -6,991 |
Net income | 9,712 | 4,086 |
Other comprehensive income (loss) | ||
Balances | 11,818 | 12,068 |
Accumulated Other Comprehensive Income (Loss) [Member] | ||
Balances | -3 | 15 |
Distributions | ||
Net income | ||
Other comprehensive income (loss) | 7 | -18 |
Balances | $4 | ($3) |
STATEMENTS_OF_CASH_FLOWS
STATEMENTS OF CASH FLOWS (USD $) | 12 Months Ended | |
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 |
Cash flows from operating activities | ||
Net income | $10,020 | $5,360 |
Adjustments to reconcile net income to net cash provided by operating activities: | ||
Depletion, depreciation and amortization | 1,198 | 3,336 |
Impairment of oil and gas properties | 646 | |
Accretion expense | 19 | 18 |
Gain on sale of oil and gas properties | -10,396 | |
Changes in assets and liabilities: | ||
Decrease in production receivable | 864 | 766 |
Decrease (increase) in other current assets | 51 | -21 |
(Decrease) increase in due to operators | -355 | 279 |
(Decrease) increase in accrued expenses | -6 | 2 |
Net cash provided by operating activities | 2,041 | 9,740 |
Cash flows from investing activities | ||
Payments to operators for working interests and expenditures | -68 | |
Proceeds from sale of oil and gas properties | 10,978 | |
Capital expenditures for oil and gas properties | -3,927 | -1,326 |
Investments in salvage fund | -10 | -476 |
Net cash provided by (used in) investing activities | 7,041 | -1,870 |
Cash flows from financing activities | ||
Long-term borrowings | 1,800 | |
Distributions | -10,527 | -8,225 |
Net cash used in financing activities | -8,727 | -8,225 |
Net increase (decrease) in cash and cash equivalents | 355 | -355 |
Cash and cash equivalents, beginning of year | 4,690 | 5,045 |
Cash and cash equivalents, end of year | 5,045 | 4,690 |
Supplemental schedule of non-cash investing activities | ||
Advances used for capital expenditures in oil and gas properties reclassified to proved properties | $68 |
Organization_and_Summary_of_Si
Organization and Summary of Significant Accounting Policies | 12 Months Ended | ||||||||||||
Dec. 31, 2014 | |||||||||||||
Organization and Summary of Significant Accounting Policies [Abstract] | |||||||||||||
Organization and Summary of Significant Accounting Policies | 1. Organization and Summary of Significant Accounting Policies | ||||||||||||
Organization | |||||||||||||
The Ridgewood Energy A-1 Fund, LLC (the "Fund"), a Delaware limited liability company, was formed on February 3, 2009 and operates pursuant to a limited liability company agreement (the “LLC Agreement") dated as of March 2, 2009 by and among Ridgewood Energy Corporation (the "Manager") and the shareholders of the Fund, which addresses matters such as the authority and voting rights of the Manager and shareholders, capitalization, transferability of membership interests, participation in costs and revenues, distribution of assets and dissolution and winding up. The Fund was organized to primarily acquire interests in oil and gas properties located in the United States offshore waters of Texas, Louisiana and Alabama in the Gulf of Mexico. | |||||||||||||
The Manager has direct and exclusive control over the management of the Fund's operations. With respect to project investments, the Manager locates potential projects, conducts due diligence, and negotiates and completes the transactions in which the investments are made. The Manager performs, or arranges for the performance of, the management, advisory and administrative services required for Fund operations. Such services include, without limitation, the administration of shareholder accounts, shareholder relations and the preparation, review and dissemination of tax and other financial information. In addition, the Manager provides office space, equipment and facilities and other services necessary for Fund operations. The Manager also engages and manages the contractual relations with unaffiliated custodians, depositories, accountants, attorneys, broker-dealers, corporate fiduciaries, insurers, banks and others as required. See Notes 3, 4 and 5. | |||||||||||||
Use of Estimates | |||||||||||||
The preparation of financial statements in accordance with accounting principles generally accepted in the United States of America (“GAAP”) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities as of the date of the financial statements and the reported amounts of revenue and expense during the reporting period. On an ongoing basis, the Manager reviews its estimates, including those related to the fair value of financial instruments, property balances, determination of proved reserves, impairments and asset retirement obligations. Actual results may differ from those estimates. | |||||||||||||
Fair Value Measurements | |||||||||||||
The fair value measurement guidance provides a hierarchy that prioritizes and defines the types of inputs used to measure fair value. The fair value hierarchy gives the highest priority to Level 1 inputs, which consists of unadjusted quoted prices for identical instruments in active markets. Level 2 inputs consist of quoted prices for similar instruments. Level 3 valuations are derived from inputs that are significant and unobservable; hence, these valuations have the lowest priority. Cash and cash equivalents approximate fair value based on Level 1 inputs. Mortgage-backed securities are recorded based on Level 2 inputs, as such instruments trade in over-the-counter markets. | |||||||||||||
Cash and Cash Equivalents | |||||||||||||
All highly liquid investments with maturities, when purchased, of three months or less, are considered cash and cash equivalents. At times, deposits may be in excess of federally insured limits, which are $250 thousand per insured financial institution. At December 31, 2014, 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, money to provide for the dismantling and removal of production platforms and facilities and plugging and abandoning its wells at the end of their useful lives in accordance with applicable federal and state laws and regulations. At December 31, 2014 and 2013, the Fund had investments in federal agency mortgage-backed securities as detailed in the following table, which are classified as available for sale. Available-for-sale securities are carried in the financial statements at fair value. | |||||||||||||
Amortized | Gross | Fair | |||||||||||
Unrealized | |||||||||||||
Cost | Gains (Losses) | Value | |||||||||||
(in thousands) | |||||||||||||
Government National Mortgage Association securities (GNMA July 2041) | |||||||||||||
December 31, 2014 | $ | 84 | $ | 3 | $ | 87 | |||||||
December 31, 2013 | $ | 90 | $ | 1 | $ | 91 | |||||||
Federal National Mortgage Association security (FNMA January 2042) | |||||||||||||
December 31, 2014 | $ | 109 | $ | 1 | $ | 110 | |||||||
December 31, 2013 | $ | 198 | $ | (4 | ) | $ | 194 | ||||||
The unrealized gains and losses on the Fund's investments in federal agency mortgage-backed securities were the result of fluctuations in market interest rates. The contractual cash flows of those investments are guaranteed by an agency of the U.S. government. It is expected that the securities would not be settled at a price less than the amortized cost basis of the Fund's investments. Unrealized gains or losses on available-for-sale securities are reported in other comprehensive income until realized. | |||||||||||||
For all investments, interest income is accrued as earned and amortization of premium or discount, if any, is included in interest income. Interest earned on the account will become part of the salvage fund. There are no restrictions on withdrawals from the salvage fund. | |||||||||||||
Debt Discounts and Deferred Financing Costs | |||||||||||||
Debt discounts and deferred financing costs include lender fees and other costs of acquiring the debt (see Note 4. “Credit Agreement – Beta Project Financing”) such as the conveyance of override royalty interests related to the Beta Project. These costs are deferred and amortized over the term of the debt period or until the redemption of the debt and are included on the balance sheet within “Other assets”. At December 31, 2014 and 2013, $0.4 million and $0.5 million, respectively, of debt discounts and deferred financing costs were unamortized. Amortization expense was $0.1 million during each of the years ended December 31, 2014 and 2013. 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”. | |||||||||||||
Oil and Gas Properties | |||||||||||||
The Fund invests in oil and gas properties, which are operated by unaffiliated entities that are responsible for drilling, administering and producing activities pursuant to the terms of the applicable operating agreements with working interest owners. The Fund's portion of exploration, drilling, operating and capital equipment expenditures is billed by operators. | |||||||||||||
Exploration, development and acquisition costs are accounted for using the successful efforts method. Costs of acquiring unproved and proved oil and natural gas leasehold acreage, including lease bonuses, brokers' fees and other related costs are capitalized. Costs of drilling and equipping productive wells and related production facilities are capitalized. Costs of developing production facilities and pipelines that service multiple oil and gas properties are segregated as “Equipment and facilities - in progress.” Exploratory costs are capitalized pending determination of whether proved reserves have been found. If proved commercial reserves are not found, exploratory 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 4. “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 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, depreciation and amortization, if any, is eliminated from the property accounts, and the resultant gain or loss is recognized. | |||||||||||||
At December 31, 2014 and 2013, amounts recorded in due to operators totaling $0.8 million and $0.7 million, respectively, related to capital expenditures for oil and gas properties. | |||||||||||||
Advances to Operators for Working Interests and Expenditures | |||||||||||||
The Fund's acquisition of a working interest in an oil and gas property requires it to make a payment to the seller for the Fund's rights, title and interest. The Fund may be required to advance its share of estimated cash expenditures for the succeeding month's operation. The Fund accounts for such payments as advances to operators for working interests and expenditures. As drilling costs are incurred, the advances are reclassified to unproved or proved properties. | |||||||||||||
Asset Retirement Obligations | |||||||||||||
For oil and gas properties, there are obligations to perform removal and remediation activities when the properties are retired. When a project reaches drilling depth and is determined to be either proved or dry, an asset retirement obligation is incurred. Plug and abandonment costs associated with unsuccessful projects are expensed as dry-hole costs. The following table presents changes in asset retirement obligations for the years ended December 31, 2014 and 2013. | |||||||||||||
2014 | 2013 | ||||||||||||
(in thousands) | |||||||||||||
Balance, beginning of year | $ | 946 | $ | 1,131 | |||||||||
Liabilities relieved/settled | - | (684 | ) | ||||||||||
Accretion expense | 19 | 18 | |||||||||||
Revisions in estimated cash flows | - | 481 | |||||||||||
Balance, end of year | $ | 965 | $ | 946 | |||||||||
At December 31, 2013, the Fund's balance sheet reflects the reclassification of the Raven Project's asset retirement obligation from “Asset retirement obligation” to “Liability held for sale”. On January 17, 2014, the Fund entered into an agreement to sell its interest in the Raven Project to a third party. | |||||||||||||
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, when delivery has occurred and title has transferred, and if collectability of the revenue is probable. 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 value of its oil and gas properties whenever management determines that events and circumstances indicate that the recorded carrying value of properties may not be recoverable. Impairments of proved properties are determined by comparing future net undiscounted cash flows to the net book value at the time of the review. If the net book value exceeds the future net undiscounted cash flows, the carrying value of the property is written down to fair value, which is determined using net discounted future cash flows from the property. The Fund provides for impairments on unproved properties when it determines that the property will not be developed or a permanent impairment in value has occurred. 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. If oil and natural gas prices decline significantly, even if only for a short period of time, it is possible that write-downs of oil and gas properties could occur. | |||||||||||||
During January 2015, the Carrera Project was shut-in due to ongoing mechanical issues related to a blockage in the flowline. Upon evaluation, it was determined that estimated costs to bring the well back on production were not economic relative to the remaining reserves and the well was fully impaired. Accordingly, during the year ended December 31, 2014, the Fund recorded an impairment of oil and gas properties of $0.6 million, representing the remaining net book value of the well at the date of impairment. The Fund did not record an impairment of oil and gas properties during the year ended December 31, 2013. | |||||||||||||
Depletion, Depreciation and Amortization | |||||||||||||
Depletion, depreciation 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. In certain circumstances, equipment and facilities costs are depreciated over the estimated useful life of the asset. | |||||||||||||
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 2010 through 2013 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. During the year ended December 31, 2014, the Fund made distributions of available cash from dispositions related to the sale of the Raven Project totaling $7.2 million. There were no such distributions during the year ended December 31, 2013. | |||||||||||||
Recent Accounting Pronouncements | |||||||||||||
The Fund has considered recent accounting pronouncements and believes that these recent pronouncements will not have a material effect on the Fund's financial statements. |
Oil_and_Gas_Properties
Oil and Gas Properties | 12 Months Ended |
Dec. 31, 2014 | |
Oil and Gas Properties [Abstract] | |
Oil and Gas Properties | 2. Oil and Gas Properties |
On January 17, 2014, the Fund, along with its affiliates, Ridgewood Energy Gulf of Mexico Oil and Gas Fund, L.P., Ridgewood Energy P Fund, LLC, Ridgewood Energy W Fund, LLC, and Ridgewood Energy Y Fund, LLC, (when used with the Fund the “Ridgewood Funds”) entered into a purchase and sale agreement to sell the Ridgewood Funds' interests in the Raven Project, located in the state waters of Louisiana, to Castex Energy Partners, L.P. for cash consideration totaling $21.7 million. The closing of the sale transaction occurred on January 30, 2014. | |
The Fund had a 25% working interest in the Raven Project and received $11.0 million in cash proceeds from the sale. The net carrying value for the Raven Project on the date of the sale was $0.6 million, thereby resulting in a gain to the Fund of $10.4 million, which was recognized during the year ended December 31, 2014. There was no such amount recorded during the year ended December 31, 2013. | |
At December 31, 2013, the Fund's balance sheet reflected the Raven Project's cost and accumulated depletion classified as “Asset held for sale”, which totaled $1.3 million, and the Raven Project's asset retirement obligation classified as “Liability held for sale”, which totaled $0.7 million. Such asset was monetized and obligation was relieved upon the closing of the Raven Project's sale. |
Related_Parties
Related Parties | 12 Months Ended |
Dec. 31, 2014 | |
Related Parties [Abstract] | |
Related Parties | 3. 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 paid 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. Management fees for the years ended December 31, 2014 and 2013 were $0.6 million and $0.9 million, respectively. | |
The Manager is entitled to receive a 15% interest in cash distributions from operations made by the Fund. Distributions from operations paid to the Manager for the years ended December 31, 2014 and 2013 were $0.6 million and $1.2 million, respectively. In addition, the Manager is entitled to receive a 1% interest in cash distributions from dispositions. Distributions from the sale of the Raven project paid to the Manager during the year ended December 31, 2014 were $0.1 million. There were no such distributions during the year ended December 31, 2013. | |
At times, short-term payables and receivables, which do not bear interest, arise from transactions with affiliates in the ordinary course of business. | |
None of the amounts paid to the Manager have been derived as a result of arm's length negotiations. | |
The Fund has working interest ownership in certain projects to acquire and develop oil and natural gas projects with other entities that are likewise managed by the Manager. |
Credit_Agreement_Beta_Project_
Credit Agreement - Beta Project Financing | 12 Months Ended |
Dec. 31, 2014 | |
Credit Agreement - Beta Project Financing [Abstract] | |
Credit Agreement - Beta Project Financing | 4. Credit Agreement – Beta Project Financing |
In November 2012, the Fund entered into a credit agreement (the “Credit Agreement”) with Rahr Energy Investments LLC, as Administrative Agent and Lender (and any other banks or financial institutions that may in the future become a party thereto, collectively “Lenders”) that provides for an aggregate loan commitment to the Fund of approximately $8.3 million (“Loan”), to provide capital toward the funding of the Fund's share of development costs on the Beta Project. Except in cases of fraud and breach of certain representations, the Loan is non-recourse to the Fund's other assets and secured solely by the Fund's interests in the Beta Project. In addition to the Fund's execution of the Credit Agreement, Ridgewood Energy O Fund, LLC, Ridgewood Energy Q Fund, LLC, Ridgewood Energy S Fund, LLC, Ridgewood Energy T Fund, LLC, Ridgewood Energy V Fund, LLC, Ridgewood Energy W Fund, LLC and Ridgewood Energy B-1 Fund, LLC (“Ridgewood Funds”, and when used with the Fund the “Ridgewood Participating Funds”) have also executed the Credit Agreement. Pursuant to the Credit Agreement, each Ridgewood Participating Fund has a separate loan commitment from the Lenders and amounts borrowed are not joint and several obligations. Each of the Ridgewood Participating Funds' borrowings is secured solely by its separate interest in the Beta Project. Therefore, the Fund is liable for the repayment of its Loan and is not liable to the Lenders to repay any loan made to any other Ridgewood Fund. The Manager serves as the manager for each Ridgewood Participating Fund. | |
The Fund anticipates it will borrow approximately $8.3 million over the development period of the Beta Project, which will bear interest at 8% compounded annually and accrue only on Loan proceeds as they are drawn. Principal and interest will not be payable until such time that initial production has commenced for the Beta Project, which is currently expected in 2016. At that time, if certain revenue production levels are met, principal and interest will be repaid at a monthly rate of 1.25% of the Fund's total principal outstanding at the date the Beta Project commences production for the first seven months of production, and a monthly rate of 4.5% of the Fund's total principal outstanding at the date the Beta Project commences production thereafter until the Loan is repaid in full, in no event later than December 31, 2020. The Loan may be prepaid by the Fund without premium or penalty. As of December 31, 2014, the Fund had borrowings of $1.8 million under the Credit Agreement. As of December 31, 2013, the Fund had no borrowings under the Credit Agreement. During the year ended December 31, 2014, interest costs of $48 thousand were capitalized and included on the balance sheet within “Oil and gas properties”. The Fund had no interest costs during the year ended December 31, 2013. | |
As additional consideration to the Lenders, each Ridgewood Participating Fund has agreed to convey an overriding royalty interest (“ORRI”) in their working interests in the Beta Project. Each Ridgewood Participating Fund's share of the Lender's aggregate ORRI is directly proportionate to its level of borrowing as a percentage of total borrowings of all Ridgewood Participating Funds. Using these principles, the Fund's percentage ORRI to be granted to the Lenders equals 16.22% of the Fund's production until the Fund's share of Beta Project's cumulative production equals approximately 0.5 million barrels of oil (“MMBO”), net of royalties. Upon reaching that milestone, the Fund's ORRI percentage decreases to 10.81% of the Fund's production until the Fund's share of the Beta Project's cumulative production equals approximately 0.79 MMBO, net of royalties, whereupon it decreases to, and remains at, 5.41% of the Fund's net production. Upon entering into the Credit Agreement, the Fund recorded the additional consideration as debt discounts and deferred financing costs at a fair value of $0.6 million, which is amortized to interest expense over the expected payoff period of the loan. The fair value of the ORRI was determined using net discounted cash flows from the Beta Project related to the ORRI based on Level 3 inputs, which include projected net income from reserves and forward pricing curves. | |
The Credit Agreement contains customary covenants, for which the Fund believes it was in compliance at December 31, 2014 and 2013. |
Commitments_and_Contingencies
Commitments and Contingencies | 12 Months Ended |
Dec. 31, 2014 | |
Commitments and Contingencies [Abstract] | |
Commitments and Contingencies | 5. 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. Currently, the Fund has one non-producing property, the Beta Project, for which additional development costs must be incurred in order to commence production. The Fund currently anticipates such development will include a four-well development with related platform and pipeline infrastructure. | |
As of December 31, 2014, the Fund's estimated capital commitments related to its oil and gas properties were $10.9 million (which include asset retirement obligations for the Fund's projects of $2.5 million and projected interest costs of $2.1 million for the Beta Project), of which $3.5 million is expected to be spent during the year ending December 31, 2015. These expected capital commitments exceed available working capital and salvage fund by $4.9 million at December 31, 2014. In November 2012, the Fund entered into a credit agreement that provides for an aggregate loan commitment of up to $8.3 million, of which the Fund has borrowed $1.8 million at December 31, 2014, to provide capital toward the funding of the Fund's share of development costs on the Beta Project. Principal and interest amounts are contracted to be repaid upon the onset of production of the Beta Project, which is expected in 2016, over a period not to extend beyond December 31, 2020. See Note 4. “Credit Agreement” – Beta Project Financing” for additional information. | |
Based upon its current cash position and its current reserve estimates, the Fund expects cash flow from operations and borrowings 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. At December 31, 2014 and 2013, there were no known environmental contingencies that required the Fund to record a liability. | |
During the past several years, the United States Congress, as well as certain regulatory agencies with jurisdiction over the Fund's business, have considered or proposed legislation or regulation relating to the upstream oil and gas industry both onshore and offshore. If any such proposals were to be enacted or adopted they could potentially materially impact the Fund's operations. It is not possible at this time to predict whether such legislation or regulation, if proposed, will be adopted as initially written, if at all, or how legislation or new regulation that may be adopted would impact the Fund's business. Any such future laws and regulations could result in increased compliance costs or additional operating restrictions, which could have a material adverse effect on the Fund's operating results and cash flows. | |
Insurance Coverage | |
The Fund is subject to all risks inherent in the exploration for and development of oil and natural gas. Insurance coverage as is customary for entities engaged in similar operations is maintained, but losses may occur from uninsurable risks or amounts in excess of existing insurance coverage. The occurrence of an event that is not insured or not fully insured could have a material adverse impact upon earnings and financial position. Moreover, insurance is obtained as a package covering all of the funds managed by the Manager. Claims made by other funds managed by the Manager can reduce or eliminate insurance for the Fund. |
Information_about_Oil_and_Gas_
Information about Oil and Gas Producing Activities | 12 Months Ended | ||||||||||||||||||||||||
Dec. 31, 2014 | |||||||||||||||||||||||||
Information About Oil And Gas Producing Activities [Abstract] | |||||||||||||||||||||||||
Information about Oil and Gas Producing Activities | Ridgewood Energy A-1 Fund, LLC | ||||||||||||||||||||||||
Supplementary Financial Information | |||||||||||||||||||||||||
Information about Oil and Gas Producing Activities – Unaudited | |||||||||||||||||||||||||
In accordance with the Financial Accounting Standards Board 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, | |||||||||||||||||||||||||
2014 | 2013 | ||||||||||||||||||||||||
(in thousands) | |||||||||||||||||||||||||
Advances to operators for working interests and expenditures | $ | - | $ | 68 | |||||||||||||||||||||
Proved properties | 9,763 | 15,735 | |||||||||||||||||||||||
Equipment and facilities - in progress | 4,934 | 1,842 | |||||||||||||||||||||||
Total oil and gas properties | 14,697 | 17,645 | |||||||||||||||||||||||
Accumulated depletion, depreciation and amortization | (6,318 | ) | (11,547 | ) | |||||||||||||||||||||
Oil and gas properties, net | $ | 8,379 | $ | 6,098 | |||||||||||||||||||||
Table II - Costs Incurred in Oil and Gas Property Acquisition, Exploration, and Development | |||||||||||||||||||||||||
Year ended December 31, | |||||||||||||||||||||||||
2014 | 2013 | ||||||||||||||||||||||||
(in thousands) | |||||||||||||||||||||||||
Exploration costs | $ | (3 | ) | $ | 6 | ||||||||||||||||||||
Development costs | 4,021 | 2,235 | |||||||||||||||||||||||
$ | 4,018 | $ | 2,241 | ||||||||||||||||||||||
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, 2014 and 2013. 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. | |||||||||||||||||||||||||
31-Dec-14 | 31-Dec-13 | ||||||||||||||||||||||||
United States | |||||||||||||||||||||||||
Oil (BBLS) | NGL (BBLS) | Gas (MCF) | Oil (BBLS) | NGL (BBLS) | Gas (MCF) | ||||||||||||||||||||
Proved developed and undeveloped reserves: | |||||||||||||||||||||||||
Beginning of year | 355,412 | 171,648 | 6,378,017 | 408,514 | - | 7,968,443 | |||||||||||||||||||
Extensions and discoveries | - | - | - | - | - | - | |||||||||||||||||||
Sales of minerals in place (a) | (40,214 | ) | (153,769 | ) | (5,873,539 | ) | - | - | - | ||||||||||||||||
Revisions of previous estimates (b) | 16,383 | 2,140 | (19,471 | ) | (12,065 | ) | 223,015 | 67,501 | |||||||||||||||||
Production | (24,798 | ) | (8,624 | ) | (113,142 | ) | (41,037 | ) | (51,367 | ) | (1,657,927 | ) | |||||||||||||
End of year (c) | 306,783 | 11,395 | 371,865 | 355,412 | 171,648 | 6,378,017 | |||||||||||||||||||
Proved developed reserves: | |||||||||||||||||||||||||
Beginning of year | 46,097 | 41,475 | 1,182,852 | 104,155 | - | 3,308,526 | |||||||||||||||||||
End of year | 27,798 | 11,395 | 162,625 | 46,097 | 41,475 | 1,182,852 | |||||||||||||||||||
Proved undeveloped reserves: | |||||||||||||||||||||||||
Beginning of year | 309,315 | 130,173 | 5,195,165 | 304,359 | - | 4,659,917 | |||||||||||||||||||
End of year (d) | 278,985 | - | 209,240 | 309,315 | 130,173 | 5,195,165 | |||||||||||||||||||
(a) | On January 17, 2014, the Fund entered into an agreement to sell its leasehold interests in the Raven Project to a third party, which at December 31, 2013, included proved developed and undeveloped oil reserves of approximately 5 thousand barrels and 36 thousand barrels, respectively, proved developed and undeveloped NGL reserves of approximately 24 thousand barrels and 0.1 million barrels, respectively, and proved developed and undeveloped gas reserves of approximately 0.9 million mcf and 5.0 million mcf, respectively. | ||||||||||||||||||||||||
(b) | Revisions of previous estimates were attributable to well performance. | ||||||||||||||||||||||||
(c) | During January 2015, the Carrera Project was shut-in due to ongoing mechanical issues related to a blockage in the flowline. Upon evaluation, it was determined that estimated costs to bring the well back on production were not economic relative to the remaining reserves. As a result, approximately 15 thousand barrels of oil, 1 thousand barrels of NGL's, and 18 thousand mcf's of gas, related to the Carrera Project, which are included in the above table, are not expected to be recovered. | ||||||||||||||||||||||||
(d) | At December 31, 2014, the decreases in proved undeveloped reserves were principally due to the sale of the Raven Project. | ||||||||||||||||||||||||
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, | |||||||||||||||||||||||||
2014 | 2013 | ||||||||||||||||||||||||
(in thousands) | |||||||||||||||||||||||||
Future cash inflows | $ | 29,128 | $ | 64,392 | |||||||||||||||||||||
Future production costs | (2,566 | ) | (6,628 | ) | |||||||||||||||||||||
Future development costs | (8,854 | ) | (20,534 | ) | |||||||||||||||||||||
Future ad valorem taxes | - | (599 | ) | ||||||||||||||||||||||
Future net cash flows (a) (b) | 17,708 | 36,631 | |||||||||||||||||||||||
10% annual discount for estimated timing of cash flows | (5,381 | ) | (12,562 | ) | |||||||||||||||||||||
Standardized measure of discounted future estimated net cash flows (a) (b) | $ | 12,327 | $ | 24,069 | |||||||||||||||||||||
(a) | On January 17, 2014, the Fund entered into an agreement to sell its leasehold interests in the Raven Project to a third party, which, at December 31, 2013, included undiscounted and discounted cash flows of approximately $17.4 million and $12.5 million, respectively. | ||||||||||||||||||||||||
(b) | During January 2015, the Carrera Project was shut-in due to ongoing mechanical issues related to a blockage in the flowline. Upon evaluation, it was determined that estimated costs to bring the well back on production were not economic relative to the remaining reserves. As a result, undiscounted and discounted cash flows at December 31, 2014 of approximately $0.7 million related to the Carrera Project are not expected to be realized. | ||||||||||||||||||||||||
Table V - Changes in the Standardized Measure for Discounted Future Net Cash Flows | |||||||||||||||||||||||||
The changes in present values between years, which can be significant, reflect changes in estimated proved reserve quantities and prices and assumptions used in forecasting production volumes and costs. | |||||||||||||||||||||||||
Year ended December 31, | |||||||||||||||||||||||||
2014 | 2013 | ||||||||||||||||||||||||
(in thousands) | |||||||||||||||||||||||||
Net change in sales and transfer prices and in production costs | $ | (2,638 | ) | $ | 1,110 | ||||||||||||||||||||
related to future production | |||||||||||||||||||||||||
Sales and transfers of oil and gas produced during the period | (2,453 | ) | (10,206 | ) | |||||||||||||||||||||
Net change due to purchases and sales of minerals in place (a) | (12,530 | ) | - | ||||||||||||||||||||||
Changes in estimated future development costs | 4,227 | (2,730 | ) | ||||||||||||||||||||||
Net change due to revisions in quantities estimates | 743 | 5,249 | |||||||||||||||||||||||
Accretion of discount | 2,407 | 2,742 | |||||||||||||||||||||||
Other | (1,498 | ) | 482 | ||||||||||||||||||||||
Aggregate change in the standardized measure of discounted future net cash flows | $ | (11,742 | ) | $ | (3,353 | ) | |||||||||||||||||||
for the year (b) | |||||||||||||||||||||||||
(a) | On January 17, 2014, the Fund entered into an agreement to sell its leasehold interests in the Raven Project to a third party, which, at December 31, 2013, included discounted cash flows of approximately $12.5 million. | ||||||||||||||||||||||||
(b) | During January 2015, the Carrera Project was shut-in due to ongoing mechanical issues related to a blockage in the flowline. Upon evaluation, it was determined that estimated costs to bring the well back on production were not economic relative to the remaining reserves. See additional information in Tables III and IV. | ||||||||||||||||||||||||
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_Si1
Organization and Summary of Significant Accounting Policies (Policy) | 12 Months Ended | ||||||||||||
Dec. 31, 2014 | |||||||||||||
Organization and Summary of Significant Accounting Policies [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, property balances, determination of proved reserves, impairments and asset retirement obligations. Actual results may differ from those estimates. | |||||||||||||
Fair Value Measurements | Fair Value Measurements | ||||||||||||
The fair value measurement guidance provides a hierarchy that prioritizes and defines the types of inputs used to measure fair value. The fair value hierarchy gives the highest priority to Level 1 inputs, which consists of unadjusted quoted prices for identical instruments in active markets. Level 2 inputs consist of quoted prices for similar instruments. Level 3 valuations are derived from inputs that are significant and unobservable; hence, these valuations have the lowest priority. Cash and cash equivalents approximate fair value based on Level 1 inputs. Mortgage-backed securities are recorded based on Level 2 inputs, as such instruments trade in over-the-counter markets. | |||||||||||||
Cash and Cash Equivalents | Cash and Cash Equivalents | ||||||||||||
All highly liquid investments with maturities, when purchased, of three months or less, are considered cash and cash equivalents. At times, deposits may be in excess of federally insured limits, which are $250 thousand per insured financial institution. At December 31, 2014, 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, money to provide for the dismantling and removal of production platforms and facilities and plugging and abandoning its wells at the end of their useful lives in accordance with applicable federal and state laws and regulations. At December 31, 2014 and 2013, the Fund had investments in federal agency mortgage-backed securities as detailed in the following table, which are classified as available for sale. Available-for-sale securities are carried in the financial statements at fair value. | |||||||||||||
Amortized | Gross | Fair | |||||||||||
Unrealized | |||||||||||||
Cost | Gains (Losses) | Value | |||||||||||
(in thousands) | |||||||||||||
Government National Mortgage Association securities (GNMA July 2041) | |||||||||||||
December 31, 2014 | $ | 84 | $ | 3 | $ | 87 | |||||||
December 31, 2013 | $ | 90 | $ | 1 | $ | 91 | |||||||
Federal National Mortgage Association security (FNMA January 2042) | |||||||||||||
December 31, 2014 | $ | 109 | $ | 1 | $ | 110 | |||||||
December 31, 2013 | $ | 198 | $ | (4 | ) | $ | 194 | ||||||
The unrealized gains and losses on the Fund's investments in federal agency mortgage-backed securities were the result of fluctuations in market interest rates. The contractual cash flows of those investments are guaranteed by an agency of the U.S. government. It is expected that the securities would not be settled at a price less than the amortized cost basis of the Fund's investments. Unrealized gains or losses on available-for-sale securities are reported in other comprehensive income until realized. | |||||||||||||
For all investments, interest income is accrued as earned and amortization of premium or discount, if any, is included in interest income. Interest earned on the account will become part of the salvage fund. There are no restrictions on withdrawals from the salvage fund. | |||||||||||||
Debt Discounts and Deferred Financing Costs | Debt Discounts and Deferred Financing Costs | ||||||||||||
Debt discounts and deferred financing costs include lender fees and other costs of acquiring the debt (see Note 4. “Credit Agreement – Beta Project Financing”) such as the conveyance of override royalty interests related to the Beta Project. These costs are deferred and amortized over the term of the debt period or until the redemption of the debt and are included on the balance sheet within “Other assets”. At December 31, 2014 and 2013, $0.4 million and $0.5 million, respectively, of debt discounts and deferred financing costs were unamortized. Amortization expense was $0.1 million during each of the years ended December 31, 2014 and 2013. 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”. | |||||||||||||
Oil and Gas Properties | Oil and Gas Properties | ||||||||||||
The Fund invests in oil and gas properties, which are operated by unaffiliated entities that are responsible for drilling, administering and producing activities pursuant to the terms of the applicable operating agreements with working interest owners. The Fund's portion of exploration, drilling, operating and capital equipment expenditures is billed by operators. | |||||||||||||
Exploration, development and acquisition costs are accounted for using the successful efforts method. Costs of acquiring unproved and proved oil and natural gas leasehold acreage, including lease bonuses, brokers' fees and other related costs are capitalized. Costs of drilling and equipping productive wells and related production facilities are capitalized. Costs of developing production facilities and pipelines that service multiple oil and gas properties are segregated as “Equipment and facilities - in progress.” Exploratory costs are capitalized pending determination of whether proved reserves have been found. If proved commercial reserves are not found, exploratory 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 4. “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 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, depreciation and amortization, if any, is eliminated from the property accounts, and the resultant gain or loss is recognized. | |||||||||||||
At December 31, 2014 and 2013, amounts recorded in due to operators totaling $0.8 million and $0.7 million, respectively, related to capital expenditures for oil and gas properties. | |||||||||||||
Advances to Operators for Working Interests and Expenditures | Advances to Operators for Working Interests and Expenditures | ||||||||||||
The Fund's acquisition of a working interest in an oil and gas property requires it to make a payment to the seller for the Fund's rights, title and interest. The Fund may be required to advance its share of estimated cash expenditures for the succeeding month's operation. The Fund accounts for such payments as advances to operators for working interests and expenditures. As drilling costs are incurred, the advances are reclassified to unproved or 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. When a project reaches drilling depth and is determined to be either proved or dry, an asset retirement obligation is incurred. Plug and abandonment costs associated with unsuccessful projects are expensed as dry-hole costs. The following table presents changes in asset retirement obligations for the years ended December 31, 2014 and 2013. | |||||||||||||
2014 | 2013 | ||||||||||||
(in thousands) | |||||||||||||
Balance, beginning of year | $ | 946 | $ | 1,131 | |||||||||
Liabilities relieved/settled | - | (684 | ) | ||||||||||
Accretion expense | 19 | 18 | |||||||||||
Revisions in estimated cash flows | - | 481 | |||||||||||
Balance, end of year | $ | 965 | $ | 946 | |||||||||
At December 31, 2013, the Fund's balance sheet reflects the reclassification of the Raven Project's asset retirement obligation from “Asset retirement obligation” to “Liability held for sale”. On January 17, 2014, the Fund entered into an agreement to sell its interest in the Raven Project to a third party. | |||||||||||||
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, when delivery has occurred and title has transferred, and if collectability of the revenue is probable. 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 value of its oil and gas properties whenever management determines that events and circumstances indicate that the recorded carrying value of properties may not be recoverable. Impairments of proved properties are determined by comparing future net undiscounted cash flows to the net book value at the time of the review. If the net book value exceeds the future net undiscounted cash flows, the carrying value of the property is written down to fair value, which is determined using net discounted future cash flows from the property. The Fund provides for impairments on unproved properties when it determines that the property will not be developed or a permanent impairment in value has occurred. 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. If oil and natural gas prices decline significantly, even if only for a short period of time, it is possible that write-downs of oil and gas properties could occur. | |||||||||||||
During January 2015, the Carrera Project was shut-in due to ongoing mechanical issues related to a blockage in the flowline. Upon evaluation, it was determined that estimated costs to bring the well back on production were not economic relative to the remaining reserves and the well was fully impaired. Accordingly, during the year ended December 31, 2014, the Fund recorded an impairment of oil and gas properties of $0.6 million, representing the remaining net book value of the well at the date of impairment. The Fund did not record an impairment of oil and gas properties during the year ended December 31, 2013. | |||||||||||||
Depletion, Depreciation and Amortization | Depletion, Depreciation and Amortization | ||||||||||||
Depletion, depreciation 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. In certain circumstances, equipment and facilities costs are depreciated over the estimated useful life of the asset. | |||||||||||||
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 2010 through 2013 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. During the year ended December 31, 2014, the Fund made distributions of available cash from dispositions related to the sale of the Raven Project totaling $7.2 million. There were no such distributions during the year ended December 31, 2013. | |||||||||||||
Recent Accounting Pronouncements | Recent Accounting Pronouncements | ||||||||||||
The Fund has considered recent accounting pronouncements and believes that these recent pronouncements will not have a material effect on the Fund's financial statements. |
Organization_and_Summary_of_Si2
Organization and Summary of Significant Accounting Policies (Tables) | 12 Months Ended | ||||||||||||
Dec. 31, 2014 | |||||||||||||
Organization and Summary of Significant Accounting Policies [Abstract] | |||||||||||||
Schedule of Available-For-Sale Securities | Amortized | Gross | Fair | ||||||||||
Unrealized | |||||||||||||
Cost | Gains (Losses) | Value | |||||||||||
(in thousands) | |||||||||||||
Government National Mortgage Association securities (GNMA July 2041) | |||||||||||||
December 31, 2014 | $ | 84 | $ | 3 | $ | 87 | |||||||
December 31, 2013 | $ | 90 | $ | 1 | $ | 91 | |||||||
Federal National Mortgage Association security (FNMA January 2042) | |||||||||||||
December 31, 2014 | $ | 109 | $ | 1 | $ | 110 | |||||||
December 31, 2013 | $ | 198 | $ | (4 | ) | $ | 194 | ||||||
Schedule of Changes in Asset Retirement Obligations | 2014 | 2013 | |||||||||||
(in thousands) | |||||||||||||
Balance, beginning of year | $ | 946 | $ | 1,131 | |||||||||
Liabilities relieved/settled | - | (684 | ) | ||||||||||
Accretion expense | 19 | 18 | |||||||||||
Revisions in estimated cash flows | - | 481 | |||||||||||
Balance, end of year | $ | 965 | $ | 946 |
Information_about_Oil_and_Gas_1
Information about Oil and Gas Producing Activities (Tables) | 12 Months Ended | ||||||||||||||||||||||||
Dec. 31, 2014 | |||||||||||||||||||||||||
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, | |||||||||||||||||||||||||
2014 | 2013 | ||||||||||||||||||||||||
(in thousands) | |||||||||||||||||||||||||
Advances to operators for working interests and expenditures | $ | - | $ | 68 | |||||||||||||||||||||
Proved properties | 9,763 | 15,735 | |||||||||||||||||||||||
Equipment and facilities - in progress | 4,934 | 1,842 | |||||||||||||||||||||||
Total oil and gas properties | 14,697 | 17,645 | |||||||||||||||||||||||
Accumulated depletion, depreciation and amortization | (6,318 | ) | (11,547 | ) | |||||||||||||||||||||
Oil and gas properties, net | $ | 8,379 | $ | 6,098 | |||||||||||||||||||||
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, | |||||||||||||||||||||||||
2014 | 2013 | ||||||||||||||||||||||||
(in thousands) | |||||||||||||||||||||||||
Exploration costs | $ | (3 | ) | $ | 6 | ||||||||||||||||||||
Development costs | 4,021 | 2,235 | |||||||||||||||||||||||
$ | 4,018 | $ | 2,241 | ||||||||||||||||||||||
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, 2014 and 2013. 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. | |||||||||||||||||||||||||
31-Dec-14 | 31-Dec-13 | ||||||||||||||||||||||||
United States | |||||||||||||||||||||||||
Oil (BBLS) | NGL (BBLS) | Gas (MCF) | Oil (BBLS) | NGL (BBLS) | Gas (MCF) | ||||||||||||||||||||
Proved developed and undeveloped reserves: | |||||||||||||||||||||||||
Beginning of year | 355,412 | 171,648 | 6,378,017 | 408,514 | - | 7,968,443 | |||||||||||||||||||
Extensions and discoveries | - | - | - | - | - | - | |||||||||||||||||||
Sales of minerals in place (a) | (40,214 | ) | (153,769 | ) | (5,873,539 | ) | - | - | - | ||||||||||||||||
Revisions of previous estimates (b) | 16,383 | 2,140 | (19,471 | ) | (12,065 | ) | 223,015 | 67,501 | |||||||||||||||||
Production | (24,798 | ) | (8,624 | ) | (113,142 | ) | (41,037 | ) | (51,367 | ) | (1,657,927 | ) | |||||||||||||
End of year (c) | 306,783 | 11,395 | 371,865 | 355,412 | 171,648 | 6,378,017 | |||||||||||||||||||
Proved developed reserves: | |||||||||||||||||||||||||
Beginning of year | 46,097 | 41,475 | 1,182,852 | 104,155 | - | 3,308,526 | |||||||||||||||||||
End of year | 27,798 | 11,395 | 162,625 | 46,097 | 41,475 | 1,182,852 | |||||||||||||||||||
Proved undeveloped reserves: | |||||||||||||||||||||||||
Beginning of year | 309,315 | 130,173 | 5,195,165 | 304,359 | - | 4,659,917 | |||||||||||||||||||
End of year (d) | 278,985 | - | 209,240 | 309,315 | 130,173 | 5,195,165 | |||||||||||||||||||
(a) | On January 17, 2014, the Fund entered into an agreement to sell its leasehold interests in the Raven Project to a third party, which at December 31, 2013, included proved developed and undeveloped oil reserves of approximately 5 thousand barrels and 36 thousand barrels, respectively, proved developed and undeveloped NGL reserves of approximately 24 thousand barrels and 0.1 million barrels, respectively, and proved developed and undeveloped gas reserves of approximately 0.9 million mcf and 5.0 million mcf, respectively. | ||||||||||||||||||||||||
(b) | Revisions of previous estimates were attributable to well performance. | ||||||||||||||||||||||||
(c) | During January 2015, the Carrera Project was shut-in due to ongoing mechanical issues related to a blockage in the flowline. Upon evaluation, it was determined that estimated costs to bring the well back on production were not economic relative to the remaining reserves. As a result, approximately 15 thousand barrels of oil, 1 thousand barrels of NGL's, and 18 thousand mcf's of gas, related to the Carrera Project, which are included in the above table, are not expected to be recovered. | ||||||||||||||||||||||||
(d) | At December 31, 2014, the decreases in proved undeveloped reserves were principally due to the sale of the Raven Project. | ||||||||||||||||||||||||
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, | |||||||||||||||||||||||||
2014 | 2013 | ||||||||||||||||||||||||
(in thousands) | |||||||||||||||||||||||||
Future cash inflows | $ | 29,128 | $ | 64,392 | |||||||||||||||||||||
Future production costs | (2,566 | ) | (6,628 | ) | |||||||||||||||||||||
Future development costs | (8,854 | ) | (20,534 | ) | |||||||||||||||||||||
Future ad valorem taxes | - | (599 | ) | ||||||||||||||||||||||
Future net cash flows (a) (b) | 17,708 | 36,631 | |||||||||||||||||||||||
10% annual discount for estimated timing of cash flows | (5,381 | ) | (12,562 | ) | |||||||||||||||||||||
Standardized measure of discounted future estimated net cash flows (a) (b) | $ | 12,327 | $ | 24,069 | |||||||||||||||||||||
(a) | On January 17, 2014, the Fund entered into an agreement to sell its leasehold interests in the Raven Project to a third party, which, at December 31, 2013, included undiscounted and discounted cash flows of approximately $17.4 million and $12.5 million, respectively. | ||||||||||||||||||||||||
(b) | During January 2015, the Carrera Project was shut-in due to ongoing mechanical issues related to a blockage in the flowline. Upon evaluation, it was determined that estimated costs to bring the well back on production were not economic relative to the remaining reserves. As a result, undiscounted and discounted cash flows at December 31, 2014 of approximately $0.7 million related to the Carrera Project are not expected to be realized. | ||||||||||||||||||||||||
Schedule of Changes in the Standardized Measure for Discounted Cash Flows | Table V - Changes in the Standardized Measure for Discounted Future Net Cash Flows | ||||||||||||||||||||||||
The changes in present values between years, which can be significant, reflect changes in estimated proved reserve quantities and prices and assumptions used in forecasting production volumes and costs. | |||||||||||||||||||||||||
Year ended December 31, | |||||||||||||||||||||||||
2014 | 2013 | ||||||||||||||||||||||||
(in thousands) | |||||||||||||||||||||||||
Net change in sales and transfer prices and in production costs | $ | (2,638 | ) | $ | 1,110 | ||||||||||||||||||||
related to future production | |||||||||||||||||||||||||
Sales and transfers of oil and gas produced during the period | (2,453 | ) | (10,206 | ) | |||||||||||||||||||||
Net change due to purchases and sales of minerals in place (a) | (12,530 | ) | - | ||||||||||||||||||||||
Changes in estimated future development costs | 4,227 | (2,730 | ) | ||||||||||||||||||||||
Net change due to revisions in quantities estimates | 743 | 5,249 | |||||||||||||||||||||||
Accretion of discount | 2,407 | 2,742 | |||||||||||||||||||||||
Other | (1,498 | ) | 482 | ||||||||||||||||||||||
Aggregate change in the standardized measure of discounted future net cash flows | $ | (11,742 | ) | $ | (3,353 | ) | |||||||||||||||||||
for the year (b) | |||||||||||||||||||||||||
(a) | On January 17, 2014, the Fund entered into an agreement to sell its leasehold interests in the Raven Project to a third party, which, at December 31, 2013, included discounted cash flows of approximately $12.5 million. | ||||||||||||||||||||||||
(b) | During January 2015, the Carrera Project was shut-in due to ongoing mechanical issues related to a blockage in the flowline. Upon evaluation, it was determined that estimated costs to bring the well back on production were not economic relative to the remaining reserves. See additional information in Tables III and IV. | ||||||||||||||||||||||||
Organization_and_Summary_of_Si3
Organization and Summary of Significant Accounting Policies (Narrative) (Details) (USD $) | 12 Months Ended | |
Dec. 31, 2014 | Dec. 31, 2013 | |
Organization and Summary of Significant Accounting Policies [Abstract] | ||
Maximum cash balance insured by the FDIC, per financial institution | $250,000 | |
Unamortized debt discounts and deferred financing costs | 400,000 | 500,000 |
Amortization of financing costs | 100,000 | 100,000 |
Value of capital expenditures for oil and gas properties owed to operators | 800,000 | 700,000 |
Impaired Long-Lived Assets Held and Used [Line Items] | ||
Impairment of oil and gas properties | 646,000 | |
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 the Fund manager | 1.00% | |
Percentage of available cash from dispositions allocated to shareholders after shareholders have received distributions equal to their capital contributions | 85.00% | |
Percentage of available cash from dispositions allocated to the Fund manager after shareholders have received distributions equal to their capital contributions | 15.00% | |
Distributions related to Raven Project | 7,200,000 | |
Carrera Project [Member] | ||
Impaired Long-Lived Assets Held and Used [Line Items] | ||
Impairment of oil and gas properties | $600,000 |
Organization_and_Summary_of_Si4
Organization and Summary of Significant Accounting Policies (Schedule of Available-For-Sale Securities) (Details) (USD $) | 12 Months Ended | |
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 |
GNMA July 2041 [Member] | ||
Schedule of Available-for-sale Securities [Line Items] | ||
Amortized Cost | $84 | $90 |
Gross Unrealized Gains (Losses) | 3 | 1 |
Fair Value | 87 | 91 |
FNMA January 2042 [Member] | ||
Schedule of Available-for-sale Securities [Line Items] | ||
Amortized Cost | 109 | 198 |
Gross Unrealized Gains (Losses) | 1 | -4 |
Fair Value | $110 | $194 |
Organization_and_Summary_of_Si5
Organization and Summary of Significant Accounting Policies (Schedule of Changes in Asset Retirement Obligations) (Details) (USD $) | 12 Months Ended | |
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 |
Organization and Summary of Significant Accounting Policies [Abstract] | ||
Balance, beginning of year | $946 | $1,131 |
Liabilities relieved/settled | -684 | |
Accretion expense | 19 | 18 |
Revisions in estimated cash flows | 481 | |
Balance, end of year | $965 | $946 |
Oil_and_Gas_Properties_Details
Oil and Gas Properties (Details) (USD $) | 12 Months Ended | |
Dec. 31, 2014 | Dec. 31, 2013 | |
Oil and Gas Properties [Abstract] | ||
Cash consideration | $21,700,000 | |
Working interest percentage | 25.00% | |
Proceeds from sale of oil and gas properties | 10,978,000 | |
Carrying value of oil and gas properties at date of sale | 600,000 | |
Gain on sale of oil and gas properties | 10,396,000 | |
Asset held for sale | 1,266,000 | |
Liability held for sale | $684,000 |
Related_Parties_Details
Related Parties (Details) (USD $) | 12 Months Ended | |
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 |
Related Party Transaction [Line Items] | ||
Annual management fee percentage rate | 2.50% | |
Annual management fees paid to Fund Manager | $632 | $929 |
Percentage of total distributions allocated to Fund Manager | 15.00% | |
Distributions | -10,527 | -8,225 |
Fund Manager [Member] | ||
Related Party Transaction [Line Items] | ||
Distributions | -600 | -1,200 |
Fund Manager [Member] | Raven Project [Member] | ||
Related Party Transaction [Line Items] | ||
Percentage of total distributions allocated to Fund Manager | 1.00% | |
Distributions | ($100) |
Credit_Agreement_Beta_Project_1
Credit Agreement - Beta Project Financing (Details) (USD $) | 12 Months Ended | ||
Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | |
Credit Agreement - Beta Project Financing [Abstract] | |||
Credit agreement, maximum borrowing capacity | $8,300,000 | ||
Credit agreement, interest rate | 8.00% | ||
Credit agreement, contingency repayment rate, first seven months of production | 1.25% | ||
Credit agreement, contingency repayment rate, after first seven months of production | 4.50% | ||
Credit agreement, maturity date | 31-Dec-20 | ||
Long-term borrowings | 1,800,000 | ||
Capitalized interest | 48,000 | ||
Oil And Gas Properties Milestone [Line Items] | |||
Deferred financing cost | $600,000 | ||
Milestone One [Member] | |||
Oil And Gas Properties Milestone [Line Items] | |||
Overriding royalty interest | 16.22% | ||
Maximum barrels of oil | 500,000 | ||
Milestone Two [Member] | |||
Oil And Gas Properties Milestone [Line Items] | |||
Overriding royalty interest | 10.81% | ||
Maximum barrels of oil | 790,000 | ||
Milestone Thereafter [Member] | |||
Oil And Gas Properties Milestone [Line Items] | |||
Overriding royalty interest | 5.41% |
Commitments_and_Contingencies_
Commitments and Contingencies (Details) (USD $) | 12 Months Ended | |
Dec. 31, 2014 | Dec. 31, 2013 | |
Commitments and Contingencies [Abstract] | ||
Commitments for the drilling and development of investment properties | $10,900,000 | |
Commitments for asset retirement obligations included in estimated capital commitments | 2,500,000 | |
Commitments for projected interest costs included in estimated capital commitments | 2,100,000 | |
Commitments for the drilling and development of investment properties expected to be incurred in the next 12 months | 3,500,000 | |
Commitments for the drilling and development of investment properties in excess of working capital | 4,900,000 | |
Credit agreement, maximum borrowing capacity | 8,300,000 | |
Long-term borrowings | $1,800,000 |
Information_about_Oil_and_Gas_2
Information about Oil and Gas Producing Activities (Schedule of Capitalized Costs Relating to Oil and Gas Producing Activities) (Details) (USD $) | Dec. 31, 2014 | Dec. 31, 2013 |
In Thousands, unless otherwise specified | ||
Information About Oil And Gas Producing Activities [Abstract] | ||
Advances to operators for working interests and expenditures | $68 | |
Proved properties | 9,763 | 15,735 |
Equipment and facilities - in progress | 4,934 | 1,842 |
Total oil and gas properties | 14,697 | 17,645 |
Accumulated depletion, depreciation and amortization | -6,318 | -11,547 |
Total oil and gas properties, net | $8,379 | $6,098 |
Information_about_Oil_and_Gas_3
Information about Oil and Gas Producing Activities (Schedule of Costs Incurred in Oil and Gas Property Acquisition, Exploration, and Development) (Details) (USD $) | 12 Months Ended | |
In Thousands, unless otherwise specified | Dec. 31, 2014 | Dec. 31, 2013 |
Information About Oil And Gas Producing Activities [Abstract] | ||
Exploration costs | ($3) | $6 |
Development costs | 4,021 | 2,235 |
Total costs | $4,018 | $2,241 |
Information_about_Oil_and_Gas_4
Information about Oil and Gas Producing Activities (Schedule of Reserve Quantity Information) (Details) | 12 Months Ended | |||||
Dec. 31, 2014 | Dec. 31, 2013 | Jan. 31, 2015 | Jan. 17, 2014 | |||
bbl | bbl | bbl | bbl | |||
Oil (BBLS) [Member] | ||||||
Proved developed and undeveloped reserves: | ||||||
Beginning of year | 355,412 | [1] | 408,514 | |||
Extensions and discoveries | ||||||
Sales of minerals in place | -40,214 | [2] | [2] | |||
Revisions of previous estimates | 16,383 | [3] | -12,065 | [3] | ||
Production | -24,798 | -41,037 | ||||
End of year | 306,783 | [1] | 355,412 | [1] | ||
Reserves not expected to be recovered | 15,000 | |||||
Proved developed reserves: | ||||||
Beginning of year | 46,097 | 104,155 | 5,000 | |||
End of year | 27,798 | 46,097 | 5,000 | |||
Proved undeveloped reserves: | ||||||
Beginning of year | 309,315 | [4] | 304,359 | 36,000 | ||
End of year | 278,985 | [4] | 309,315 | [4] | 36,000 | |
NGL (BBLS) [Member] | ||||||
Proved developed and undeveloped reserves: | ||||||
Beginning of year | 171,648 | [1] | ||||
Extensions and discoveries | ||||||
Sales of minerals in place | -153,769 | [2] | [2] | |||
Revisions of previous estimates | 2,140 | [3] | 223,015 | [3] | ||
Production | -8,624 | -51,367 | ||||
End of year | 11,395 | [1] | 171,648 | [1] | ||
Reserves not expected to be recovered | 1,000 | |||||
Proved developed reserves: | ||||||
Beginning of year | 41,475 | 24,000 | ||||
End of year | 11,395 | 41,475 | 24,000 | |||
Proved undeveloped reserves: | ||||||
Beginning of year | 130,173 | [4] | 100,000 | |||
End of year | [4] | 130,173 | [4] | 100,000 | ||
Gas (MCF) [Member] | ||||||
Proved developed and undeveloped reserves: | ||||||
Beginning of year | 6,378,017 | [1] | 7,968,443 | |||
Extensions and discoveries | ||||||
Sales of minerals in place | -5,873,539 | [2] | [2] | |||
Revisions of previous estimates | -19,471 | [3] | 67,501 | [3] | ||
Production | -113,142 | -1,657,927 | ||||
End of year | 371,865 | [1] | 6,378,017 | [1] | ||
Reserves not expected to be recovered | 18,000 | |||||
Proved developed reserves: | ||||||
Beginning of year | 1,182,852 | 3,308,526 | 900,000 | |||
End of year | 162,625 | 1,182,852 | 900,000 | |||
Proved undeveloped reserves: | ||||||
Beginning of year | 5,195,165 | [4] | 4,659,917 | 5,000,000 | ||
End of year | 209,240 | [4] | 5,195,165 | [4] | 5,000,000 | |
[1] | During January 2015, the Carrera Project was shut-in due to ongoing mechanical issues related to a blockage in the flowline. Upon evaluation, it was determined that estimated costs to bring the well back on production were not economic relative to the remaining reserves. As a result, approximately 15 thousand barrels of oil, 1 thousand barrels of NGL's, and 18 thousand mcf's of gas, related to the Carrera Project, which are included in the above table, are not expected to be recovered. | |||||
[2] | On January 17, 2014, the Fund entered into an agreement to sell its leasehold interests in the Raven Project to a third party, which at December 31, 2013, included proved developed and undeveloped oil reserves of approximately 5 thousand barrels and 36 thousand barrels, respectively, proved developed and undeveloped NGL reserves of approximately 24 thousand barrels and 0.1 million barrels, respectively, and proved developed and undeveloped gas reserves of approximately 0.9 million mcf and 5.0 million mcf, respectively. | |||||
[3] | Revisions of previous estimates were attributable to well performance. | |||||
[4] | At December 31, 2014, the decreases in proved undeveloped reserves were principally due to the sale of the Raven Project. |
Information_about_Oil_and_Gas_5
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 $) | Jan. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | ||
Information About Oil And Gas Producing Activities [Abstract] | |||||
Future cash inflows | $29,128,000 | $64,392,000 | |||
Future production costs | -2,566,000 | -6,628,000 | |||
Future development costs | -8,854,000 | -20,534,000 | |||
Future ad valorem taxes | -599,000 | ||||
Future net cash flows | 17,708,000 | [1],[2] | 36,631,000 | [1],[2] | |
10% annual discount for estimated timing of cash flows | -5,381,000 | -12,562,000 | |||
Standardized measure of discounted future estimated net cash flows | 12,327,000 | [1],[2] | 24,069,000 | [1],[2] | |
Undiscounted cash flows | 17,400,000 | ||||
Discounted cash flows | 12,500,000 | ||||
Undiscounted cash flows not expected to be realized | 700,000 | ||||
Discounted cash flows not expected to be realized | $700,000 | ||||
[1] | During January 2015, the Carrera Project was shut-in due to ongoing mechanical issues related to a blockage in the flowline. Upon evaluation, it was determined that estimated costs to bring the well back on production were not economic relative to the remaining reserves. As a result, undiscounted and discounted cash flows at December 31, 2014 of approximately $0.7 million related to the Carrera Project are not expected to be realized. | ||||
[2] | On January 17, 2014, the Fund entered into an agreement to sell its leasehold interests in the Raven Project to a third party, which, at December 31, 2013, included undiscounted and discounted cash flows of approximately $17.4 million and $12.5 million, respectively. |
Information_about_Oil_and_Gas_6
Information about Oil and Gas Producing Activities (Schedule of Changes in the Standardized Measure for Discounted Cash Flows) (Details) (USD $) | 12 Months Ended | |||
Dec. 31, 2014 | Dec. 31, 2013 | |||
Information About Oil And Gas Producing Activities [Abstract] | ||||
Net change in sales and transfer prices and in production costs related to future production | ($2,638,000) | $1,110,000 | ||
Sales and transfers of oil and gas produced during the period | -2,453,000 | -10,206,000 | ||
Net change due to purchases and sales of minerals in place | -12,530,000 | [1] | [1] | |
Changes in estimated future development costs | 4,227,000 | -2,730,000 | ||
Net change due to revisions in quantities estimates | 743,000 | 5,249,000 | ||
Accretion of discount | 2,407,000 | 2,742,000 | ||
Other | -1,498,000 | 482,000 | ||
Aggregate change in the standardized measure of discounted future net cash flows for the year | -11,742,000 | [2] | -3,353,000 | [2] |
Discounted cash flows | $12,500,000 | |||
[1] | On January 17, 2014, the Fund entered into an agreement to sell its leasehold interests in the Raven Project to a third party, which, at December 31, 2013, included discounted cash flows of approximately $12.5 million. | |||
[2] | During January 2015, the Carrera Project was shut-in due to ongoing mechanical issues related to a blockage in the flowline. Upon evaluation, it was determined that estimated costs to bring the well back on production were not economic relative to the remaining reserves. See additional information in Tables III and IV. |