Document and Entity Information
Document and Entity Information - USD ($) | 12 Months Ended | ||
Dec. 31, 2016 | Apr. 14, 2017 | Jun. 30, 2016 | |
Document And Entity Information | |||
Entity Registrant Name | Spindletop Oil & Gas Co. | ||
Entity Central Index Key | 867,038 | ||
Document Type | 10-K | ||
Document Period End Date | Dec. 31, 2016 | ||
Amendment Flag | false | ||
Current Fiscal Year End Date | --12-31 | ||
Is Entity a Well-known Seasoned Issuer? | No | ||
Is Entity a Voluntary Filer? | No | ||
Is Entity's Reporting Status Current? | Yes | ||
Entity Filer Category | Smaller Reporting Company | ||
Entity Public Float | $ 2,061,095 | ||
Entity Common Stock, Shares Outstanding | 6,936,269 | ||
Document Fiscal Period Focus | FY | ||
Document Fiscal Year Focus | 2,016 |
Consolidated Balance Sheets
Consolidated Balance Sheets - USD ($) | Dec. 31, 2016 | Dec. 31, 2015 |
Current Assets | ||
Cash and cash equivalents | $ 11,021,000 | $ 12,381,000 |
Restricted cash | 363,000 | 464,000 |
Accounts receivable, trade | 1,928,000 | 1,835,000 |
Income tax receivable | 927,000 | 754,000 |
Total Current Assets | 14,239,000 | 15,434,000 |
Property and Equipment - at cost | ||
Oil and gas properties (full cost method) | 29,661,000 | 29,144,000 |
Rental equipment | 406,000 | 406,000 |
Gas gathering system | 115,000 | 115,000 |
Other property and equipment | 296,000 | 296,000 |
Total Property and Equipment | 30,478,000 | 29,961,000 |
Accumulated depreciation and amortization | (24,329,000) | (22,577,000) |
Total Property and Equipment, Net | 6,149,000 | 7,384,000 |
Real Estate Property - at cost | ||
Land | 688,000 | 688,000 |
Commercial office building | 1,580,000 | 1,580,000 |
Accumulated depreciation | (850,000) | (803,000) |
Total Real Estate Property | 1,418,000 | 1,465,000 |
Other Assets | ||
Other long-term investments | 1,550,000 | 1,600,000 |
Other | 9,000 | 6,000 |
Total Other Assets | 1,559,000 | 1,606,000 |
Total Assets | 23,365,000 | 25,889,000 |
Current Liabilities | ||
Accounts payable and accrued liabilities | 5,291,000 | 5,809,000 |
Total Current Liabilities | 5,291,000 | 5,809,000 |
Noncurrent Liabilities | ||
Asset retirement obligation | 916,000 | 1,121,000 |
Total Noncurrent Liabilities | 916,000 | 1,121,000 |
Deferred Income Tax Payable | 18,000 | 490,000 |
Total Liabilities | 6,225,000 | 7,420,000 |
Shareholders' Equity | ||
Common stock, $.01 par value, 100,000,000 shares authorized; 7,677,471 shares issued and 6,936,269 shares outstanding at December 31, 2016 and at December 31, 2015. | 77,000 | 77,000 |
Additional paid-in capital | 943,000 | 943,000 |
Treasury stock, at cost | (1,536,000) | (1,536,000) |
Retained earnings | 17,656,000 | 18,985,000 |
Total Shareholders' Equity | 17,140,000 | 18,469,000 |
Total Liabilities and Shareholders' Equity | $ 23,365,000 | $ 25,889,000 |
Consolidated Balance Sheets (Pa
Consolidated Balance Sheets (Parenthetical) - $ / shares | Dec. 31, 2016 | Dec. 31, 2015 |
Common Stock, Par Value $0.01 | ||
Common Stock, Par Value | $ 0.01 | $ 0.01 |
Common Stock, Shares Authorized | 100,000,000 | 100,000,000 |
Common Stock, Shares Issued | 7,677,471 | 7,677,471 |
Common Stock, Shares Outstanding | 6,936,269 | 6,936,269 |
Consolidated Statements of Oper
Consolidated Statements of Operations - USD ($) | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Revenues | |||
Oil and gas revenues | $ 3,320,000 | $ 4,841,000 | $ 11,688,000 |
Revenue from lease operations | 415,000 | 481,000 | 481,000 |
Gas gathering, compression, equipment rental | 114,000 | 141,000 | 155,000 |
Real estate rental income | 314,000 | 230,000 | 240,000 |
Interest Income | 83,000 | 68,000 | 125,000 |
Other | 269,000 | 183,000 | 519,000 |
Total Revenues | 4,515,000 | 5,944,000 | 13,208,000 |
Expenses | |||
Lease operations | 1,499,000 | 2,365,000 | 2,240,000 |
Production taxes, gathering and marketing | 422,000 | 600,000 | 996,000 |
Pipeline and rental operations | 46,000 | 32,000 | 49,000 |
Real estate operations | 175,000 | 215,000 | 220,000 |
Depreciation and amortization | 1,104,000 | 2,426,000 | 1,846,000 |
Impairment of oil & gas properties | 695,000 | 5,116,000 | |
ARO accretion expense | 36,000 | 35,000 | 42,000 |
General and administrative | 2,512,000 | 3,198,000 | 4,019,000 |
Total Expenses | 6,489,000 | 13,987,000 | 9,412,000 |
Income (Loss) Before Income Tax | (1,974,000) | (8,043,000) | 3,796,000 |
Current income tax provision (benefit) | (173,000) | (928,000) | 526,000 |
Deferred income tax provision (benefit) | (472,000) | (1,338,000) | 65,000 |
Total income tax provision (benefit) | (645,000) | (2,266,000) | 591,000 |
Net Income (Loss) | $ (1,329,000) | $ (5,777,000) | $ 3,205,000 |
Earnings (Loss) per Share of Common Stock Basic and Diluted | $ (0.19) | $ (0.83) | $ 0.46 |
Weighted Average Shares Outstanding Basic and Diluted | 6,936,269 | 6,936,269 | 6,936,269 |
Consolidated Statements of Chan
Consolidated Statements of Changes in Shareholders Equity - USD ($) | Common Stock | Additional Paid-In Capital | Treasury Stock | Retained Earnings [Member] | Total |
Beginning Balance, Amount at Dec. 31, 2013 | $ 77,000 | $ 943,000 | $ (1,536,000) | $ 21,557,000 | $ 21,041,000 |
Beginning Balance, Shares at Dec. 31, 2013 | 7,677,471 | 741,202 | |||
Net loss | 3,205,000 | 3,205,000 | |||
Ending Balance, Amount at Dec. 31, 2014 | $ 77,000 | 943,000 | $ (1,536,000) | 24,762,000 | 24,246,000 |
Enidng Balance, shares at Dec. 31, 2014 | 7,677,471 | 741,202 | |||
Net loss | (5,777,000) | (5,777,000) | |||
Ending Balance, Amount at Dec. 31, 2015 | $ 77,000 | 943,000 | $ (1,536,000) | 18,985,000 | 18,469,000 |
Enidng Balance, shares at Dec. 31, 2015 | 7,677,471 | 741,202 | |||
Net loss | 1,329,000 | 1,329,000 | |||
Ending Balance, Amount at Dec. 31, 2016 | $ 77,000 | $ 943,000 | $ (1,536,000) | $ 17,656,000 | $ 17,140,000 |
Enidng Balance, shares at Dec. 31, 2016 | 7,677,471 | 741,202 |
Consolidated Statements of Cash
Consolidated Statements of Cash Flows - USD ($) | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Cash Flows from Operating Activities | |||
Net Income (Loss) | $ (1,329,000) | $ (5,777,000) | $ 3,205,000 |
Reconciliation of net income (loss) to net cash provided by operating activities | |||
Depreciation and amortization | 1,104,000 | 2,426,000 | 1,846,000 |
Impairment of oil and gas properties | 695,000 | 5,116,000 | |
Accretion of asset retirement obligation | 36,000 | 35,000 | 42,000 |
Changes in accounts receivable | (93,000) | 318,000 | 1,480,000 |
Changes in income tax receivable | (173,000) | (582,000) | (172,000) |
Changes in accts payable & accrued liabilities | (518,000) | (545,000) | 2,322,000 |
Changes in current tax payable | (252,000) | ||
Changes in deferred tax payable | (472,000) | (1,338,000) | 65,000 |
Other | (3,000) | 12,000 | (14,000) |
Net cash provided (used) for operating activities | (753,000) | (335,000) | 8,522,000 |
Cash Flows from Investing Activities | |||
Capitalized acquisition, exploration and development | (990,000) | 1,114,000 | (3,357,000) |
Other long-term investments | 50,000 | ||
Refund of prepaid drilling costs | 232,000 | ||
Net cash used for investing activities | (708,000) | 1,114,000 | (3,357,000) |
Increase (decrease) in cash, cash equivalents, and restricted cash | (1,461,000) | (1,449,000) | 5,165,000 |
Cash, cash equivalents, and restricted cash at beginning of period | 12,845,000 | $ 9,129,000 | |
Cash, cash equivalents, and restricted cash at end of period | $ 11,384,000 | $ 12,845,000 |
Basis of Presentation
Basis of Presentation | 12 Months Ended |
Dec. 31, 2016 | |
Accounting Policies [Abstract] | |
Basis of Presentation | 1. BASIS OF PRESENTATION AND ORGANIZATION Merger and Basis of Presentation On July 13, 1990, Prairie States Energy Co., a Texas corporation, (the Company) merged with Spindletop Oil & Gas Co., a Utah corporation (the Acquired Company). The name of Prairie States Energy Co. was changed to Spindletop Oil & Gas Co., a Texas corporation at the time of the merger. Organization and Nature of Operations The Company was organized as a Texas corporation in September 1985, in connection with the Plan of Reorganization ("the Plan"), effective September 9, 1985, of Prairie States Exploration, Inc., ("Exploration"), a Colorado corporation, which had previously filed for Chapter 11 bankruptcy. In connection with the Plan, Exploration was merged into the Company, with the Company being the surviving corporation. Spindletop Oil & Gas Co. is engaged in the exploration, development and production of oil and natural gas; and through one of its subsidiaries, the gathering and marketing of natural gas. The Company owns land along with a commercial office building which contains approximately 46,286 of rentable square feet, of which the Company occupies approximately 12,759 rentable square feet as its corporate office headquarters. The Company leases the remaining space in the building to non-related third party commercial tenants at prevailing market rates. |
Summary of Significant Accounti
Summary of Significant Accounting Policies | 12 Months Ended |
Dec. 31, 2016 | |
Accounting Policies [Abstract] | |
Summary of Significant Accounting Policies | 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES A summary of the significant accounting policies consistently applied in the preparation of the accompanying financial statements follows: Consolidation The consolidated financial statements include the accounts of Spindletop Oil & Gas Co. and its wholly owned subsidiaries, Prairie Pipeline Co. and Spindletop Drilling Company. All significant inter-company transactions and accounts have been eliminated. Cash and Cash Equivalents The Company considers all highly liquid instruments with a maturity of three months or less at time of original issuance to be cash equivalents. Other Investments Other short-term and long-term investments consist of certificates of deposit with maturities of more than three months. Carrying amounts approximate fair value. Allowance for Doubtful Accounts The Company provides an allowance for doubtful accounts equal to the estimated uncollectible portion of accounts receivable. This estimate is based on historical collection experience and a review of the current status of accounts receivable. Oil and Gas Properties The Company follows the full cost method of accounting for its oil and gas properties. Accordingly, all costs associated with acquisition, exploration and development of oil and natural gas reserves are capitalized and accounted for in cost centers, on a country-by-country basis. For each cost center, capitalized costs, less accumulated amortization and related deferred income taxes, shall not exceed an amount (the cost center ceiling) equal to the sum of: e) The present value of estimated future net revenues computed by applying current prices of oil and natural gas reserves (with consideration of price changes only to the extent provided by contractual arrangements) to estimated future production of proved oil and gas reserves as of the date of the latest balance sheet presented, less estimated future expenditures (based on current costs) to be incurred in developing and producing the proved reserves computed using a discount factor of ten percent and assuming continuation of existing economic conditions; plus f) The cost of properties not being amortized; plus g) The lower of cost or estimated fair market value of unproven properties included in the costs being amortized; less h) Income tax effects related to differences between the book and tax basis of the properties. If unamortized costs capitalized within a cost center, less related deferred income taxes, exceed the cost center ceiling (as defined), the excess is charged to expense and separately disclosed during the period in which the excess occurs. Amounts required to be written off will not be reinstated for any subsequent increase in the cost center ceiling. For the years ended December 31, 2015 and 2016, the Company recorded an impairment expense in the carrying value of its proved oil and gas properties of $5,116,000 and $695,000 respectively. These impairments were due primarily to declines in the average realized prices for sales of its crude oil and natural gas. Depreciation and amortization for each cost center are computed on a composite unit-of-production method, based on estimated proven reserves attributable to the respective cost center. All costs associated with oil and gas properties are currently included in the base for computation and amortization. Such costs include all acquisition, exploration, development costs and estimated future expenditures for proved undeveloped properties as well as estimated dismantlement and abandonment costs as calculated under the asset retirement obligation category, net of salvage value. All of the Company's oil and gas properties are located within the continental United States. Gains and losses on sales of oil and gas properties are treated as adjustments of capitalized costs. Gains or losses on sales of property and equipment, other than oil and gas properties, are recognized as part of operations. Expenditures for renewals and improvements are capitalized, while expenditures for maintenance and repairs are charged to operations as incurred. Property and Equipment The Company, as operator, leases equipment to owners of oil and gas wells, on a month-to-month basis. The Company, as operator, transports natural gas through its natural gas gathering systems, in exchange for a fee. Depreciation is provided in amounts sufficient to relate the cost of depreciable assets to operations over their estimated service lives (5 to 10 years for rental equipment and natural gas gathering systems, 4 to 5 years for other property and equipment). The straight-line method of depreciation is used for financial reporting purposes, while accelerated methods are used for tax purposes. Real Estate Property The Company owns land along with a two-story commercial office building which is situated thereon. The Company occupies a portion of the building as its primary corporate headquarters, and leases the remaining space in the building to non-related third party commercial tenants at prevailing market rates. The Company depreciates the commercial office using the straight-line method of depreciation for financial statement and income tax purposes. Investments in Real Estate All investments in real estate holdings are stated at cost or adjusted carrying value. ASC Topic 360, “Accounting for the Impairment or Disposal of Long-Lived Assets”, requires that a property be considered impaired if the sum of the expected future cash flows (undiscounted and without interest charges) is less than the carrying amount of the property. If impairment exists, an impairment loss is recognized by a charge against earnings equal to the amount by which the carrying amount of the property exceeds fair market value less cost to sell the property. If impairment of a property is recognized, the carrying amount of the property is reduced by the amount of the impairment, and a new cost for the property is established. Depreciation is provided over the properties estimated remaining useful life. There was no charge to earnings during 2016, 2015, or 2014 due to impairment of real estate holdings. Accounting for Asset Retirement Obligations The Company adopted ASC Topic 410-20, "Accounting for Asset Retirement Obligations" on December 31, 2005. This statement requires the recording of a liability in the period in which an asset retirement obligation ("ARO") is incurred, in an amount equal to the discounted estimated fair value of the obligation that is capitalized. Thereafter, each quarter, this liability is accreted up to the final retirement cost. The determination of the ARO is based on an estimate of the future cost to plug and abandon our oil and gas wells. The actual costs could be higher or lower than current estimates. The following table reflects the changes of the asset retirement obligations during the period ending December 31; 2016 2015 Carrying amount of asset retirement obligation $ 1,121,000 $ 1,078,000 Liabilities added 18,000 54,000 Liabilities divested or settled (259,000) (46,000) Current period accretion expenses 36,000 35,000 Carrying amount as of December 31, $ 916,000 $ 1,121,000 Revenue Recognition The Company follows the “sales” (takes or cash) method of accounting for oil and natural gas revenues. Under this method, the Company recognizes revenues on oil and natural gas production as it is taken and delivered to the purchasers. The volumes sold may be more or less than the volumes the Company is entitled to take based on our ownership in the property. These differences result in a condition known as a production imbalance. Our crude oil and natural gas imbalances are insignificant. Income Taxes In June, 2006, an interpretation of ASC Topic 740-10, “Accounting for Uncertainty in Income Taxes” was issued. The interpretation creates a single model to address accounting for uncertainty in tax positions. Specifically, the pronouncement prescribes a recognition threshold and a measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. The interpretation also provides guidance on de-recognition, classification, interest and penalties, accounting in interim periods, disclosure and transition of certain tax positions. Federal and state tax authorities generally have the right to examine and audit the previous three years of tax returns filed. The Company accounts for income taxes pursuant to ASC Topic 740-10 "Accounting for Income Taxes" , which requires the recognition of deferred tax liabilities and assets for the expected future tax consequences of events that have been recognized in the Company's financial statements or tax returns. Under this method, deferred tax liabilities and assets are determined based on the difference between the financial statement carrying amounts and tax bases of assets and liabilities, using enacted tax rates in effect in the years in which the differences are expected to reverse. The temporary differences primarily relate to depreciation, depletion and intangible drilling costs. Use of Estimates The preparation of financial statements in conformity with U. S. Generally Accepted Accounting Principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Share-Based Payments Effective January 1, 2006, the Company adopted ASC Topic 718-10, “Share-Based Payment". ASC Topic 718-10 requires compensation costs related to share-based payments to be recognized in the income statement over the requisite service period. The amount of the compensation cost is to be measured based on the grant-date fair value of the instrument issued. ASC Topic 718-10 is effective for awards granted or modified after the date of adoption and for awards granted prior to that date that have not vested. ASC Topic 718-10 does not materially change the Company's existing accounting practices or the amount of share-based compensation recognized in earnings. Recently Issued Accounting Pronouncements In February 2016, the FASB issued Accounting Standards Update No. 2016-02: Leases (Topic 842). The FASB issued this Update to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. The accounting for Lessees relates primarily to finance leases and for operating leases. The Company does not currently have any finance or operating leases as a lessee. The accounting applied by a lessor is largely unchanged from that applied under previous GAAP. Under GAAP accounting, lessors should continue to recognize lease income for those leases on a generally straight-line basis over the lease term. The Company does lease space in its commercial office building to third-party tenants under rental lease agreements as the lessor, and recognizes lease income from tenants on a straight-line basis. The amendments in this Update are effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years for public business entities. The Company does not anticipate that this new guidance will have a material impact on the Company’s consolidated financial position or results of operations for the periods presented. In March 2016, the FASB issued Accounting Standards Update No. 2016-08: Revenue from Contracts with Customers (Topic 606), Principal versus Agent Considerations (Reporting Revenue Gross versus Net) and in April 2016, issued Accounting Standards Update No. 2016-10: Revenue from Contracts with Customers (Topic 606), Identifying Performance Obligations and Licensing. The Company does not anticipate that this new guidance will have a material impact on the Company’s consolidated financial position or results of operations for the periods presented. In May 2016, the FASB also issued Accounting Standards Updates No 2016-11 related to Revenue Recognition (Topic 605), Derivatives and Hedging (Topic 815) , and Accounting Standards Updates No 2016-12: Revenue from Contracts with Customers (Topic 606), Narrow-Scope Improvements and Practical Expedients. The Company does not anticipate that this new guidance will have a material impact on the Company’s consolidated financial position or results of operations for the periods presented. In March 2016, the FASB issued Accounting Standards Update No. 2016-09: Compensation-Stock Compensation (Topic 718), Improvements to Employee share-Based Payment Accounting. The Board issued this Update as part of its Simplification Initiative to identify, evaluate, and improve areas of generally accepted accounting principles (GASP) for which cost and complexity can be reduced while maintaining or improving the usefulness of the information provided to users of financial statements. The Company does not anticipate that this new guidance will have a material impact on the Company’s consolidated financial position or results of operations for the periods presented. For public business entities, the amendments in this Update are effective for annual periods beginning after December 15, 2016, and interim periods within those annual periods. The Company has adopted application of this Update for its financial statements issued for the year ended December 31, 2016. In August 2016, the FASB issued Accounting Standards Update No 2016-15: Statement of Cash Flows (Topic 230), Classification of Certain Cash Receipts and Cash Payments. The FASB issued this Accounting Standards Update to address eight specific cash flow issues with the objective of reducing the existing diversity in practice. The amendments in this Update are effective for public entities for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years. In November 2016, the FASB issued Accounting Standards Update No 2016-18: Statement of Cash Flows (Topic 230), Restricted Cash. The FASB issued this Accounting Standards Update to require that a statement of cash flows explain the change during the period in the total of cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents. The amendments in this Update are effective for public entities for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years. Currently, there are no other new accounting pronouncements that were issued to be effective in 2016 or subsequent thereto that would have a material impact on the Company’s financial reporting. Certain amounts in the 2015 financial statements have been reclassified for comparative purposes to conform to the 2016 presentation. Subsequent Events The Company has evaluated subsequent events through the issuance date of April 14, 2017. |
Account Receivable
Account Receivable | 12 Months Ended |
Dec. 31, 2016 | |
Notes to Financial Statements | |
Account Receivable | 3. ACCOUNTS RECEIVABLE December 31, 2016 2015 Trade $ 132,000 $ 167,000 Accrued receivable 1,811,000 1,683,000 1,943,000 1,850,000 Less: Allowance for losses (15,000) (15,000) $ 1,928,000 $ 1,835,000 Accrued receivables are receivables from purchasers of oil and gas. These revenues are booked from check stub detail after receipt of the check for sales of oil and natural gas products. These payments are for sales of oil and natural gas produced in the reporting period, but for which payment has not yet been received until after the closing date of the reporting period. Therefore these sales are accrued as receivables as of the balance sheet date. Revenues for oil and natural gas production that has been sold but for which payment has not yet been received is accrued in the period sold. |
Accounts Payable
Accounts Payable | 12 Months Ended |
Dec. 31, 2016 | |
Payables and Accruals [Abstract] | |
Accounts Payable | 4. ACCOUNTS PAYABLE December 31, 2016 2015 Trade payables $ 1,619,000 $ 1,609,000 Production proceeds payable 2,912,000 2,911,000 Prepaid drilling costs 760,000 1,289,000 $ 5,291,000 $ 5,809,000 |
Related Party Transactions
Related Party Transactions | 12 Months Ended |
Dec. 31, 2016 | |
Related Party Transactions [Abstract] | |
Related Party Transactions | 5. RELATED PARTY TRANSACTIONS On October 1, 2008, Giant entered into an Administrative Services Agreement with the Company whereby Giant pays the Company $250 per month for the Company providing administrative services to Giant. The Company also entered into a management services agreement with MRO whereby MRO made monthly payments in the amount of $1,000 per month to the Company in exchange for the Company providing administrative services to MRO. Effective August 1, 2015, MRO became inactive and the payment ceased. The Company’s agreement with MRO was terminated effective September 1, 2015. On October 1, 2008, the Company entered into a similar agreement with Giant NRG, LP (“NRG”) a limited partnership with Chris Mazzini and Michelle Mazzini as limited partners. Under this agreement NRG pays a monthly fee of $2,500 to the Company in exchange for the Company providing certain administrative services to NRG. Effective August 1, 2016, this administrative services fee was reduced to $1,500 per month. The Company has entered into a similar arrangement with Peveler Pipeline, LP ("Peveler"), whereby Peveler pays the Company a monthly charge of $250 in exchange for the Company providing administrative services to Peveler. Chris and Michelle Mazzini are the owners of Peveler Pipeline, LP, a limited partnership which owns a pipeline gathering system servicing wells owned by Giant, another related entity, described elsewhere in this report. The Company entered into a similar agreement with M-R Ventures, LLC (“MRV”) a limited liability company that operates some wells in Michigan, and that is owned by Chris and Michelle Mazzini. Pursuant to this agreement, MRV pays the Company a monthly fee in the amount of $500 for certain administrative services that the Company provides to MRV. The Company entered into a similar agreement with Reserve Royalty Company (“Reserve”) a sole proprietorship that holds some royalty interests owned by Chris and Michelle Mazzini. Pursuant to this agreement, Reserve pays the Company a monthly fee in the amount of $350 for certain administrative services that the Company provides to Reserve. |
Common Stock
Common Stock | 12 Months Ended |
Dec. 31, 2016 | |
Equity [Abstract] | |
Common Stock | 6. COMMON STOCK Effective January 1, 2006, the Company adopted ASC Topic 718-10, "Share-Based Payment". ASC Topic 718-10 requires compensation costs related to share-based payments to be recognized in the income statement over the requisite service period. The amount of the compensation cost is to be measured based on the grant date fair value of the instrument issued. ASC Topic 718-10 is effective for awards granted or modified after the date of adoption and for awards granted prior to that date that have not vested. ASC Topic 718-10 does not materially change the Company's existing accounting practices or the amount of share-based compensation recognized in earnings. During the three year period ending December 31, 2016, the Company did not issue any compensation related to share-based payments. The Company has not approved nor authorized any standing repurchase program for its common stock. The Company made no repurchases of its common stock during 2014, 2015 or 2016. The repurchased shares are held as Treasury Stock. |
Income Taxes
Income Taxes | 12 Months Ended |
Dec. 31, 2016 | |
Income Tax Disclosure [Abstract] | |
Income Taxes | 7. INCOME TAXES The Company accounts for income taxes pursuant to ASC Topic 740-10, "Accounting for Income Taxes". ASC Topic 740-10 utilizes the liability method of computing deferred income taxes. Income tax differed from the amounts computed by applying an effective United States federal income tax rate of 34% to pretax income in 2016, 2015 and 2014 as a result of the following: 2016 2015 2014 Computed expected tax expense (benefit) $ (671,000) $ (2,735,000) $ 1,290,000 Miscellaneous timing differences related to book and tax depletion differences and the expensing of intangible drilling costs 380,000 1,978,000 (764,000) NOL Carryforward 118,000 - - Correction of prior year estimate - (171,000) - Expected Federal income tax expense (benefit) $ (173,000) $ (928,000) $ 526,000 Income tax expense (benefit) for the years ended December 31, 2016, 2015 and 2014 consisted of the following: 2016 2015 2014 Federal income taxes (benefit) $ (173,000) $ (928,000) $ 526,000 State income taxes - - - Current income tax provision (benefit) $ (173,000) $ (928,000) $ 526,000 Deferred income taxes reflect the effects of temporary differences between the tax bases of assets and liabilities and the reported amounts of those assets and liabilities for financial reporting purposes. Deferred income taxes also reflect the value of investment tax credits and an offsetting valuation allowance. The Company's total deferred tax assets and corresponding valuation allowance at December 31, 2016 and 2015 consisted of the following: December 31, 2016 2015 Deferred tax assets Depletion and amortization 1,137,000 1,186,000 Expired leasehold 250,000 190,000 Other, net 7,000 7,000 Total deferred tax assets 1,394,000 1,383,000 Deferred tax liabilities Intangible drilling costs (1,323,000) (1,801,000) Depreciation (89,000) (72,000) Total deferred tax liability (1,412,000) (1,873,000) Net deferred income tax payable $ (18,000) $ (490,000) |
Cash Flow Information
Cash Flow Information | 12 Months Ended |
Dec. 31, 2016 | |
Supplemental Cash Flow Elements [Abstract] | |
Cash Flow Information | 8. CASH FLOW INFORMATION The Company does not consider any of its assets, other than cash and certificates of deposit shown as cash on the balance sheet, to meet the definition of a cash equivalent. Net cash provided by operating activities includes cash payments for the following: 2016 2015 2014 Income taxes $ - $ 50,000 $ 950,000 Excluded from the Consolidated Statements of Cash Flows were the effects of certain non-cash investing and financing activities, as follows: 2016 2015 2014 Addition (Reduction) of oil & gas properties by recognitions of asset retirement obligation $ (239,000) $ 8,000 $ (71,000) $ (239,000) $ 8,000 $ (71,000) |
Earnings Per Share
Earnings Per Share | 12 Months Ended |
Dec. 31, 2016 | |
Earnings Per Share [Abstract] | |
Earnings Per Share | 9. EARNINGS PER SHARE Earnings per share ("EPS") are calculated in accordance with ASC Topic 260-10, "Earnings per Share", which was adopted in 1997 for all years presented. Basic EPS is computed by dividing income available to common shareholders by the weighted average number of common shares outstanding during the period. The adoption of ASC Topic 260-10 had no effect on previously reported EPS. Diluted EPS is computed based on the weighted number of shares outstanding, plus the additional common shares that would have been issued had the options outstanding been exercised. |
Concentration of Credit Risk
Concentration of Credit Risk | 12 Months Ended |
Dec. 31, 2016 | |
Risks and Uncertainties [Abstract] | |
Concentration of Credit Risk | 10. CONCENTRATIONS OF CREDIT RISK Subsequent to December 31, 2012, FDIC Deposit Insurance coverage changed. As scheduled, the unlimited insurance coverage for noninterest-bearing transaction accounts provided under the Dodd-Frank Wall Street Reform and Consumer Protection Act expired on December 31, 2012. Deposits held in non-interest-bearing transaction accounts at the same institution are now aggregated with any interest-bearing deposits the owner may hold in the same ownership category, and the combined total insured up to at least $250,000. As of December 31, 2016 the Company had approximately $ 8,597,000 Most of the Company's business activity is located in Texas. Accounts receivable as of December 31, 2016 and 2015 are due from both individual and institutional owners of joint interests in oil and gas wells as well as purchasers of oil and natural gas. A portion of the Company's ability to collect these receivables is dependent upon revenues generated from sales of oil and natural gas produced by the related wells. |
Financial Instruments
Financial Instruments | 12 Months Ended |
Dec. 31, 2016 | |
Investments, All Other Investments [Abstract] | |
Financial Instruments | 11. FINANCIAL INSTRUMENTS The estimated fair value of the Company's financial instruments at December 31, 2016 and 2015 follows: 2016 2015 Carrying Amount Fair Value Carrying Amount Fair Value Cash $ 11,021,000 $ 11,021,000 $ 12,381,000 $ 12,381,000 Restricted cash 363,000 363,000 464,000 464,000 Long-term investments 1,550,000 1,550,000 1,600,000 1,600,000 Accounts receivable, trade 1,928,000 1,928,000 1,835,000 1,835,000 The fair value amounts for each of the financial instruments listed above approximate carrying amounts due to the short maturities of these instruments. |
Commitments and Contingencies
Commitments and Contingencies | 12 Months Ended |
Dec. 31, 2016 | |
Commitments and Contingencies Disclosure [Abstract] | |
Commitments and Contingencies | 12. COMMITMENTS AND CONTINGENCIES The Company's oil and gas exploration and production activities are subject to Federal, State and environmental quality and pollution control laws and regulations. Such regulations restrict emission and discharge of wastes from wells, may require permits for the drilling of wells, prescribe the spacing of wells and rate of production, and require prevention and clean-up of pollution. Although the Company has not in the past incurred substantial costs in complying with such laws and regulations, future environmental restrictions or requirements may materially increase the Company's capital expenditures, reduce earnings, and delay or prohibit certain activities. At December 31, 2016 the Company has acquired bonds and letters of credit issued in favor of various state regulatory agencies as mandated by state law in order to comply with financial assurance regulations required to perform oil and gas operations within the various state jurisdictions. The Company has seven, $5,000 single-well bonds totaling $35,000 and one $10,000 single well bond with an insurance company, for wells the Company operates in Alabama. The $5,000 bonds are written for a three year period and have been expiration dates of August 1, 2019. The $10,000 bond is written for a one year period and expires February 28, 2017. Subsequent to year-end, this bond has been extended through February 28, 2018. The Company has nine letters of credit from a bank issued for the benefit of various state regulatory agencies in Texas, New Mexico, Oklahoma, and Louisiana, ranging in amounts from $17,875 to $100,000 and totaling $363,000. These letters of credit are fully secured by funds on deposit with the bank in business money market accounts. There are seven letters of credit that automatically extend for a period of one year unless cancelled by the beneficiary and two letters of credit that automatically extend for a period of five years unless cancelled by the beneficiary. The Company also has six letters of credit secured with six certificates of deposit at a second bank totaling $428,680. The letters of credit have expiration dates ranging from March 31, 2017 to February 23, 2020. |
Additional Operations and Balan
Additional Operations and Balance Sheet Information | 12 Months Ended |
Dec. 31, 2016 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Additional Operations and Balance Sheet Information | 13. ADDITIONAL OPERATIONS AND BALANCE SHEET INFORMATION Certain information about the Company's operations for the years ended December 31, 2016, 2015 and 2014 follows. Dependence on Customers The following is a summary of a partial list of purchasers / operators (listed by percent of total oil and natural gas sales) from oil and natural gas produced by the Company for the three-year period ended December 31, 2016: Purchaser / Operator 2016 2015 2014 Targa Midstream Services, LLC 14% 9% 8% ETX Energy, LLC formerly New Gulf Resources 13% 16% 9% Sunoco Partners Marketing 12% 5% 5% Eastex Crude Company 10% 8% 7% Enlink Gas Marketing, LTD. 9% 6% 4% Shell Trading (US) Company 4% 4% 5% OXY USA, Inc. 4% 4% 0% Midcoast Energy Partners LP 4% 2% 2% Pruet Production Co. 3% 7% 6% LPC Crude Oil Marketing LLC 3% 2% 2% DCP Midstream, LP 3% 2% 1% Valero Energy Corporation 2% 3% 1% Enervest Operating, LLC 2% 2% 2% Agave Energy Company 2% 1% 2% Phillips 66 1% 2% 1% Linear Energy Management LLC 1% 0% 0% ETC Texas Pipeline, Ltd 1% 0% 0% Courson Oil & Gas, Inc. 1% 1% 0% Sandridge Energy, Inc. 1% 0% 0% Empire Pipeline Corp. 1% 1% 1% XTO Energy, Inc. 1% 1% 1% Ward Petrolum Corporation 1% 2% 1% Enterprise Crude Oil, LLC 1% 2% 2% Range Resources Corporation 1% 0% 0% Corum Production Company 1% 0% 0% Webb Energy Resources, Inc. 1% 0% 0% Sklar Exploration Co., LLC 0% 0% 1% BP America Production Company 0% 1% 0% Engridge Energy Partners 0% 7% 12% Halcon Resources Operating, Inc. 0% 0% 9% Holly Corp (Formerly Navajo Refining Co.) 0% 0% 2% Oil and natural gas is sold to approximately 95 different purchasers Except as set forth above, there are no other customers of the Company that individually accounted for more than one percent of the Company's oil and gas revenues during the three years ended December 31, 2016. The Company currently has no hedged contracts. Certain revenues, costs and expenses related to the Company's oil and gas operations are as follows: Year Ended December 31, 2016 2015 2014 Capitalized costs relating to oil and gas producing activities: Unproved properties $ 1,891,000 $ 1,872,000 $ 1,847,000 Proved properties 27,770,000 27,272,000 26,220,000 Total capitalized costs 29,661,000 29,144,000 28,067,000 Accumulated amortization (23,557,000) (21,824,000) (14,357,000) Total capitalized costs, net $ 6,104,000 7,320,000 13,710,000 Year Ended December 31, 2016 2015 2014 Costs incurred in oil and gas property acquisitions, exploration and development: Acquisition of properties $ 470,000 $ 15,000 $ 413,000 Development costs 281,000 1,549,000 2,617,000 Total costs incurred $ 751,000 $ 1,564,000 $ 3,030,000 Year Ended December 31, 2016 2015 2014 Results of operations from producing activities: Sales of oil and gas $ 3,320,000 $ 4,841,000 $ 11,688,000 Production costs 1,920,000 2,965,000 3,236,000 Amortization of oil and gas properties 1,038,000 2,351,000 1,771,000 Total production costs 2,958,000 5,316,000 5,007,000 Total net revenue $ 362,000 $ (475,000) $ 6,681,000 Year Ended December 31, 2016 2015 2014 Sales price per equivalent Mcf $ 3.76 $ 4.34 $ 9.17 Production costs per equivalent Mcf $ 2.17 $ 2.66 $ 2.54 Amortization per equivalent Mcf $ 1.17 $ 2.11 $ 1.39 Year Ended December 31, 2016 2015 2014 Results of operations from gas gathering and equipment rental activities: Revenue $ 114,000 $ 141,000 $ 155,000 Operating expenses 46,000 32,000 49,000 Depreciation 13,000 13,000 6,000 Total costs 59,000 45,000 55,000 Total net revenue $ 55,000 $ 96,000 $ 100,000 |
Business Segments
Business Segments | 12 Months Ended |
Dec. 31, 2016 | |
Segment Reporting [Abstract] | |
Business Segments | 14. BUSINESS SEGMENTS The Company's three business segments are (1) oil and gas exploration, acquisition, production and operations, (2) transportation and compression of natural gas, and (3) commercial real estate investment. Management has chosen to organize the Company into the three segments based on the products or services provided. The following is a summary of selected information for these segments for the three-year period ended December 31, 2016: Year Ended December 31, 2016 2015 2014 Revenues: (1) Oil and gas exploration, production $ 3,735,000 $ 5,322,000 $ 12,169,000 and operations Gas gathering, compression and 114,000 141,000 155,000 equipment rental Real estate rental 314,000 230,000 240,000 $ 4,163,000 $ 5,693,000 $ 12,564,000 Year Ended December 31, 2016 2015 2014 Depreciation, depletion, and amortization expense: Oil and gas exploration, production $ 1,043,000 $ 2,365,000 $ 1,788,000 and operations Impairment of oil and gas assets 695,000 5,116,000 - Gas gathering, compression and 13,000 13,000 6,000 equipment rental Real estate rental 48,000 48,000 52,000 $ 1,799,000 $ 7,542,000 $ 1,846,000 Year Ended December 31, 2016 2015 2014 Income (loss) from operations: Oil and gas exploration, production $ 40,000 $ (5,159,000) $ 7,097,000 and operations Gas gathering, compression and 55,000 96,000 106,000 equipment rental Real estate rental 91,000 (33,000) (32,000) 186,000 (5,096,000) 7,171,000 Corporate and other (2) (1,515,000) (681,000) (3,966,000) Consolidated net income (loss) $ (1,329,000) $ (5,777,000) $ 3,205,000 Year Ended December 31, 2016 2015 2014 Identifiable assets net of DDA: Oil and gas exploration, production and operations $ 6,139,000 $ 7,361,000 $ 13,722,000 Gas gathering, compression and equipment rental 10,000 23,000 35,000 Real estate rental 1,418,000 1,465,000 1,512,000 7,567,000 8,849,000 15,269,000 Corporate and other (3) 15,798,000 17,040,000 18,237,000 Consolidated total assets $ 23,365,000 $ 25,889,000 $ 33,506,000 Note (1): All reported revenues are from external customers. Note (2): Corporate and other includes general and administrative expenses, other non-operating income and expense and income taxes. Note (3): Corporate and other includes cash, accounts and notes receivable, inventory, other property and equipment and intangible assets. |
Supplementory Income Statement
Supplementory Income Statement | 12 Months Ended |
Dec. 31, 2016 | |
Notes to Financial Statements | |
Supplementory Income Statement | 15. SUPPLEMENTARY INCOME STATEMENT INFORMATION The following items were charged directly to expense: Year Ended December 31, 2016 2015 2014 Maintenance and repairs $ 12,000 $ 21,000 $ 40,000 Production taxes 127,000 190,000 582,000 Taxes, other than payroll and income taxes 8,000 35,000 48,000 |
Quarterly Data
Quarterly Data | 12 Months Ended |
Dec. 31, 2016 | |
Quarterly Financial Information Disclosure [Abstract] | |
Quarterly Data | 16. QUARTERLY DATA (UNAUDITED) The table below reflects selected quarterly information for the years ended December 31, 2016, 2015 and 2014. Year Ended December 31, 2016 First Quarter Second Quarter Third Quarter Fourth Quarter Revenue $ 893,000 $ 1,356,000 $ 1,089,000 $ 1,177,000 Expense (1,345,000) (1,540,000) (1,347,000) (2,257,000) Operating income (loss) (452,000) (184,000) (258,000) (1,080,000) Current tax (provision) benefit - - - 173,000 Deferred tax (provision) benefit 152,000 270,000 155,000 105,000 Net income (loss) $ (300,000) $ 86,000 $ (103,000) $ (1,012,000) Earnings (loss) per share of common stock Basic and diluted $ (0.04) $ 0.01 $ (0.01) $ (0.15) Year Ended December 31, 2015 First Quarter Second Quarter Third Quarter Fourth Quarter Revenue $ 1,456,000 $ 1,496,000 $ 1,551,000 $ 1,441,000 Expense (1,895,000) (2,110,000) (2,097,000) (7,885,000) Operating income (loss) (439,000) (614,000) (546,000) (6,444,000) Current tax (provision) benefit 50,000 384,000 (262,000) 756,000 Deferred tax (provision) benefit 233,000 278,000 329,000 498,000 Net income (loss) $ (156,000) $ 48,000 $ (479,000) $ (5,190,000) Earnings (loss) per share of common stock Basic and diluted $ (0.02) $ 0.01 $ (0.07) $ (0.75) Year Ended December 31, 2014 First Quarter Second Quarter Third Quarter Fourth Quarter Revenue $ 3,568,000 $ 3,893,000 $ 3,174,000 $ 2,573,000 Expense (2,047,000) (2,513,000) (2,001,000) (2,851,000) Operating income (loss) 1,521,000 1,380,000 1,173,000 (278,000) Current tax (provision) benefit (216,000) 39,000 (136,000) (213,000) Deferred tax (provision) benefit (290,000) (100,000) (107,000) 432,000 Net income (loss) $ 1,015,000 $ 1,319,000 $ 930,000 $ (59,000) Earnings (loss) per share of common stock Basic and diluted $ 0.15 $ 0.19 $ 0.13 $ (0.01) |
Supplemental Reserve Informatio
Supplemental Reserve Information | 12 Months Ended |
Dec. 31, 2016 | |
Notes to Financial Statements | |
Supplemental Reserve Information | 17. SUPPLEMENTAL RESERVE INFORMATION (UNAUDITED) The Company’s net proved oil and natural gas reserves as of December 31, 2016, 2015, and 2014, have been estimated by Company personnel. All estimates are in accordance generally accepted petroleum engineering and evaluation principles and definitions and with guidelines established by the Securities and Exchange Commission. All of the Company’s reserves are located in the United States of America and accounted for under one cost center. Our policies and practices regarding internal control over the estimating of reserves are structured to objectively and accurately estimate our oil and natural gas reserve quantities and present values in compliance with the U.S. Securities and Exchange Commission (“SEC”) regulations and accounting principles generally accepted in the United States of America. We maintain an internal staff of petroleum engineers and geosciences professionals who work closely with the accounting and financial departments to insure the integrity, accuracy and timeliness of data used in the estimation process. The data used in our reserve estimation process is based on historical results for production, oil and natural gas prices received, lease operating expenses and development costs incurred, ownership interest and other required data. Historical oil and natural gas prices, lease operating expenses, and ownership interests are provided by and verified by the Company’s accounting department. The Petroleum Engineer responsible for the supervision and preparation of the Company’s internally generated reserve report has a Bachelor of Science degree in Petroleum Engineering from a major university and has experience in preparing economic evaluations and reserve estimates. He meets the requirements regarding qualifications, objectivity and confidentiality set forth in the Standards Pertaining to the Engineering and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. The Company has established a written internal control procedure to verify that the data entered into our engineering evaluation software is complete and correct. These internal control procedures establish the source of the data both internally and externally, the personnel that will collect the data and testing of the data collected to ensure its accuracy. The following reserve estimates were based on existing economic and operating conditions. Oil and natural gas prices for 2016, 2015, and 2014 were calculated using a 12-month average price, calculated as the un-weighted arithmetic average of the first-day-of-the month price for each month of each year. Operating costs, production and ad valorem taxes and future development costs were based on current costs with no escalation. There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting the future rates of production and timing of development expenditures. The following reserve data represents estimates only and should not be construed as being exact. Moreover, the present values should not be construed as the current market value of the Company's oil and natural gas reserves or the costs that would be incurred to obtain equivalent reserves. Changes in Estimated Quantities of Proved Oil and Gas Reserves (Unaudited): Quantities of Proved Reserves: Crude Oil Bbls Natural Gas Mcf Balance December 31, 2013 449,880 6,762,330 Sales of reserves in place - - Acquired properties 8,910 - Extensions and discoveries 10,240 69,870 Revisions of previous estimates * 24,544 747,239 Production (89,068) (739,948) Balance December 31, 2014 404,506 6,839,491 Sales of reserves in place - (121,810) Acquired properties - - Extensions and discoveries 38,800 107,480 Revisions of previous estimates * (93,559) (2,054,712) Production (64,207) (730,709) Balance December 31, 2015 285,540 4,039,740 Sales of reserves in place - - Acquired properties 65,520 118,030 Extensions and discoveries 17,150 4,670 Revisions of previous estimates * (4,682) 262,897 Production (50,248) (582,348) Balance December 31, 2016 313,280 3,842,989 * May also include divestitures, not only changes in engineering. Proved Developed Reserves: Balance December 31, 2014 404,506 6,839,491 Balance December 31, 2015 285,540 4,039,740 Balance December 31, 2016 313,280 3,842,989 Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Oil and Natural Gas Reserves (Unaudited) The Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Oil and Natural Gas Reserves ("Standardized Measures") does not purport to present the fair market value of a company's oil and gas properties. An estimate of such value should consider, among other factors, anticipated future prices of oil and natural gas, the probability of recoveries in excess of existing proved reserves, the value of probable reserves and acreage prospects, and perhaps different discount rates. It should be noted that estimates of reserve quantities, especially from new discoveries, are inherently imprecise and subject to substantial revision. Reserve estimates were prepared in accordance with standard Security and Exchange Commission guidelines. The future net cash flow for 2016, 2015, and 2014, was computed using a 12-month average price, calculated as the un-weighted arithmetic average of the first-day-of-the month price for each month of the year. Lease operating costs, compression, dehydration, transportation, ad valorem taxes, severance taxes, and federal income taxes were deducted. Costs and prices were held constant and were not escalated over the life of the properties. No deduction has been made for interest, or general corporate overhead. The annual discount of estimated future cash flows is defined, for use herein, as future cash flows discounted at 10% per year, over the expected period of realization. Proved Developed Reserves were calculated based on Decline Curve Analysis on 53 operated wells and 42 non-operated wells The Company emphasizes that reserve estimates are inherently imprecise. Accordingly, the estimates are expected to change as more current information becomes available. It is reasonably possible that, because of changes in market conditions or the inherent imprecision of these reserve estimates, that the estimates of future cash inflows, future gross revenues, the amount of oil and natural gas reserves, the remaining estimated lives of the oil and natural gas properties, or any combination of the above may be increased or reduced in the near term. If reduced, the carrying amount of capitalized oil and gas properties may be reduced materially in the near term. Year Ended December 31, 2016 2015 2014 Future production revenue $ 19,964,000 $ 21,230,000 $ 63,857,000 Future development costs - - - Future production costs (10,801,000) (10,989,000) (27,073,000) Future net cash flow before Federal income taxes 9,163,000 10,241,000 36,784,000 Future income taxes (2,566,000) (2,867,000) (10,300,000) Future net cash flows 6,597,000 7,374,000 26,484,000 Effect of 10% annual discounting (574,000) (368,000) (4,266,000) Standardized measure of discounted cash flows $ 6,023,000 $ 7,006,000 $ 22,218,000 Changes in the standardized measure of discounted future net cash flows: Year Ended December 31, 2016 2015 2014 Beginning of the year $ 7,006,000 $ 22,218,000 $ 24,161,000 Sales of oil and gas, net of production costs (1,332,000) (1,785,000) (8,041,000) Net changes in prices and production costs (662,000) (16,505,000) (969,000) Extensions, discoveries, additions less related costs 271,000 937,000 345,000 Development costs incurred 267,000 1,474,000 2,490,000 Net changes in future development cost - - (103,000) Revisions of previous quantity estimates (756,000) (1,965,000) 1,474,000 Net change in purchase and sales of minerals in place 884,000 - 116,000 Accretion of discount 701,000 2,222,000 2,416,000 Net change in income taxes (80,000) 1,516,000 (22,000) Other (276,000) (1,106,000) 351,000 End of year $ 6,023,000 $ 7,006,000 $ 22,218,000 SPINDLETOP OIL & GAS CO. AND SUBSIDIARIES VALUATION AND QUALIFYING ACCOUNTS YEARS ENDED DECEMBER 31, 2016, 2015, AND 2014 SCHEDULE I I Balance Costs & Expenses Deductions Ending Balance Allowance for doubtful accounts December 31, 2014 $15,000 $- $- $15,000 December 31, 2015 $15,000 $- $- $15,000 December 31, 2016 $15,000 $- $- $15,000 SCHEDULE III SPINDLETOP OIL & GAS CO. AND SUBSIDIARIES REAL ESTATE AND ACCUMULATED DEPRECIATION Initial Cost to Corporation Total Cost Description Encumbrances Land Buildings Subsequent to Acquist'n Two story multi-tenant garden office building with sub-grade parking garage located in Dallas, Texas (b) $ 688,000 $ 1,298,000 $ 282,000 Gross amounts at which carried at close of year Land Buildings Total Accumulated Depreciation Life on which Depreciation Calculated Date Acquired $ 688,000 $1,580,000 $ 2,268,000 $ 850,000 (a) 12/27/2004 Notes to Schedule III (a) See Footnote 2 to the Financial Statements outlining depreciation methods and lives. (b) None (c) The reconciliation for investments in real estate and accumulated depreciation for the years ended December 31, 2016 are as follows Investments in Real Estate Accumulated Depreciation Balance, December 31, 2005 $ 1,986,000 $ 49,000 Acquisitions 210,000 Depreciation expense 71,000 Balance, December 31, 2006 2,196,000 120,000 Acquisitions 34,000 Depreciation expense 84,000 Balance, December 31, 2007 2,230,000 204,000 Acquisitions 38,000 Depreciation expense 96,000 Balance, December 31, 2008 2,268,000 300,000 Acquisitions Depreciation expense 100,000 Balance, December 31, 2009 2,268,000 400,000 Acquisitions Depreciation expense 101,000 Balance, December 31, 2010 2,268,000 501,000 Acquisitions Depreciation expense 100,000 Balance, December 31, 2011 2,268,000 601,000 Acquisitions Depreciation expense 51,000 Balance, December 31, 2012 2,268,000 652,000 Acquisitions Depreciation expense 52,000 Balance, December 31, 2013 2,268,000 704,000 Acquisitions Depreciation expense 52,000 Balance, December 31, 2014 2,268,000 756,000 Acquisitions Depreciation expense 47,000 Balance, December 31, 2015 2,268,000 803,000 Acquisitions Depreciation expense 47,000 Balance, December 31, 2016 2,268,000 850,000 |
Basis of Presentation (Policies
Basis of Presentation (Policies) | 12 Months Ended |
Dec. 31, 2016 | |
Accounting Policies [Abstract] | |
Merger and Basis of Presentation | Merger and Basis of Presentation On July 13, 1990, Prairie States Energy Co., a Texas corporation, (the Company) merged with Spindletop Oil & Gas Co., a Utah corporation (the Acquired Company). The name of Prairie States Energy Co. was changed to Spindletop Oil & Gas Co., a Texas corporation at the time of the merger. |
Organization and Nature of Operations | Organization and Nature of Operations The Company was organized as a Texas corporation in September 1985, in connection with the Plan of Reorganization ("the Plan"), effective September 9, 1985, of Prairie States Exploration, Inc., ("Exploration"), a Colorado corporation, which had previously filed for Chapter 11 bankruptcy. In connection with the Plan, Exploration was merged into the Company, with the Company being the surviving corporation. Spindletop Oil & Gas Co. is engaged in the exploration, development and production of oil and natural gas; and through one of its subsidiaries, the gathering and marketing of natural gas. The Company owns land along with a commercial office building which contains approximately 46,286 of rentable square feet, of which the Company occupies approximately 12,759 rentable square feet as its corporate office headquarters. The Company leases the remaining space in the building to non-related third party commercial tenants at prevailing market rates. |
Summary of Significant Accoun25
Summary of Significant Accounting Policies (Policies) | 12 Months Ended |
Dec. 31, 2016 | |
Accounting Policies [Abstract] | |
Consolidation | Consolidation The consolidated financial statements include the accounts of Spindletop Oil & Gas Co. and its wholly owned subsidiaries, Prairie Pipeline Co. and Spindletop Drilling Company. All significant inter-company transactions and accounts have been eliminated. |
Cash and Cash Equivalents | Cash and Cash Equivalents The Company considers all highly liquid instruments with a maturity of three months or less at time of original issuance to be cash equivalents. |
Other Investments | Other Investments Other short-term and long-term investments consist of certificates of deposit with maturities of more than three months. Carrying amounts approximate fair value. |
Allowance for Doubtful Accounts | Allowance for Doubtful Accounts The Company provides an allowance for doubtful accounts equal to the estimated uncollectible portion of accounts receivable. This estimate is based on historical collection experience and a review of the current status of accounts receivable |
Oil and Gas Properties | Oil and Gas Properties The Company follows the full cost method of accounting for its oil and gas properties. Accordingly, all costs associated with acquisition, exploration and development of oil and natural gas reserves are capitalized and accounted for in cost centers, on a country-by-country basis. For each cost center, capitalized costs, less accumulated amortization and related deferred income taxes, shall not exceed an amount (the cost center ceiling) equal to the sum of: e) The present value of estimated future net revenues computed by applying current prices of oil and natural gas reserves (with consideration of price changes only to the extent provided by contractual arrangements) to estimated future production of proved oil and gas reserves as of the date of the latest balance sheet presented, less estimated future expenditures (based on current costs) to be incurred in developing and producing the proved reserves computed using a discount factor of ten percent and assuming continuation of existing economic conditions; plus f) The cost of properties not being amortized; plus g) The lower of cost or estimated fair market value of unproven properties included in the costs being amortized; less h) Income tax effects related to differences between the book and tax basis of the properties. If unamortized costs capitalized within a cost center, less related deferred income taxes, exceed the cost center ceiling (as defined), the excess is charged to expense and separately disclosed during the period in which the excess occurs. Amounts required to be written off will not be reinstated for any subsequent increase in the cost center ceiling. For the years ended December 31, 2015 and 2016, the Company recorded an impairment expense in the carrying value of its proved oil and gas properties of $5,116,000 and $695,000 respectively. These impairments were due primarily to declines in the average realized prices for sales of its crude oil and natural gas. Depreciation and amortization for each cost center are computed on a composite unit-of-production method, based on estimated proven reserves attributable to the respective cost center. All costs associated with oil and gas properties are currently included in the base for computation and amortization. Such costs include all acquisition, exploration, development costs and estimated future expenditures for proved undeveloped properties as well as estimated dismantlement and abandonment costs as calculated under the asset retirement obligation category, net of salvage value. All of the Company's oil and gas properties are located within the continental United States. Gains and losses on sales of oil and gas properties are treated as adjustments of capitalized costs. Gains or losses on sales of property and equipment, other than oil and gas properties, are recognized as part of operations. Expenditures for renewals and improvements are capitalized, while expenditures for maintenance and repairs are charged to operations as incurred. |
Property and Equipment | Property and Equipment The Company, as operator, leases equipment to owners of oil and gas wells, on a month-to-month basis. The Company, as operator, transports natural gas through its natural gas gathering systems, in exchange for a fee. Depreciation is provided in amounts sufficient to relate the cost of depreciable assets to operations over their estimated service lives (5 to 10 years for rental equipment and natural gas gathering systems, 4 to 5 years for other property and equipment). The straight-line method of depreciation is used for financial reporting purposes, while accelerated methods are used for tax purposes. |
Real Estate Property | Real Estate Property The Company owns land along with a two-story commercial office building which is situated thereon. The Company occupies a portion of the building as its primary corporate headquarters, and leases the remaining space in the building to non-related third party commercial tenants at prevailing market rates. The Company depreciates the commercial office using the straight-line method of depreciation for financial statement and income tax purposes. |
Investments in Real Estate | Investments in Real Estate All investments in real estate holdings are stated at cost or adjusted carrying value. ASC Topic 360, “Accounting for the Impairment or Disposal of Long-Lived Assets”, requires that a property be considered impaired if the sum of the expected future cash flows (undiscounted and without interest charges) is less than the carrying amount of the property. If impairment exists, an impairment loss is recognized by a charge against earnings equal to the amount by which the carrying amount of the property exceeds fair market value less cost to sell the property. If impairment of a property is recognized, the carrying amount of the property is reduced by the amount of the impairment, and a new cost for the property is established. Depreciation is provided over the properties estimated remaining useful life. There was no charge to earnings during 2016, 2015, or 2014 due to impairment of real estate holdings. |
Accounting for Asset Retirement Obligations | Accounting for Asset Retirement Obligations The Company adopted ASC Topic 410-20, "Accounting for Asset Retirement Obligations" on December 31, 2005. This statement requires the recording of a liability in the period in which an asset retirement obligation ("ARO") is incurred, in an amount equal to the discounted estimated fair value of the obligation that is capitalized. Thereafter, each quarter, this liability is accreted up to the final retirement cost. The determination of the ARO is based on an estimate of the future cost to plug and abandon our oil and gas wells. The actual costs could be higher or lower than current estimates. The following table reflects the changes of the asset retirement obligations during the period ending December 31; 2016 2015 Carrying amount of asset retirement obligation $ 1,121,000 $ 1,078,000 Liabilities added 18,000 54,000 Liabilities divested or settled (259,000) (46,000) Current period accretion expenses 36,000 35,000 Carrying amount as of December 31, $ 916,000 $ 1,121,000 |
Revenue Recognition | Revenue Recognition The Company follows the “sales” (takes or cash) method of accounting for oil and natural gas revenues. Under this method, the Company recognizes revenues on oil and natural gas production as it is taken and delivered to the purchasers. The volumes sold may be more or less than the volumes the Company is entitled to take based on our ownership in the property. These differences result in a condition known as a production imbalance. Our crude oil and natural gas imbalances are insignificant. |
Income Taxes | Income Taxes In June, 2006, an interpretation of ASC Topic 740-10, “Accounting for Uncertainty in Income Taxes” was issued. The interpretation creates a single model to address accounting for uncertainty in tax positions. Specifically, the pronouncement prescribes a recognition threshold and a measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. The interpretation also provides guidance on de-recognition, classification, interest and penalties, accounting in interim periods, disclosure and transition of certain tax positions. Federal and state tax authorities generally have the right to examine and audit the previous three years of tax returns filed. The Company accounts for income taxes pursuant to ASC Topic 740-10 "Accounting for Income Taxes" , which requires the recognition of deferred tax liabilities and assets for the expected future tax consequences of events that have been recognized in the Company's financial statements or tax returns. Under this method, deferred tax liabilities and assets are determined based on the difference between the financial statement carrying amounts and tax bases of assets and liabilities, using enacted tax rates in effect in the years in which the differences are expected to reverse. The temporary differences primarily relate to depreciation, depletion and intangible drilling costs. |
Use of Estimates | Use of Estimates The preparation of financial statements in conformity with U. S. Generally Accepted Accounting Principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. |
Share-Based Payments | Share-Based Payments Effective January 1, 2006, the Company adopted ASC Topic 718-10, “Share-Based Payment". ASC Topic 718-10 requires compensation costs related to share-based payments to be recognized in the income statement over the requisite service period. The amount of the compensation cost is to be measured based on the grant-date fair value of the instrument issued. ASC Topic 718-10 is effective for awards granted or modified after the date of adoption and for awards granted prior to that date that have not vested. ASC Topic 718-10 does not materially change the Company's existing accounting practices or the amount of share-based compensation recognized in earnings. |
Recently Issued Accounting Pronouncements | Recently Issued Accounting Pronouncements In February 2016, the FASB issued Accounting Standards Update No. 2016-02: Leases (Topic 842). The FASB issued this Update to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. The accounting for Lessees relates primarily to finance leases and for operating leases. The Company does not currently have any finance or operating leases as a lessee. The accounting applied by a lessor is largely unchanged from that applied under previous GAAP. Under GAAP accounting, lessors should continue to recognize lease income for those leases on a generally straight-line basis over the lease term. The Company does lease space in its commercial office building to third-party tenants under rental lease agreements as the lessor, and recognizes lease income from tenants on a straight-line basis. The amendments in this Update are effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years for public business entities. The Company does not anticipate that this new guidance will have a material impact on the CompanyÂ’s consolidated financial position or results of operations for the periods presented. In March 2016, the FASB issued Accounting Standards Update No. 2016-08: Revenue from Contracts with Customers (Topic 606), Principal versus Agent Considerations (Reporting Revenue Gross versus Net) and in April 2016, issued Accounting Standards Update No. 2016-10: Revenue from Contracts with Customers (Topic 606), Identifying Performance Obligations and Licensing. The Company does not anticipate that this new guidance will have a material impact on the CompanyÂ’s consolidated financial position or results of operations for the periods presented. In May 2016, the FASB also issued Accounting Standards Updates No 2016-11 related to Revenue Recognition (Topic 605), Derivatives and Hedging (Topic 815) , and Accounting Standards Updates No 2016-12: Revenue from Contracts with Customers (Topic 606), Narrow-Scope Improvements and Practical Expedients. The Company does not anticipate that this new guidance will have a material impact on the CompanyÂ’s consolidated financial position or results of operations for the periods presented. In March 2016, the FASB issued Accounting Standards Update No. 2016-09: Compensation-Stock Compensation (Topic 718), Improvements to Employee share-Based Payment Accounting. The Board issued this Update as part of its Simplification Initiative to identify, evaluate, and improve areas of generally accepted accounting principles (GASP) for which cost and complexity can be reduced while maintaining or improving the usefulness of the information provided to users of financial statements. The Company does not anticipate that this new guidance will have a material impact on the CompanyÂ’s consolidated financial position or results of operations for the periods presented. For public business entities, the amendments in this Update are effective for annual periods beginning after December 15, 2016, and interim periods within those annual periods. The Company has adopted application of this Update for its financial statements issued for the year ended December 31, 2016. In August 2016, the FASB issued Accounting Standards Update No 2016-15: Statement of Cash Flows (Topic 230), Classification of Certain Cash Receipts and Cash Payments. The FASB issued this Accounting Standards Update to address eight specific cash flow issues with the objective of reducing the existing diversity in practice. The amendments in this Update are effective for public entities for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years. In November 2016, the FASB issued Accounting Standards Update No 2016-18: Statement of Cash Flows (Topic 230), Restricted Cash. The FASB issued this Accounting Standards Update to require that a statement of cash flows explain the change during the period in the total of cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents. The amendments in this Update are effective for public entities for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years. Currently, there are no other new accounting pronouncements that were issued to be effective in 2016 or subsequent thereto that would have a material impact on the CompanyÂ’s financial reporting. Certain amounts in the 2015 financial statements have been reclassified for comparative purposes to conform to the 2016 presentation. |
Subsequent Events | Subsequent Events The Company has evaluated subsequent events through the issuance date of April 14, 2017. |
Summary of Significant Accoun26
Summary of Significant Accounting Policies (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Accounting Policies [Abstract] | |
Asset Retirement Obligation | 2016 2015 Carrying amount of asset retirement obligation $ 1,121,000 $ 1,078,000 Liabilities added 18,000 54,000 Liabilities divested or settled (259,000) (46,000) Current period accretion expenses 36,000 35,000 Carrying amount as of December 31, $ 916,000 $ 1,121,000 |
Account Receivable (Tables)
Account Receivable (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Notes to Financial Statements | |
Accounts Receivable | December 31, 2016 2015 Trade $ 132,000 $ 167,000 Accrued receivable 1,811,000 1,683,000 1,943,000 1,850,000 Less: Allowance for losses (15,000) (15,000) $ 1,928,000 $ 1,835,000 |
Accounts Payable (Tables)
Accounts Payable (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Payables and Accruals [Abstract] | |
Accounts Payable | December 31, 2016 2015 Trade payables $ 1,619,000 $ 1,609,000 Production proceeds payable 2,912,000 2,911,000 Prepaid drilling costs 760,000 1,289,000 $ 5,291,000 $ 5,809,000 |
Income Taxes (Tables)
Income Taxes (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Income Tax Disclosure [Abstract] | |
Income Tax Expense (Benefit) | 2016 2015 2014 Computed expected tax expense (benefit) $ (671,000) $ (2,735,000) $ 1,290,000 Miscellaneous timing differences related to book and tax depletion differences and the expensing of intangible drilling costs 380,000 1,978,000 (764,000) NOL Carryforward 118,000 - - Correction of prior year estimate - (171,000) - Expected Federal income tax expense (benefit) $ (173,000) $ (928,000) $ 526,000 Income tax expense (benefit) for the years ended December 31, 2016, 2015 and 2014 consisted of the following: 2016 2015 2014 Federal income taxes (benefit) $ (173,000) $ (928,000) $ 526,000 State income taxes - - - Current income tax provision (benefit) $ (173,000) $ (928,000) $ 526,000 |
Deferred Tax | December 31, 2016 2015 Deferred tax assets Depletion and amortization 1,137,000 1,186,000 Expired leasehold 250,000 190,000 Other, net 7,000 7,000 Total deferred tax assets 1,394,000 1,383,000 Deferred tax liabilities Intangible drilling costs (1,323,000) (1,801,000) Depreciation (89,000) (72,000) Total deferred tax liability (1,412,000) (1,873,000) Net deferred income tax payable $ (18,000) $ (490,000) |
Cash Flow Information (Tables)
Cash Flow Information (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Supplemental Cash Flow Elements [Abstract] | |
Cash Flow | Net cash provided by operating activities includes cash payments for the following: 2016 2015 2014 Income taxes $ - $ 50,000 $ 950,000 Excluded from the Consolidated Statements of Cash Flows were the effects of certain non-cash investing and financing activities, as follows: 2016 2015 2014 Addition (Reduction) of oil & gas properties by recognitions of asset retirement obligation $ (239,000) $ 8,000 $ (71,000) $ (239,000) $ 8,000 $ (71,000) |
Financial Instruments (Tables)
Financial Instruments (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Investments, All Other Investments [Abstract] | |
Financial Instruments | 2016 2015 Carrying Amount Fair Value Carrying Amount Fair Value Cash $ 11,021,000 $ 11,021,000 $ 12,381,000 $ 12,381,000 Restricted cash 363,000 363,000 464,000 464,000 Long-term investments 1,550,000 1,550,000 1,600,000 1,600,000 Accounts receivable, trade 1,928,000 1,928,000 1,835,000 1,835,000 |
Additional Operations and Bal32
Additional Operations and Balance Sheet Information (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Significant purchasers / operators | Purchaser / Operator 2016 2015 2014 Targa Midstream Services, LLC 14% 9% 8% ETX Energy, LLC formerly New Gulf Resources 13% 16% 9% Sunoco Partners Marketing 12% 5% 5% Eastex Crude Company 10% 8% 7% Enlink Gas Marketing, LTD. 9% 6% 4% Shell Trading (US) Company 4% 4% 5% OXY USA, Inc. 4% 4% 0% Midcoast Energy Partners LP 4% 2% 2% Pruet Production Co. 3% 7% 6% LPC Crude Oil Marketing LLC 3% 2% 2% DCP Midstream, LP 3% 2% 1% Valero Energy Corporation 2% 3% 1% Enervest Operating, LLC 2% 2% 2% Agave Energy Company 2% 1% 2% Phillips 66 1% 2% 1% Linear Energy Management LLC 1% 0% 0% ETC Texas Pipeline, Ltd 1% 0% 0% Courson Oil & Gas, Inc. 1% 1% 0% Sandridge Energy, Inc. 1% 0% 0% Empire Pipeline Corp. 1% 1% 1% XTO Energy, Inc. 1% 1% 1% Ward Petrolum Corporation 1% 2% 1% Enterprise Crude Oil, LLC 1% 2% 2% Range Resources Corporation 1% 0% 0% Corum Production Company 1% 0% 0% Webb Energy Resources, Inc. 1% 0% 0% Sklar Exploration Co., LLC 0% 0% 1% BP America Production Company 0% 1% 0% Engridge Energy Partners 0% 7% 12% Halcon Resources Operating, Inc. 0% 0% 9% Holly Corp (Formerly Navajo Refining Co.) 0% 0% 2% |
Revenues, costs and expenses related to the Company's oil and gas operations | Certain revenues, costs and expenses related to the Company's oil and gas operations are as follows: Year Ended December 31, 2016 2015 2014 Capitalized costs relating to oil and gas producing activities: Unproved properties $ 1,891,000 $ 1,872,000 $ 1,847,000 Proved properties 27,770,000 27,272,000 26,220,000 Total capitalized costs 29,661,000 29,144,000 28,067,000 Accumulated amortization (23,557,000) (21,824,000) (14,357,000) Total capitalized costs, net $ 6,104,000 7,320,000 13,710,000 Year Ended December 31, 2016 2015 2014 Costs incurred in oil and gas property acquisitions, exploration and development: Acquisition of properties $ 470,000 $ 15,000 $ 413,000 Development costs 281,000 1,549,000 2,617,000 Total costs incurred $ 751,000 $ 1,564,000 $ 3,030,000 Year Ended December 31, 2016 2015 2014 Results of operations from producing activities: Sales of oil and gas $ 3,320,000 $ 4,841,000 $ 11,688,000 Production costs 1,920,000 2,965,000 3,236,000 Amortization of oil and gas properties 1,038,000 2,351,000 1,771,000 Total production costs 2,958,000 5,316,000 5,007,000 Total net revenue $ 362,000 $ (475,000) $ 6,681,000 Year Ended December 31, 2016 2015 2014 Sales price per equivalent Mcf $ 3.76 $ 4.34 $ 9.17 Production costs per equivalent Mcf $ 2.17 $ 2.66 $ 2.54 Amortization per equivalent Mcf $ 1.17 $ 2.11 $ 1.39 Year Ended December 31, 2016 2015 2014 Results of operations from gas gathering and equipment rental activities: Revenue $ 114,000 $ 141,000 $ 155,000 Operating expenses 46,000 32,000 49,000 Depreciation 13,000 13,000 6,000 Total costs 59,000 45,000 55,000 Total net revenue $ 55,000 $ 96,000 $ 100,000 |
Business Segments (Tables)
Business Segments (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Segment Reporting [Abstract] | |
Business Segments | Year Ended December 31, 2016 2015 2014 Revenues: (1) Oil and gas exploration, production $ 3,735,000 $ 5,322,000 $ 12,169,000 and operations Gas gathering, compression and 114,000 141,000 155,000 equipment rental Real estate rental 314,000 230,000 240,000 $ 4,163,000 $ 5,693,000 $ 12,564,000 Year Ended December 31, 2016 2015 2014 Depreciation, depletion, and amortization expense: Oil and gas exploration, production $ 1,043,000 $ 2,365,000 $ 1,788,000 and operations Impairment of oil and gas assets 695,000 5,116,000 - Gas gathering, compression and 13,000 13,000 6,000 equipment rental Real estate rental 48,000 48,000 52,000 $ 1,799,000 $ 7,542,000 $ 1,846,000 Year Ended December 31, 2016 2015 2014 Income (loss) from operations: Oil and gas exploration, production $ 40,000 $ (5,159,000) $ 7,097,000 and operations Gas gathering, compression and 55,000 96,000 106,000 equipment rental Real estate rental 91,000 (33,000) (32,000) 186,000 (5,096,000) 7,171,000 Corporate and other (2) (1,515,000) (681,000) (3,966,000) Consolidated net income (loss) $ (1,329,000) $ (5,777,000) $ 3,205,000 Year Ended December 31, 2016 2015 2014 Identifiable assets net of DDA: Oil and gas exploration, production and operations $ 6,139,000 $ 7,361,000 $ 13,722,000 Gas gathering, compression and equipment rental 10,000 23,000 35,000 Real estate rental 1,418,000 1,465,000 1,512,000 7,567,000 8,849,000 15,269,000 Corporate and other (3) 15,798,000 17,040,000 18,237,000 Consolidated total assets $ 23,365,000 $ 25,889,000 $ 33,506,000 |
Supplementory Income Statement
Supplementory Income Statement (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Notes to Financial Statements | |
Supplementary Income statement | Year Ended December 31, 2016 2015 2014 Maintenance and repairs $ 12,000 $ 21,000 $ 40,000 Production taxes 127,000 190,000 582,000 Taxes, other than payroll and income taxes 8,000 35,000 48,000 |
Quarterly Data (Tables)
Quarterly Data (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Quarterly Financial Information Disclosure [Abstract] | |
Quarterly Data | Year Ended December 31, 2016 First Quarter Second Quarter Third Quarter Fourth Quarter Revenue $ 893,000 $ 1,356,000 $ 1,089,000 $ 1,177,000 Expense (1,345,000) (1,540,000) (1,347,000) (2,257,000) Operating income (loss) (452,000) (184,000) (258,000) (1,080,000) Current tax (provision) benefit - - - 173,000 Deferred tax (provision) benefit 152,000 270,000 155,000 105,000 Net income (loss) $ (300,000) $ 86,000 $ (103,000) $ (1,012,000) Earnings (loss) per share of common stock Basic and diluted $ (0.04) $ 0.01 $ (0.01) $ (0.15) Year Ended December 31, 2015 First Quarter Second Quarter Third Quarter Fourth Quarter Revenue $ 1,456,000 $ 1,496,000 $ 1,551,000 $ 1,441,000 Expense (1,895,000) (2,110,000) (2,097,000) (7,885,000) Operating income (loss) (439,000) (614,000) (546,000) (6,444,000) Current tax (provision) benefit 50,000 384,000 (262,000) 756,000 Deferred tax (provision) benefit 233,000 278,000 329,000 498,000 Net income (loss) $ (156,000) $ 48,000 $ (479,000) $ (5,190,000) Earnings (loss) per share of common stock Basic and diluted $ (0.02) $ 0.01 $ (0.07) $ (0.75) Year Ended December 31, 2014 First Quarter Second Quarter Third Quarter Fourth Quarter Revenue $ 3,568,000 $ 3,893,000 $ 3,174,000 $ 2,573,000 Expense (2,047,000) (2,513,000) (2,001,000) (2,851,000) Operating income (loss) 1,521,000 1,380,000 1,173,000 (278,000) Current tax (provision) benefit (216,000) 39,000 (136,000) (213,000) Deferred tax (provision) benefit (290,000) (100,000) (107,000) 432,000 Net income (loss) $ 1,015,000 $ 1,319,000 $ 930,000 $ (59,000) Earnings (loss) per share of common stock Basic and diluted $ 0.15 $ 0.19 $ 0.13 $ (0.01) |
Supplemental Reserve Informat36
Supplemental Reserve Information (Tables) | 12 Months Ended |
Dec. 31, 2016 | |
Notes to Financial Statements | |
Quantities of Proved Reserves | Quantities of Proved Reserves: Crude Oil Bbls Natural Gas Mcf Balance December 31, 2013 449,880 6,762,330 Sales of reserves in place - - Acquired properties 8,910 - Extensions and discoveries 10,240 69,870 Revisions of previous estimates * 24,544 747,239 Production (89,068) (739,948) Balance December 31, 2014 404,506 6,839,491 Sales of reserves in place - (121,810) Acquired properties - - Extensions and discoveries 38,800 107,480 Revisions of previous estimates * (93,559) (2,054,712) Production (64,207) (730,709) Balance December 31, 2015 285,540 4,039,740 Sales of reserves in place - - Acquired properties 65,520 118,030 Extensions and discoveries 17,150 4,670 Revisions of previous estimates * (4,682) 262,897 Production (50,248) (582,348) Balance December 31, 2016 313,280 3,842,989 * May also include divestitures, not only changes in engineering. Proved Developed Reserves: Balance December 31, 2014 404,506 6,839,491 Balance December 31, 2015 285,540 4,039,740 Balance December 31, 2016 313,280 3,842,989 |
Standardized measure of discounted future net cash flows related to proved reserves: | Year Ended December 31, 2016 2015 2014 Future production revenue $ 19,964,000 $ 21,230,000 $ 63,857,000 Future development costs - - - Future production costs (10,801,000) (10,989,000) (27,073,000) Future net cash flow before Federal income taxes 9,163,000 10,241,000 36,784,000 Future income taxes (2,566,000) (2,867,000) (10,300,000) Future net cash flows 6,597,000 7,374,000 26,484,000 Effect of 10% annual discounting (574,000) (368,000) (4,266,000) Standardized measure of discounted cash flows $ 6,023,000 $ 7,006,000 $ 22,218,000 |
Changes in the standardized measure of discounted future net cash flows: | Year Ended December 31, 2016 2015 2014 Beginning of the year $ 7,006,000 $ 22,218,000 $ 24,161,000 Sales of oil and gas, net of production costs (1,332,000) (1,785,000) (8,041,000) Net changes in prices and production costs (662,000) (16,505,000) (969,000) Extensions, discoveries, additions less related costs 271,000 937,000 345,000 Development costs incurred 267,000 1,474,000 2,490,000 Net changes in future development cost - - (103,000) Revisions of previous quantity estimates (756,000) (1,965,000) 1,474,000 Net change in purchase and sales of minerals in place 884,000 - 116,000 Accretion of discount 701,000 2,222,000 2,416,000 Net change in income taxes (80,000) 1,516,000 (22,000) Other (276,000) (1,106,000) 351,000 End of year $ 6,023,000 $ 7,006,000 $ 22,218,000 |
Allowance for doubtful accounts | SCHEDULE I I Balance Costs & Expenses Deductions Ending Balance Allowance for doubtful accounts December 31, 2014 $15,000 $- $- $15,000 December 31, 2015 $15,000 $- $- $15,000 December 31, 2016 $15,000 $- $- $15,000 |
Real Estate | SCHEDULE III SPINDLETOP OIL & GAS CO. AND SUBSIDIARIES REAL ESTATE AND ACCUMULATED DEPRECIATION Initial Cost to Corporation Total Cost Description Encumbrances Land Buildings Subsequent to Acquist'n Two story multi-tenant garden office building with sub-grade parking garage located in Dallas, Texas (b) $ 688,000 $ 1,298,000 $ 282,000 Gross amounts at which carried at close of year Land Buildings Total Accumulated Depreciation Life on which Depreciation Calculated Date Acquired $ 688,000 $1,580,000 $ 2,268,000 $ 850,000 (a) 12/27/2004 Notes to Schedule III (a) See Footnote 2 to the Financial Statements outlining depreciation methods and lives. (b) None |
Basis of Presentation (Details)
Basis of Presentation (Details) | 12 Months Ended |
Dec. 31, 2016 | |
Basis Of Presentation Details | |
Rental square feet | The Company owns land along with a commercial office building which contains approximately 46,286 of rentable square feet, of which the Company occupies approximately 12,759 rentable square feet as its corporate office headquarters. |
Summary of Significant Accoun38
Summary of Significant Accounting Policies (Details Narrative 1) - USD ($) | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Summary Of Significant Accounting Policies Details Narrative 1 | |||
Impairment of oil & gas properties | $ 695,000 | $ 5,116,000 |
Summary of Significant Accoun39
Summary of Significant Accounting Policies - Asset Retirement Obligation (Details) - USD ($) | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Accounting Policies [Abstract] | |||
Carrying amount of asset retirement obligation | $ 1,121,000 | $ 1,078,000 | |
Liabilities added | 18,000 | 54,000 | |
Liabilities divested or settled | (259,000) | (46,000) | |
Current period accretion expenses | 36,000 | 35,000 | $ 42,000 |
Carrying amount as of December 31, | $ 916,000 | $ 1,121,000 | $ 1,078,000 |
Summary of Significant Accoun40
Summary of Significant Accounting Policies (Details Narrative 2) | 12 Months Ended |
Dec. 31, 2014 | |
Rental Properties [Member] | Minimum [Member] | |
Acquired Finite-Lived Intangible Assets [Line Items] | |
Estimated life | 5 years |
Rental Properties [Member] | Maximum | |
Acquired Finite-Lived Intangible Assets [Line Items] | |
Estimated life | 10 years |
Gas Gathering [Member] | Minimum [Member] | |
Acquired Finite-Lived Intangible Assets [Line Items] | |
Estimated life | 4 years |
Gas Gathering [Member] | Maximum | |
Acquired Finite-Lived Intangible Assets [Line Items] | |
Estimated life | 5 years |
Account Receivable (Details)
Account Receivable (Details) - USD ($) | Dec. 31, 2016 | Dec. 31, 2015 |
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||
Account receivable, gross | $ 1,943,000 | $ 1,850,000 |
Less: Allowance for losses | (15,000) | (15,000) |
Accounts receivable, trade | 1,928,000 | 1,835,000 |
Trade Receivables [Member] | ||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||
Account receivable, gross | 132,000 | 167,000 |
Accrued Receivables [Member] | ||
Accounts, Notes, Loans and Financing Receivable [Line Items] | ||
Account receivable, gross | $ 1,811,000 | $ 1,683,000 |
Accounts Payable - Accounts Pay
Accounts Payable - Accounts Payable (Details) - USD ($) | Dec. 31, 2016 | Dec. 31, 2015 |
Payables and Accruals [Abstract] | ||
Trade payables | $ 1,619,000 | $ 1,609,000 |
Production proceeds payable | 2,912,000 | 2,911,000 |
Prepaid drilling costs | 760,000 | 1,289,000 |
Accounts payable and accrued liabilities | $ 5,291,000 | $ 5,809,000 |
Related Party Transactions (Det
Related Party Transactions (Details Narrative) | Oct. 01, 2008USD ($) |
Giant [Member] | |
Related Party Transaction [Line Items] | |
Monthly Fees | $ 250 |
MRO [Member] | |
Related Party Transaction [Line Items] | |
Monthly Fees | 1,000 |
NRG [Member] | |
Related Party Transaction [Line Items] | |
Monthly Fees | 2,500 |
Peveler [Member] | |
Related Party Transaction [Line Items] | |
Monthly Fees | 250 |
MRV [Member] | |
Related Party Transaction [Line Items] | |
Monthly Fees | 500 |
Reserve [Member] | |
Related Party Transaction [Line Items] | |
Monthly Fees | $ 350 |
Income Taxes - Income Tax Expen
Income Taxes - Income Tax Expense (Benefit) (Details) - USD ($) | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Income Tax Disclosure [Abstract] | |||
Computed expected tax expense (benefit) | $ (671,000) | $ (2,735,000) | $ 1,290,000 |
Miscellaneous timing differences related to book and tax depletion differences and the expensing of intangible drilling costs | 380,000 | 1,978,000 | (764,000) |
NOL Carryforward | 118,000 | ||
Correction of prior year estimate | (171,000) | ||
Expected Federal income tax expense (benefit) | (173,000) | (928,000) | 526,000 |
Current income tax provision (benefit) | $ (173,000) | $ (928,000) | $ 526,000 |
Income Taxes - Deferred Tax (De
Income Taxes - Deferred Tax (Details) - USD ($) | Dec. 31, 2016 | Dec. 31, 2015 |
Deferred tax assets | ||
Depreciation and amortization | $ 1,137,000 | $ 1,186,000 |
Expired leasehold | 250,000 | 190,000 |
Other, net | 7,000 | 7,000 |
Net deferred tax asset | 1,394,000 | 1,383,000 |
Deferred tax liabilities | ||
Intangible drilling costs | (1,323,000) | (1,801,000) |
Depreciation | (89,000) | (72,000) |
Total deferred tax liability | (1,412,000) | (1,873,000) |
Net deferred tax liability | $ (18,000) | $ (490,000) |
Income Taxes (Details Narrative
Income Taxes (Details Narrative) | 12 Months Ended |
Dec. 31, 2014 | |
Income Tax Disclosure [Abstract] | |
Effective tax rate | 34.00% |
Cash Flow Information - Cash Fl
Cash Flow Information - Cash Flow (Details) - USD ($) | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Net cash provided by operating activities includes cash payments for the following: | |||
Income taxes | $ 50,000 | $ 950,000 | |
Excluded from the Consolidated Statements of Cash Flows were the effects of certain non-cash investing and financing activities, as follows: | |||
Addition (Reductions) of oil & gas properties by recognitions of asset retirement obligation | $ (239,000) | $ 8,000 | $ (71,000) |
Concentration of Credit Risk (D
Concentration of Credit Risk (Details Narrative) | 12 Months Ended |
Dec. 31, 2016USD ($) | |
Concentration Risk [Line Items] | |
FDIC Insured | $ 250,000 |
Certificate of Deposit [Member] | |
Concentration Risk [Line Items] | |
FIDC Insured | Exceeds 9,835,000 |
Bank One [Member] | |
Concentration Risk [Line Items] | |
Checking and money market accounts | $ 8,597,000 |
Other Banks [Member] | |
Concentration Risk [Line Items] | |
Long term investments | $ 3,939,000 |
Financial Instruments - Financi
Financial Instruments - Financial Instruments (Details) - USD ($) | Dec. 31, 2016 | Dec. 31, 2015 |
Investments, All Other Investments [Abstract] | ||
Cash and cash equivalents | $ 11,021,000 | $ 12,381,000 |
Cash, Fair Value | 11,021,000 | 12,381,000 |
Restricted cash | 363,000 | 464,000 |
Restricted cash, Fair Value | 363,000 | 464,000 |
Other long-term investments | 1,550,000 | 1,600,000 |
Other long-term investments, Fair Value | 1,550,000 | 1,600,000 |
Accounts receivable, trade | 1,928,000 | 1,835,000 |
Accounts receivable, Fair Value | $ 1,928,000 | $ 1,835,000 |
Commitments and Contingencies (
Commitments and Contingencies (Details Narrative) | Dec. 31, 2016USD ($) | |
Single-well bonds [Member] | ||
Other Commitments [Line Items] | ||
Single-well bonds | $ 35,000 | [1] |
Single-well bonds Additional | ||
Other Commitments [Line Items] | ||
Single-well bonds | 10,000 | |
Letters of Credit [Member] | ||
Other Commitments [Line Items] | ||
Single-well bonds | 363,000 | [2] |
Letters of Credit [Member] | Minimum [Member] | ||
Other Commitments [Line Items] | ||
Single-well bonds | 17,875 | |
Letters of Credit [Member] | Maximum [Member] | ||
Other Commitments [Line Items] | ||
Single-well bonds | 100,000 | |
Letters of Credit Additional [Member] | ||
Other Commitments [Line Items] | ||
Single-well bonds | $ 428,680 | |
[1] | Seven, $5,000 single-well | |
[2] | Nine Letters of credit |
Additional Operations and Bal51
Additional Operations and Balance Sheet Information - Significant purchasers / operators (Details) | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Targa Midstream Services, LLC [Member] | |||
Product Information [Line Items] | |||
Significant Purchaser | 14.00% | 9.00% | 8.00% |
ETX Energy, LLC formerly New Gulf Resources [Member] | |||
Product Information [Line Items] | |||
Significant Purchaser | 13.00% | 16.00% | 9.00% |
Sunoco Partners Marketing[Member] | |||
Product Information [Line Items] | |||
Significant Purchaser | 12.00% | 5.00% | 5.00% |
Eastex Crude Company [Member] | |||
Product Information [Line Items] | |||
Significant Purchaser | 10.00% | 8.00% | 7.00% |
Enlink Gas Marketing, LTD. [Member] | |||
Product Information [Line Items] | |||
Significant Purchaser | 9.00% | 6.00% | 4.00% |
Shell Trading (US) Company[Member] | |||
Product Information [Line Items] | |||
Significant Purchaser | 4.00% | 4.00% | 5.00% |
OXY USA, Inc.[Member] | |||
Product Information [Line Items] | |||
Significant Purchaser | 4.00% | 4.00% | 0.00% |
Midcoast Energy Partners LP[Member] | |||
Product Information [Line Items] | |||
Significant Purchaser | 4.00% | 2.00% | 2.00% |
Pruet Production Co.[Member] | |||
Product Information [Line Items] | |||
Significant Purchaser | 3.00% | 7.00% | 6.00% |
LPC Crude Oil Marketing LLC[Member] | |||
Product Information [Line Items] | |||
Significant Purchaser | 3.00% | 2.00% | 2.00% |
DCP Midstream, LP[Member] | |||
Product Information [Line Items] | |||
Significant Purchaser | 3.00% | 2.00% | 1.00% |
Valero Energy Corporation[Member] | |||
Product Information [Line Items] | |||
Significant Purchaser | 2.00% | 3.00% | 1.00% |
Enervest Operating, LLC[Member] | |||
Product Information [Line Items] | |||
Significant Purchaser | 2.00% | 2.00% | 2.00% |
Agave Energy Company[Member] | |||
Product Information [Line Items] | |||
Significant Purchaser | 2.00% | 1.00% | 2.00% |
Phillips 66[Member] | |||
Product Information [Line Items] | |||
Significant Purchaser | 1.00% | 2.00% | 1.00% |
Linear Energy Management LLCMember] | |||
Product Information [Line Items] | |||
Significant Purchaser | 1.00% | 0.00% | 0.00% |
ETC Texas Pipeline, Ltd [Member] | |||
Product Information [Line Items] | |||
Significant Purchaser | 1.00% | 0.00% | 0.00% |
Courson Oil & Gas, Inc.[Member] | |||
Product Information [Line Items] | |||
Significant Purchaser | 1.00% | 1.00% | 0.00% |
Sandridge Energy, Inc.[Member] | |||
Product Information [Line Items] | |||
Significant Purchaser | 1.00% | 0.00% | 0.00% |
Empire Pipeline Corp..[Member] | |||
Product Information [Line Items] | |||
Significant Purchaser | 1.00% | 1.00% | 1.00% |
XTO Energy, Inc.[Member] | |||
Product Information [Line Items] | |||
Significant Purchaser | 1.00% | 1.00% | 1.00% |
Ward Petrolum Corporation[Member] | |||
Product Information [Line Items] | |||
Significant Purchaser | 1.00% | 2.00% | 1.00% |
Enterprise Crude Oil, LLC[Member] | |||
Product Information [Line Items] | |||
Significant Purchaser | 1.00% | 2.00% | 2.00% |
Range Resources Corporation[Member] | |||
Product Information [Line Items] | |||
Significant Purchaser | 1.00% | 0.00% | 0.00% |
Corum Production Company[Member] | |||
Product Information [Line Items] | |||
Significant Purchaser | 1.00% | 0.00% | 0.00% |
Webb Energy Resources, Inc.[Member] | |||
Product Information [Line Items] | |||
Significant Purchaser | 1.00% | 0.00% | 0.00% |
Sklar Exploration Co., LLC[Member] | |||
Product Information [Line Items] | |||
Significant Purchaser | 0.00% | 0.00% | 1.00% |
BP America Production Company[Member] | |||
Product Information [Line Items] | |||
Significant Purchaser | 0.00% | 1.00% | 0.00% |
Engridge Energy Partners[Member] | |||
Product Information [Line Items] | |||
Significant Purchaser | 0.00% | 7.00% | 12.00% |
Halcon Resources Operating, Inc.[Member] | |||
Product Information [Line Items] | |||
Significant Purchaser | 0.00% | 0.00% | 9.00% |
Holly Corp (Formerly Navajo Refining Co)[Member] | |||
Product Information [Line Items] | |||
Significant Purchaser | 0.00% | 0.00% | 2.00% |
Additional Operations and Bal52
Additional Operations and Balance Sheet Information - Revenues, costs and expenses related to the Company's oil and gas operations (Details) - USD ($) | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 |
Capitalized costs relating to oil and gas producing activities: | |||
Unproved properties | $ 1,891,000 | $ 1,872,000 | $ 1,847,000 |
Proved properties | 27,770,000 | 27,272,000 | 26,220,000 |
Total capitalized costs | 29,661,000 | 29,144,000 | 28,067,000 |
Accumulated amortization | (23,557,000) | (21,824,000) | (14,357,000) |
Total capitalized costs, net | $ 6,104,000 | $ 7,320,000 | $ 13,710,000 |
Additional Operations and Bal53
Additional Operations and Balance Sheet Information (Details 2) - USD ($) | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Costs incurred in oil and gas property acquisitions, exploration and development: | |||
Acquisition of properties | $ 470,000 | $ 15,000 | $ 413,000 |
Development costs | 281,000 | 1,549,000 | 2,617,000 |
Total costs incurred | $ 751,000 | $ 1,564,000 | $ 3,030,000 |
Additional Operations and Bal54
Additional Operations and Balance Sheet Information (Details 3) - Oil and gas exploration, acquisition, production and operations [Member] - USD ($) | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Result of operations from producing activities: | |||
Oil and gas revenues | $ 3,320,000 | $ 4,841,000 | $ 11,688,000 |
Production costs | 1,920,000 | 2,965,000 | 3,236,000 |
Amortization of oil and gas properties | 1,038,000 | 2,351,000 | 1,771,000 |
Total production costs | 2,958,000 | 5,316,000 | 5,007,000 |
Total net revenue | $ 362,000 | $ (475,000) | $ 6,681,000 |
Additional Operations and Bal55
Additional Operations and Balance Sheet Information (Details 4) - $ / Mcf | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |||
Sales price per equivalent Mcf | 3.76 | 4.34 | 9.17 |
Production costs per equivalent Mcf | 2.17 | 2.66 | 2.54 |
Amortization per equivalent Mcf | 1.17 | 2.11 | 1.39 |
Additional Operations and Bal56
Additional Operations and Balance Sheet Information (Details 5) - Gas Gathering [Member] - USD ($) | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Results of opeations from gas gathering and equipment rental activities: | |||
Revenue | $ 114,000 | $ 141,000 | $ 155,000 |
Operataing costs | 46,000 | 32,000 | 49,000 |
Amortization/Depreciation | 13,000 | 13,000 | 6,000 |
Total production costs | 59,000 | 45,000 | 55,000 |
Total net revenue | $ 55,000 | $ 96,000 | $ 100,000 |
Business Segments - Business Se
Business Segments - Business Segments (Details) - USD ($) | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Segment Reporting Information [Line Items] | |||
Revenue | $ 4,163,000 | $ 5,693,000 | $ 12,564,000 |
Depreciation, depletion, and amortization | 1,799,000 | 7,542,000 | 1,846,000 |
Income from operations | (1,329,000) | (5,777,000) | 3,205,000 |
Identifiable assets net of DDA | 23,365,000 | 25,889,000 | 33,506,000 |
Impairment of oil and gas assets[Member] | |||
Segment Reporting Information [Line Items] | |||
Depreciation, depletion, and amortization | 695,000 | 5,116,000 | |
Gas gathering, compression and equipment rental [Member] | |||
Segment Reporting Information [Line Items] | |||
Revenue | 114,000 | 141,000 | 155,000 |
Depreciation, depletion, and amortization | 13,000 | 13,000 | |
Income from operations | 55,000 | 96,000 | 106,000 |
Identifiable assets net of DDA | 10,000 | 23,000 | 35,000 |
Commercial real estate investment [Member] | |||
Segment Reporting Information [Line Items] | |||
Revenue | 314,000 | 230,000 | 240,000 |
Depreciation, depletion, and amortization | 48,000 | 48,000 | 52,000 |
Income from operations | 91,000 | (33,000) | (32,000) |
Subtotal [Member] | |||
Segment Reporting Information [Line Items] | |||
Income from operations | 186,000 | (5,096,000) | 7,171,000 |
Identifiable assets net of DDA | 7,567,000 | 8,849,000 | 15,269,000 |
Corporate and other [Member] | |||
Segment Reporting Information [Line Items] | |||
Income from operations | (1,515,000) | (681,000) | (3,966,000) |
Identifiable assets net of DDA | 15,798,000 | 17,040,000 | 18,237,000 |
Commercial real estate investment | |||
Segment Reporting Information [Line Items] | |||
Identifiable assets net of DDA | 1,418,000 | 1,465,000 | 1,512,000 |
Oil and gas exploration, acquisition, production and operations [Member] | |||
Segment Reporting Information [Line Items] | |||
Revenue | 3,735,000 | 5,322,000 | 12,169,000 |
Depreciation, depletion, and amortization | 1,043,000 | 2,365,000 | 1,794,000 |
Income from operations | 40,000 | (5,159,000) | 7,097,000 |
Identifiable assets net of DDA | $ 6,139,000 | $ 7,361,000 | $ 13,722,000 |
Supplementory Income Statemen58
Supplementory Income Statement - Supplementary Income statement (Details) - USD ($) | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Income Statement Related Disclosures [Abstract] | |||
Maintenance and repairs | $ 12,000 | $ 21,000 | $ 40,000 |
Production taxes | 127,000 | 190,000 | 582,000 |
Taxes, other than payroll and income taxes | $ 8,000 | $ 35,000 | $ 48,000 |
Quarterly Data - Quarterly Data
Quarterly Data - Quarterly Data (Details) - USD ($) | 3 Months Ended | 12 Months Ended | |||||||||||||
Dec. 31, 2016 | Sep. 30, 2016 | Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2015 | Sep. 30, 2015 | Jun. 30, 2015 | Mar. 31, 2015 | Dec. 31, 2014 | Sep. 30, 2014 | Jun. 30, 2014 | Mar. 31, 2014 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Quarterly Financial Information Disclosure [Abstract] | |||||||||||||||
Total Revenues | $ 1,177,000 | $ 1,089,000 | $ 1,356,000 | $ 893,000 | $ 1,441,000 | $ 1,551,000 | $ 1,496,000 | $ 1,456,000 | $ 2,573,000 | $ 3,174,000 | $ 3,893,000 | $ 3,568,000 | $ 4,515,000 | $ 5,944,000 | $ 13,208,000 |
Expense | (2,257,000) | (1,347,000) | (1,540,000) | (1,345,000) | (7,885,000) | (2,097,000) | (2,110,000) | (1,895,000) | (2,851,000) | (2,001,000) | (2,513,000) | (2,047,000) | 6,489,000 | 13,987,000 | 9,412,000 |
Operating income (loss) | (1,080,000) | (258,000) | (184,000) | (452,000) | (6,444,000) | (546,000) | (614,000) | (439,000) | (278,000) | 1,173,000 | 1,380,000 | 1,521,000 | (1,974,000) | (8,043,000) | 3,796,000 |
Current tax (provision) benefit | 173,000 | 756,000 | (262,000) | 384,000 | 50,000 | (213,000) | (136,000) | 39,000 | (216,000) | ||||||
Deferred tax (provision) benefit | 105,000 | 155,000 | 270,000 | 152,000 | (498,000) | 329,000 | 278,000 | 233,000 | 432,000 | (107,000) | (100,000) | (290,000) | |||
Net income (loss) | $ (1,012,000) | $ (103,000) | $ 86,000 | $ (300,000) | $ (5,190,000) | $ (479,000) | $ 48,000 | $ (156,000) | $ (59,000) | $ 930,000 | $ 1,319,000 | $ 1,015,000 | $ (1,329,000) | $ (5,777,000) | $ 3,205,000 |
Earnings (loss) per share of common stock Basic and diluted | $ (0.15) | $ (0.01) | $ 0.01 | $ (0.04) | $ (0.75) | $ (0.07) | $ 0.01 | $ (0.02) | $ (0.01) | $ 0.13 | $ 0.19 | $ 0.15 | $ (0.19) | $ (0.83) | $ 0.46 |
Supplemental Reserve Informat60
Supplemental Reserve Information (Details 1) | 12 Months Ended | |||
Dec. 31, 2016bblMcf | Dec. 31, 2015bblMcf | Dec. 31, 2014bblMcf | Dec. 31, 2013bblMcf | |
Crude Oil Bbls [Member] | ||||
Quantities of Proved Reserves: | ||||
Beginning Balance | bbl | 285,540 | 404,506 | 449,880 | |
Sales of reserves in place | bbl | ||||
Acquired properties | bbl | 65,520 | 8,910 | ||
Extensions and discoveries | bbl | 17,150 | 38,800 | 10,240 | |
Revisions of previous estimates * | bbl | (4,682) | (93,559) | 24,544 | |
Production | bbl | (50,248) | (64,207) | (89,068) | |
Ending Balance | bbl | 313,280 | 285,540 | 404,506 | |
Proved Developed Reserves: | ||||
Proved Developed Reserves | bbl | 313,280 | 285,540 | 404,506 | 449,880 |
Natural Gas Mcf [Member] | ||||
Quantities of Proved Reserves: | ||||
Beginning Balance | Mcf | 4,039,740 | 6,839,491 | 6,762,330 | |
Sales of reserves in place | Mcf | (121,810) | |||
Acquired properties | Mcf | 118,030 | |||
Extensions and discoveries | Mcf | 4,670 | 107,480 | 69,870 | |
Revisions of previous estimates * | Mcf | 262,897 | (2,054,712) | 747,239 | |
Production | Mcf | (582,348) | (730,709) | (739,948) | |
Ending Balance | Mcf | 3,842,989 | 4,039,740 | 6,839,491 | |
Proved Developed Reserves: | ||||
Proved Developed Reserves | Mcf | 3,842,989 | 4,039,740 | 6,839,491 | 6,762,330 |
Supplemental Reserve Informat61
Supplemental Reserve Information (Details 2) - USD ($) | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 |
Standardized measure of discounted future net cash flows related to proved reserves: | |||
Future production revenue | $ 19,964,000 | $ 21,230,000 | $ 63,857,000 |
Future development costs | |||
Future production costs | (10,801,000) | (10,989,000) | (27,073,000) |
Future net cash flow before Federal income taxes | 9,163,000 | 10,241,000 | 36,784,000 |
Future income taxes | (2,566,000) | (2,867,000) | (10,300,000) |
Future net cash flows | 6,597,000 | 7,374,000 | 26,484,000 |
Effect of 10% annual discounting | (574,000) | (368,000) | (4,266,000) |
Standardized measure of discounted cash flows | $ 6,023,000 | $ 7,006,000 | $ 22,218,000 |
Supplemental Reserve Informat62
Supplemental Reserve Information (Details 3) - USD ($) | 12 Months Ended | ||
Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | |
Changes in the standardized measure of discounted future net cash flows: | |||
Beginning of the year | $ 7,006,000 | $ 22,218,000 | |
Sales of oil and gas, net of production costs | (1,332,000) | (1,785,000) | $ (8,041,000) |
Net changes in prices and production costs | (662,000) | (16,505,000) | (969,000) |
Extensions, discoveries, additions less related costs | 271,000 | 937,000 | 345,000 |
Development costs incurred | 267,000 | 1,474,000 | 2,490,000 |
Net changes in future development cost | (103,000) | ||
Revisions of previous quantity estimates | (756,000) | (1,965,000) | 1,474,000 |
Net change in purchase and sales of minerals in place | 884,000 | 116,000 | |
Accretion of discount | 701,000 | 2,222,000 | 2,416,000 |
Net change in income taxes | (80,000) | 1,516,000 | (22,000) |
Other | (276,000) | (1,106,000) | 351,000 |
End of the year | $ 6,023,000 | $ 7,006,000 | $ 22,218,000 |
Supplemental Reserve Informat63
Supplemental Reserve Information (Details 4) - USD ($) | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 |
Supplemental Reserve Information Details 4 | |||
Allowance for doubtful accounts | $ 15,000 | $ 15,000 | $ 15,000 |
Supplemental Reserve Informat64
Supplemental Reserve Information (Details 5) - USD ($) | Oct. 01, 2008 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2014 | Dec. 31, 2013 | Dec. 31, 2012 | Dec. 31, 2011 | Dec. 31, 2010 | Dec. 31, 2009 | Dec. 31, 2007 | Dec. 31, 2006 |
Supplemental Reserve Information Details 5 | |||||||||||
Land | $ 688,000 | $ 688,000 | |||||||||
Buildings | 1,580,000 | $ 1,580,000 | $ 1,298,000 | ||||||||
Acquisition Costs | 282,000 | ||||||||||
Investment in real estate | 2,268,000 | 2,268,000 | 2,268,000 | 2,268,000 | $ 2,268,000 | $ 2,268,000 | $ 2,268,000 | $ 2,268,000 | $ 2,196,000 | $ 1,986,000 | |
Acquistions in real estate | $ 38,000 | 34,000 | 210,000 | ||||||||
Investment in real estate | 2,268,000 | 2,268,000 | 2,268,000 | 2,268,000 | 2,268,000 | 2,268,000 | 2,268,000 | 2,268,000 | 2,230,000 | 2,196,000 | |
Accumulated depreciation | 803,000 | 756,000 | 704,000 | 652,000 | 601,000 | 501,000 | 400,000 | 300,000 | 120,000 | 49,000 | |
Depreciation Expense | $ 96,000 | 47,000 | 47,000 | 52,000 | 52,000 | 51,000 | 100,000 | 101,000 | 100,000 | 84,000 | 71,000 |
Accumulated depreciation | $ 850,000 | $ 803,000 | $ 756,000 | $ 704,000 | $ 652,000 | $ 601,000 | $ 501,000 | $ 400,000 | $ 204,000 | $ 120,000 |