Document And Entity Information
Document And Entity Information - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2017 | Mar. 10, 2018 | Jun. 30, 2017 | |
Document Information [Line Items] | |||
Entity Registrant Name | EVERFLOW EASTERN PARTNERS LP | ||
Entity Central Index Key | 868,082 | ||
Current Fiscal Year End Date | --12-31 | ||
Entity Filer Category | Smaller Reporting Company | ||
Entity Current Reporting Status | Yes | ||
Entity Voluntary Filers | No | ||
Entity Well-known Seasoned Issuer | No | ||
Entity Common Stock, Shares Outstanding (in shares) | 5,587,616 | ||
Entity Public Float | $ 0 | ||
Document Type | 10-K | ||
Document Period End Date | Dec. 31, 2017 | ||
Document Fiscal Year Focus | 2,017 | ||
Document Fiscal Period Focus | FY | ||
Amendment Flag | false |
Consolidated Balance Sheets
Consolidated Balance Sheets - USD ($) | Dec. 31, 2017 | Dec. 31, 2016 |
CURRENT ASSETS | ||
Cash and equivalents | $ 11,883,725 | $ 11,224,865 |
Investments | 13,207,778 | 10,080,608 |
Accounts receivable: | ||
Production | 1,189,524 | 1,014,946 |
Joint venture partners | 3,366 | |
Employees' notes receivable | 33,500 | 41,000 |
Other | 27,225 | 52,831 |
Total current assets | 26,341,752 | 22,417,616 |
PROPERTY AND EQUIPMENT | ||
Proved properties (successful efforts accounting method) | 179,141,990 | 181,447,571 |
Pipeline and support equipment | 682,135 | 682,135 |
Corporate and other | 2,127,423 | 2,116,482 |
Gross property and equipment | 181,951,548 | 184,246,188 |
Less accumulated depreciation, depletion, amortization and write down | 172,431,241 | 173,979,881 |
Net property and equipment | 9,520,307 | 10,266,307 |
OTHER ASSETS | ||
Employees' notes receivable | 13,242 | 46,045 |
Other | 123,048 | 176,558 |
Total other assets | 136,290 | 222,603 |
TOTAL ASSETS | 35,998,349 | 32,906,526 |
CURRENT LIABILITIES | ||
Accounts payable | 1,958,042 | 1,703,441 |
Accrued expenses | 1,624,205 | 1,137,290 |
Total current liabilities | 3,582,247 | 2,840,731 |
DEFERRED INCOME TAXES | 37,700 | 74,000 |
OPERATIONAL ADVANCES | 1,513,924 | 1,053,582 |
ASSET RETIREMENT OBLIGATIONS | 16,591,270 | 16,740,630 |
COMMITMENTS AND CONTINGENCIES | ||
LIMITED PARTNERS' EQUITY, SUBJECT TO REPURCHASE RIGHT | ||
Authorized - 8,000,000 Units Issued and outstanding - 5,587,616 Units | 14,103,844 | 12,052,848 |
GENERAL PARTNER'S EQUITY | 169,364 | 144,735 |
Total partners' equity | 14,273,208 | 12,197,583 |
TOTAL LIABILITIES AND PARTNERS' EQUITY | $ 35,998,349 | $ 32,906,526 |
Consolidated Balance Sheets (Pa
Consolidated Balance Sheets (Parentheticals) - shares | Dec. 31, 2017 | Dec. 31, 2016 |
Limited partner's equity, units authorized (in shares) | 8,000,000 | 8,000,000 |
Limited partner's equity, units issued (in shares) | 5,587,616 | 5,587,616 |
Limited partner's equity, units outstanding (in shares) | 5,587,616 | 5,587,616 |
Consolidated Statements of Oper
Consolidated Statements of Operations - USD ($) | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
REVENUES | ||
Crude oil and natural gas sales | $ 7,086,476 | $ 3,439,081 |
Well management and operating | 512,043 | 409,454 |
Other | 62,420 | 32,719 |
Total revenues | 7,660,939 | 3,881,254 |
DIRECT COST OF REVENUES | ||
Production costs | 2,160,029 | 2,133,282 |
Well management and operating | 299,581 | 239,815 |
Depreciation, depletion and amortization | 940,143 | 4,753,321 |
Accretion expense | 355,127 | 393,535 |
Write down/impairment and abandonment of crude oil and natural gas properties | 0 | 88,329 |
Total direct cost of revenues | 3,754,880 | 7,608,282 |
GENERAL AND ADMINISTRATIVE EXPENSE | 2,264,424 | 2,347,282 |
Total cost of revenues | 6,019,304 | 9,955,564 |
INCOME (LOSS) FROM OPERATIONS | 1,641,635 | (6,074,310) |
OTHER INCOME | ||
Interest and dividend income | 146,710 | 92,216 |
Gain on disposal of property and equipment | 80,368 | |
Gain on sale of other assets | 175,612 | |
Total other income | 402,690 | 92,216 |
INCOME (LOSS) BEFORE INCOME TAXES | 2,044,325 | (5,982,094) |
INCOME TAX EXPENSE (BENEFIT) | ||
Current | 5,000 | (19,581) |
Deferred | (36,300) | |
Total income tax benefit | (31,300) | (19,581) |
NET INCOME (LOSS) | 2,075,625 | (5,962,513) |
Allocation of Partnership Net Income (Loss): | ||
Limited Partners | 2,050,996 | (5,891,763) |
General Partner | 24,629 | (70,750) |
Net income (loss) | $ 2,075,625 | $ (5,962,513) |
Net income (loss) per unit (in dollars per share) | $ 0.37 | $ (1.05) |
Consolidated Statements of Part
Consolidated Statements of Partners' Equity | USD ($) |
PARTNERS' EQUITY – BEGINNING OF YEAR at Dec. 31, 2015 | $ 18,160,096 |
Net income (loss) | (5,962,513) |
PARTNERS' EQUITY – END OF YEAR at Dec. 31, 2016 | 12,197,583 |
Net income (loss) | 2,075,625 |
PARTNERS' EQUITY – END OF YEAR at Dec. 31, 2017 | $ 14,273,208 |
Consolidated Statements of Cash
Consolidated Statements of Cash Flows - USD ($) | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
CASH FLOWS FROM OPERATING ACTIVITIES | ||
Net income (loss) | $ 2,075,625 | $ (5,962,513) |
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities: | ||
Depreciation, depletion and amortization | 1,026,172 | 4,840,987 |
Accretion expense | 355,127 | 393,535 |
Write down/impairment and abandonment of crude oil and natural gas properties | 0 | 88,329 |
Gain on disposal of property and equipment | (80,368) | |
Gain on sale of other assets | (175,612) | |
Deferred income taxes | (36,300) | |
Changes in assets and liabilities: | ||
Accounts receivable | (171,212) | (441,659) |
Other current assets | 25,606 | (6,993) |
Other assets | (13,740) | (116) |
Accounts payable | 254,601 | (136,375) |
Accrued expenses | (124,549) | (41,091) |
Operational advances | 460,342 | 48,629 |
Total adjustments | 1,520,067 | 4,745,246 |
Net cash provided by (used in) operating activities | 3,595,692 | (1,217,267) |
CASH FLOWS FROM INVESTING ACTIVITIES | ||
Purchase of investments | (3,127,170) | (10,080,608) |
Payments received on notes receivables from employees | 52,203 | 37,392 |
Advances disbursed to employees | (11,900) | |
Purchase of property and equipment | (221,108) | (248,699) |
Proceeds from disposal of property and equipment | 128,281 | |
Proceeds from sale of other assets | 242,862 | |
Net cash used in investing activities | (2,936,832) | (10,291,915) |
NET CHANGE IN CASH AND EQUIVALENTS | 658,860 | (11,509,182) |
CASH AND EQUIVALENTS AT BEGINNING OF YEAR | 11,224,865 | 22,734,047 |
CASH AND EQUIVALENTS AT END OF YEAR | 11,883,725 | 11,224,865 |
Supplemental disclosures of cash flow information: | ||
Income taxes | $ 5,499 | $ 390 |
Note 1 - Organization and Summa
Note 1 - Organization and Summary of Significant Accounting Policies | 12 Months Ended |
Dec. 31, 2017 | |
Notes to Financial Statements | |
Organization, Consolidation and Presentation of Financial Statements Disclosure and Significant Accounting Policies [Text Block] | Note 1. Organization and Summary of Significant Accounting Policies A. Organization and Principles of Consolidation – Everflow Eastern Partners, L.P. ("Everflow") is a Delaware limited partnership which was organized in September 1990 Everflow Management Limited, LLC ("EML"), an Ohio limited liability company, is the general partner of Everflow and, as such, is authorized to perform all acts necessary or desirable to carry out the purposes and conduct of the business of Everflow. The members of EML are Everflow Management Corporation ("EMC"); two one one one September 1990 EML holds no nor no The consolidated financial statements include the accounts of Everflow, its wholly-owned subsidiaries, including EEI, and interests with joint venture partners (collectively, the "Company"), which are accounted for under the proportional consolidation method. All significant accounts and transactions between the consolidated entities have been eliminated. B . Use of Estimates – The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America ("generally accepted accounting principles" or "GAAP") 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. Significant estimates impacting the Company's financial statements include revenue and expense accruals and oil and gas reserve quantities. In the oil and gas industry, and especially as related to the Company's natural gas sales, the processing of actual transactions generally occurs 60 90 C . Fair Value of Financial Instruments – The fair values of cash and equivalents, accounts and notes receivable, accounts payable and other short-term obligations approximate their carrying values because of the short maturity of these financial instruments. The carrying values of the Company's long-term obligations approximate their fair value because they are considered to be at current market rates. In accordance with generally accepted accounting principles, rates available to the Company at the balance sheet dates are used to estimate the fair value of existing obligations. D . Cash and Equivalents – The Company considers all highly liquid debt instruments purchased with an original maturity of three may may, $1,513,924 $1,053,582 December 31, 2017 2016, 5 E . Investments – The Company’s investments are classified as available-for-sale securities and consist of shares held in a mutual fund that invests primarily in investment grade, U.S. dollar denominated short-term fixed and floating rate debt securities. The mutual fund seeks current income while seeking to maintain a low volatility of principal. The Financial Accounting Standards Board established a framework for measuring fair value and expands disclosures about fair value measurements by establishing a fair value hierarchy that prioritizes the inputs and defines valuation techniques used to measure fair value. The hierarchy gives highest priority to Level I inputs and lowest priority to Level III inputs. The three Level I – Quoted prices are available in active markets for identical financial instruments as of the reporting date. Level II – Pricing inputs are other than quoted prices in active markets, which are either directly or indirectly observable as of the reporting date, and fair value is determined through the use of models or other valuation methodologies. Level III – Pricing inputs are unobservable for the financial instrument and include situations where there is little, if any, market activity for the financial instrument. The inputs into the determination of fair value require significant management judgment or estimation. The Company ’s investments are carried at fair market value based on quoted prices available in active markets and are therefore classified as Level 1. F . Property and Equipment – The Company uses the successful efforts method of accounting for oil and gas exploration and production activities. Under successful efforts, costs to acquire mineral interests in oil and gas properties, to drill and equip development wells and related asset retirement costs are capitalized. Costs of development wells (on properties the Company has no not not no Capitalized costs of proved properties, after considering estimated dismantlement and abandonment costs and estimated salvage values, are amortized by the unit-of-production method based upon estimated proved developed reserves. Depletion, depreciation and amortization on proved properties amounted to $889,794 $4,709,814 2017 2016, On sale or retirement of a unit of a proved property (which generally constitutes the amortization base), the cost and related accumulated depreciation, depletion, amortization and write down are eliminated from the property accounts, and the resultant gain or loss is recognized. Generally accepted accounting principles require that long-lived assets (including oil and gas properties) and certain identifiable intangibles be reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not The Company, at least annually, reviews its proved crude oil and natural gas properties (on a field by field basis) for impairment by comparing the carrying value of its properties to the properties' undiscounted estimated future net cash flows. Estimates of future crude oil and natural gas prices, operating costs, and production are utilized in determining undiscounted future net cash flows. The estimated future production of oil and gas reserves is based upon the Company's independent reserve engineer's estimate of proved reserves which includes assumptions regarding field decline rates and future prices and costs. For properties where the carrying value exceeds undiscounted future net cash flows, the Company recognizes as impairment the difference between the carrying value and fair market value of the properties. The Company determines fair market value, using the income approach, as the properties’ discounted estimated future net cash flows. The key assumptions above are not not 2017. $88,329 2016 Additions to proved properties include changes to accrued expenses related to the drilling of oil and gas properties (see Note 2 1.G Pipeline and support equipment and other corporate property and equipment are recorded at cost and depreciated principally on the straight-line method over their estimated useful lives (pipeline and support equipment - 10 15 3 7 $1,536,288 39 40 $50,349 $43,507 December 31, 2017 2016, $86,029 $87,666 December 31, 2017 2016, Maintenance and repairs of property and equipment are expensed as incurred. Major renewals and improvements are capitalized, and the assets replaced are retired. G . Asset Retirement Obligations – Generally accepted accounting principles require the fair value of a liability for an asset retirement obligation to be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. For the Company, these obligations include dismantlement, plugging and abandonment of crude oil and natural gas wells and associated pipelines and equipment. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. The liability is accreted to its then present value each period, and the capitalized cost is depleted over the estimated useful life of the related asset. The estimated liability is based on historical experience in dismantling, plugging and abandoning wells, estimated remaining lives of those wells based on reserves estimates, estimates of the external cost to dismantle, plug and abandon the wells in the future and federal and state regulatory requirements. The liability is discounted using an assumed credit-adjusted risk-free interest rate. Revisions to the liability will likely occur due to: changes in estimates of dismantlement, plugging and abandonment costs, changes in estimated remaining lives of the wells, changes in federal or state regulations regarding plugging and abandonment requirements, and other factors. The Company has no tling asset retirement obligations. The Company has determined that there are no The schedule below is a reconciliation of the Company's liability for the years ended December 31: 2017 2016 Beginning of period $ 17,124,630 $ 16,736,560 Liabilities incurred 877 1,144 Liabilities settled (114,364 ) (6,609 ) Accretion expense 355,127 393,535 End of period $ 17,366,270 $ 17,124,630 The current portion of asset retirement obligations of $775,000 $384,000 December 31, 2017 2016, H . Revenue Recognition – The Company recognizes crude oil and natural gas revenues when production is sold to a purchaser at a fixed or determinable price, when delivery has occurred, title and risk of loss have transferred to the purchaser, and collectability of the revenue is reasonably assured. The Company utilizes the sales method to account for gas production volume imbalances. Under this method, revenue is recognized only when gas is produced and sold on the Company's behalf. The Company had no December 31, 2017 2016. The Company participates (and may no 5 Accounts payable to joint venture partners consist principally of deposits received from joint venture partners for drilling and development costs (see Note 2 I. Income Taxes – Everflow is not not EEI accounts for income taxes under generally accepted accounting principles, which require income taxes be provided for all items (as they relate to EEI) in the consolidated statements of operations regardless of the period when such items are reported for income tax purposes. Therefore, deferred tax assets and liabilities are recognized for temporary differences between the financial reporting basis and tax basis of certain EEI assets and liabilities. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which the temporary differences are expected to be recovered or settled. The impact on deferred taxes of changes in tax rates and laws, if any, is reflected in the financial statements in the period of enactment. Items giving rise to deferred taxes consist of temporary differences arising from differences in financial reporting and tax reporting methods for EEI's proved properties and percentage depletion credits. The Company believes that it has appropriate support for any tax positions taken and, as such, does not J . Allocation of Income and Per Unit Data – Under the terms of the limited partnership agreement, initially 99% 1% may 3 Earnings per limited partner Unit have been computed based on the weighted average number of Units outstanding during each year presented. Average outstanding Units for earnings per Unit calculation s amount to 5,587,616 2017 2016, K . New Accounting Standards – In May 2014, No. 2014 09, 606 2014 09” 2014 09 2014 09 2014 09, 2015 14, December 31, 2017 ( 606 January 1, 2018 not The Company has reviewed all other recently issued accounting standards in order to determine their effects, if any, on the consolidated financial statements. Based on that review, the Company believes that none L. Reclassifications – Certain prior period amounts have been reclassified to conform with the current period’s presentation. |
Note 2 - Current Liabilities
Note 2 - Current Liabilities | 12 Months Ended |
Dec. 31, 2017 | |
Notes to Financial Statements | |
Accounts Payable and Accrued Liabilities Disclosure [Text Block] | N ote 2. Current Liabilities The Company's accounts payable and accrued expenses consist of the following at December 31: 2017 2016 Accounts Payable: Production and related other $ 1,615,606 $ 1,364,131 Other 295,507 292,076 Joint venture partner deposits 46,929 47,234 Total accounts payable $ 1,958,042 $ 1,703,441 Accrued Expenses: Current portion of asset retirement obligations $ 775,000 $ 384,000 Payroll and retirement plan contributions 664,384 641,326 Drilling 106,100 - Other 45,600 79,500 Federal, state and local taxes 33,121 32,464 Total accrued expenses $ 1,624,205 $ 1,137,290 |
Note 3 - Partners' Equity
Note 3 - Partners' Equity | 12 Months Ended |
Dec. 31, 2017 | |
Notes to Financial Statements | |
Partners' Capital Notes Disclosure [Text Block] | N ote 3 . Partners' Equity Units represent limited partnership interests in Everflow. The Units are transferable subject only to the approval of any transfer by EML and to the laws governing the transfer of securities. The Units are not may The partnership agreement provides that Everflow will repurchase for cash up to 10% May 1 June 30 December 31 66% 10% 2018 December 31, 2017 $0.11 The Company has an Option Repurchase Plan (the " Option Plan") which permits the grant of options to repurchase certain Units to select officers and employees (the "Option Plan Participants"). The purpose of the Option Plan is to assist the Company in attracting and retaining officers and other key employees and to enable those individuals to acquire or increase their ownership interest in the Company in order to encourage them to promote the growth and profitability of the Company. The Option Plan is designed to align directly the financial interests of the Option Plan Participants with the financial interests of the Unitholders. The Company did not 2017 2016. The Company did not offer to repurchase any Units pursuant to the Repurchase Right during 2017 2016 December 31, 2015 Per Unit Calculated Units Price for Less Outstanding Repurchase Interim Net Units Units Following Right Distributions Price Paid Repurchased Issued Units Activity $ 4.935 $ 0.375 $ 4.56 26,774 13,387 5,587,616 All Units repurchased pursuant to the Repurchase Right in 2015 no December 31, 2017 2016 |
Note 4 - Retirement Plan
Note 4 - Retirement Plan | 12 Months Ended |
Dec. 31, 2017 | |
Notes to Financial Statements | |
Pension and Other Postretirement Benefits Disclosure [Text Block] | Note 4 . Retirement Plan The Company has a defined contribution plan pursuant to Section 401 $194,400 $168,700 December 31, 2017 2016, |
Note 5 - Related Party Transact
Note 5 - Related Party Transactions | 12 Months Ended |
Dec. 31, 2017 | |
Notes to Financial Statements | |
Related Party Transactions Disclosure [Text Block] | Note 5 . Related Party Transactions The Company's Officers, Directors, affiliates and certain employees have frequently participated, and will likely continue to participate in the future, as working interest owners in wells in which the Company has an interest. Frequently, the Company has loaned the funds necessary for certain employees to participate in the drilling and development of such wells. Initial terms of the unsecured loans call for repayment of all principal and accrued interest at the end of four not four Employees remain obligated for the entire loan amount regardless of a dry-hole event or otherwise insufficient production. The loans carry no no 4.50% December 31, 2017. In accordance with the Sarbanes-Oxley Act of 2002, not 2002. December 31, 2017 2016, three two December 2011 December 2017. two December 31, 2017. $46,742 87,045 December 31, 2017 2016, The Company collects and holds operational advances from employees, including officers and directors, who own working interests in wells of which the Company operates (see Note 1 December 31, 2017 2016 $180,300 $40,300, |
Note 6 - Business Segments, Ris
Note 6 - Business Segments, Risks and Major Customers | 12 Months Ended |
Dec. 31, 2017 | |
Notes to Financial Statements | |
Segment Reporting Disclosure [Text Block] | N ote 6 . Business Segments, Risks and Major Customers The Company operates exclusively in Ohio and Pennsylvania of the United States in the acquisition, exploration, development and production of oil and gas. The Company operates in an environment with many financial risks, including, but not to sell oil and gas at prices which will provide attractive rates of return, the volatility and seasonality of oil and gas production and prices, and the highly competitive and, at times, seasonal nature of the industry and worldwide economic conditions. The Company's ability to expand its reserve base and diversify its operations is also dependent upon the Company's ability to obtain the necessary capital through operating cash flow, borrowings or equity offerings. Various federal, state and governmental agencies are considering, and some have adopted, laws and regulations regarding environmental protection which could adversely affect the proposed business activities of the Company. The Company cannot predict what effect, if any, current and future regulations may Management of the Company continually evaluates whether the Company can develop oil and gas properties at historical levels given current industry and market conditions. If the Company is unable to do so, it could be determined that it is in the best interests of the Company and its Unitholders to reorganize, liquidate or sell the Company. However, management cannot predict whether any sale transaction will be a viable alternative for the Company in the immediate future. Natural g as sales accounted for 73% 61% 2017 2016, 83% 76% 2017 2016, two December 31, 2017 2016. Natural Gas Purchaser 2017 2016 Dominion Field Services, Inc. ("Dominion") 44 % 25 % Interstate Gas Supply, Inc. ("IGS") 12 13 56 % 38 % As of December 31, 2017, 500 160 76% 63% 2017 2016, Substantially all of the Company ’s crude oil production from operated wells is purchased by Ergon Oil Purchasing, Inc. (“Ergon Oil”). The Company 's production accounts receivable result from sales of natural gas and crude oil. A significant portion of the Company's production accounts receivable is due from the Company's major customers. The Company does not not not December 31, 2017 2016. 2018. not third may The Company has multiple contracts with Dominion and I GS (collectively, the “Gas Purchasers”) which obligate the Gas Purchasers to purchase, and the Company to sell and deliver, certain quantities of natural gas production from the Company’s oil and gas properties throughout the contract periods. The Company may 90,000 January 2018 March 2018 $3.35 |
Note 7 - Commitments and Contin
Note 7 - Commitments and Contingencies | 12 Months Ended |
Dec. 31, 2017 | |
Notes to Financial Statements | |
Commitments and Contingencies Disclosure [Text Block] | Note 7 . Commitments and Contingencies The Company has natural gas delivery commitments to the Gas Purchasers (see Note 6 may may The Company is party to various legal proceedings and claims in the ordinary course of its business. The Company believes certain of these matters will be covered by insurance and that the outcome of other matters will not |
Note 8 - Supplemental Informati
Note 8 - Supplemental Information Relating to Oil and Gas Producing Activities (Unaudited) | 12 Months Ended |
Dec. 31, 2017 | |
Notes to Financial Statements | |
Oil and Gas Exploration and Production Industries Disclosures [Text Block] | Note 8 . Supplemental Information Relating to Oil and Gas Producing Activities (Unaudited) The following supplemental unaudited oil and gas information is required by generally accepted accounting principles. The tables on the following pages set forth pertinent data with respect to the Company's oil and gas properties, all of which are located within the continental United States. CAPITALIZED COSTS RELATING TO OIL AND GAS PRODUCING ACTIVITIES Years ended December 31, 2017 2016 Proved oil and gas properties $ 179,141,990 $ 181,447,571 Pipeline and support equipment 682,135 682,135 Gross capitalized costs 179,824,125 182,129,706 Accumulated depreciation, depletion, amortization and write down 171,337,190 172,885,338 Net capitalized costs $ 8,486,935 $ 9,244,368 COSTS INCURRED IN OIL AND GAS PRODUCING ACTIVITIES Years ended December 31, 2017 2016 Property acquisition costs $ 11,045 $ 20,363 Development costs 192,284 136,274 The Company had no 2017 2016. RESULTS OF OPERATIONS FOR OIL AND GAS PRODUCING ACTIVITIES Years ended December 31, 2017 2016 Crude oil and natural gas sales $ 7,086,476 $ 3,439,081 Production costs (2,160,029 ) (2,133,282 ) Depreciation, depletion and amortization (940,143 ) (4,753,321 ) Accretion expense (355,127 ) (393,535 ) Write down/impairment and abandonment of crude oil and - (88,329 ) Results of operations before income tax benefit 3,631,177 (3,929,386 ) Income tax benefit (30,000 ) (20,000 ) Results of operations for oil and gas producing activities (excluding corporate overhead and financing costs) $ 3,661,177 $ (3,909,386 ) Income tax expense was computed using statutory tax rates and reflects permanent differences that are reflected in the Company's consolidated income tax expense for the year. ESTIMATED QUANTITIES OF PROVED OIL AND GAS RESERVES Oil Gas (BBLS) (MCF) Balance, January 1, 2016 277,000 7,991,000 Extensions, discoveries and other additions 5,000 13,000 Production (34,000 ) (1,157,000 ) Revision of previous estimates (4,000 ) (1,567,000 ) Balance, December 31, 2016 244,000 5,280,000 Extensions, discoveries and other additions 8,000 17,000 Production (40,000 ) (1,904,000 ) Revision of previous estimates 78,000 7,851,000 Balance, December 31, 2017 290,000 11,244,000 PROVED DEVELOPED RESERVES: December 31, 2015 277,000 7,991,000 December 31, 2016 244,000 5,280,000 December 31, 2017 290,000 11,244,000 The Company has not and other undeveloped properties, including its deep property interests. At December 31, 2017 2016, 14 46 $35,700 $36,200 December 31, 2017 2016, STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS December 31, 2017 2016 (Thousands of Dollars) Future cash inflows from sales of oil and gas $ 37,232 $ 17,014 Future production and development costs (22,716 ) (10,853 ) Future asset retirement obligations, net of salvage (16,360 ) (16,451 ) Future income tax expense (132 ) (95 ) Future net cash flows (1,976 ) (10,385 ) Effect of discounting future net cash flows at 10% per annum (3,078 ) 461 Standardized measure of discounted future net cash flows $ (5,054 ) $ (9,924 ) CHANGES IN THE STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS Years Ended December 31, 2017 2016 (Thousands of Dollars) Balance, beginning of year $ (9,924 ) $ (8,211 ) Extensions, discoveries and other additions 197 85 Revision of quantity estimates 4,031 (184 ) Sales of crude oil and natural gas, net of production costs (4,926 ) (1,306 ) Net change in income taxes (20 ) 32 Net changes in prices and production costs 2,478 (1,080 ) Accretion of discount (992 ) (821 ) Other 4,102 1,561 Balance, end of year $ (5,054 ) $ (9,924 ) There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of development expenditures , including many factors beyond the control of the Company. The estimated future cash flows are determined based on crude oil and natural gas pricing parameters established by generally accepted accounting principles, adjusted for contract terms within contract periods, estimated production of proved crude oil and natural gas reserves, estimated future production and development costs of reserves and future retirement obligations (net of salvage), based on current economic conditions, and the estimated future income tax expense, based on year-end statutory tax rates (with consideration of future tax rates already legislated) to be incurred on pretax net cash flows less the tax basis of the properties involved. Such cash flows are then discounted using a 10% The methodology and assumptions used in calculating the standardized measure are those required by generally accepted accounting principles and United States Securities and Exchange Commission reporting requirements. It is not not Average adjusted natural gas prices used in the estimation of proved reserves were $2.09 $1.41 December 31, 2017 2016, $47.48 $39.33 December 31, 2017 2016, |
Significant Accounting Policies
Significant Accounting Policies (Policies) | 12 Months Ended |
Dec. 31, 2017 | |
Accounting Policies [Abstract] | |
Organization Principles of Consolidation [Policy Text Block] | A. Organization and Principles of Consolidation – Everflow Eastern Partners, L.P. ("Everflow") is a Delaware limited partnership which was organized in September 1990 Everflow Management Limited, LLC ("EML"), an Ohio limited liability company, is the general partner of Everflow and, as such, is authorized to perform all acts necessary or desirable to carry out the purposes and conduct of the business of Everflow. The members of EML are Everflow Management Corporation ("EMC"); two one one one September 1990 EML holds no no The consolidated financial statements include the accounts of Everflow, its wholly-owned subsidiaries, including EEI, and interests with joint venture partners (collectively, the "Company"), which are accounted for under the proportional consolidation method. All significant accounts and transactions between the consolidated entities have been eliminated. |
Use of Estimates, Policy [Policy Text Block] | B . Use of Estimates – The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America ("generally accepted accounting principles" or "GAAP") 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. Significant estimates impacting the Company's financial statements include revenue and expense accruals and oil and gas reserve quantities. In the oil and gas industry, and especially as related to the Company's natural gas sales, the processing of actual transactions generally occurs 60 90 |
Fair Value of Financial Instruments, Policy [Policy Text Block] | C . Fair Value of Financial Instruments – The fair values of cash and equivalents, accounts and notes receivable, accounts payable and other short-term obligations approximate their carrying values because of the short maturity of these financial instruments. The carrying values of the Company's long-term obligations approximate their fair value because they are considered to be at current market rates. In accordance with generally accepted accounting principles, rates available to the Company at the balance sheet dates are used to estimate the fair value of existing obligations. |
Cash and Cash Equivalents, Policy [Policy Text Block] | D . Cash and Equivalents – The Company considers all highly liquid debt instruments purchased with an original maturity of three may may, $1,513,924 $1,053,582 December 31, 2017 2016, 5 |
Investment, Policy [Policy Text Block] | E . Investments – The Company’s investments are classified as available-for-sale securities and consist of shares held in a mutual fund that invests primarily in investment grade, U.S. dollar denominated short-term fixed and floating rate debt securities. The mutual fund seeks current income while seeking to maintain a low volatility of principal. The Financial Accounting Standards Board established a framework for measuring fair value and expands disclosures about fair value measurements by establishing a fair value hierarchy that prioritizes the inputs and defines valuation techniques used to measure fair value. The hierarchy gives highest priority to Level I inputs and lowest priority to Level III inputs. The three Level I – Quoted prices are available in active markets for identical financial instruments as of the reporting date. Level II – Pricing inputs are other than quoted prices in active markets, which are either directly or indirectly observable as of the reporting date, and fair value is determined through the use of models or other valuation methodologies. Level III – Pricing inputs are unobservable for the financial instrument and include situations where there is little, if any, market activity for the financial instrument. The inputs into the determination of fair value require significant management judgment or estimation. The Company ’s investments are carried at fair market value based on quoted prices available in active markets and are therefore classified as Level 1. |
Property, Plant and Equipment, Policy [Policy Text Block] | F . Property and Equipment – The Company uses the successful efforts method of accounting for oil and gas exploration and production activities. Under successful efforts, costs to acquire mineral interests in oil and gas properties, to drill and equip development wells and related asset retirement costs are capitalized. Costs of development wells (on properties the Company has no not not no Capitalized costs of proved properties, after considering estimated dismantlement and abandonment costs and estimated salvage values, are amortized by the unit-of-production method based upon estimated proved developed reserves. Depletion, depreciation and amortization on proved properties amounted to $889,794 $4,709,814 2017 2016, On sale or retirement of a unit of a proved property (which generally constitutes the amortization base), the cost and related accumulated depreciation, depletion, amortization and write down are eliminated from the property accounts, and the resultant gain or loss is recognized. Generally accepted accounting principles require that long-lived assets (including oil and gas properties) and certain identifiable intangibles be reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not The Company, at least annually, reviews its proved crude oil and natural gas properties (on a field by field basis) for impairment by comparing the carrying value of its properties to the properties' undiscounted estimated future net cash flows. Estimates of future crude oil and natural gas prices, operating costs, and production are utilized in determining undiscounted future net cash flows. The estimated future production of oil and gas reserves is based upon the Company's independent reserve engineer's estimate of proved reserves which includes assumptions regarding field decline rates and future prices and costs. For properties where the carrying value exceeds undiscounted future net cash flows, the Company recognizes as impairment the difference between the carrying value and fair market value of the properties. The Company determines fair market value, using the income approach, as the properties’ discounted estimated future net cash flows. The key assumptions above are not not 2017. $88,329 2016 Additions to proved properties include changes to accrued expenses related to the drilling of oil and gas properties (see Note 2 1.G Pipeline and support equipment and other corporate property and equipment are recorded at cost and depreciated principally on the straight-line method over their estimated useful lives (pipeline and support equipment - 10 15 3 7 $1,536,288 39 40 $50,349 $43,507 December 31, 2017 2016, $86,029 $87,666 December 31, 2017 2016, Maintenance and repairs of property and equipment are expensed as incurred. Major renewals and improvements are capitalized, and the assets replaced are retired. |
Asset Retirement Obligation [Policy Text Block] | G . Asset Retirement Obligations – Generally accepted accounting principles require the fair value of a liability for an asset retirement obligation to be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. For the Company, these obligations include dismantlement, plugging and abandonment of crude oil and natural gas wells and associated pipelines and equipment. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. The liability is accreted to its then present value each period, and the capitalized cost is depleted over the estimated useful life of the related asset. The estimated liability is based on historical experience in dismantling, plugging and abandoning wells, estimated remaining lives of those wells based on reserves estimates, estimates of the external cost to dismantle, plug and abandon the wells in the future and federal and state regulatory requirements. The liability is discounted using an assumed credit-adjusted risk-free interest rate. Revisions to the liability will likely occur due to: changes in estimates of dismantlement, plugging and abandonment costs, changes in estimated remaining lives of the wells, changes in federal or state regulations regarding plugging and abandonment requirements, and other factors. The Company has no tling asset retirement obligations. The Company has determined that there are no The schedule below is a reconciliation of the Company's liability for the years ended December 31: 2017 2016 Beginning of period $ 17,124,630 $ 16,736,560 Liabilities incurred 877 1,144 Liabilities settled (114,364 ) (6,609 ) Accretion expense 355,127 393,535 End of period $ 17,366,270 $ 17,124,630 The current portion of asset retirement obligations of $775,000 $384,000 December 31, 2017 2016, |
Revenue Recognition, Policy [Policy Text Block] | H . Revenue Recognition – The Company recognizes crude oil and natural gas revenues when production is sold to a purchaser at a fixed or determinable price, when delivery has occurred, title and risk of loss have transferred to the purchaser, and collectability of the revenue is reasonably assured. The Company utilizes the sales method to account for gas production volume imbalances. Under this method, revenue is recognized only when gas is produced and sold on the Company's behalf. The Company had no December 31, 2017 2016. The Company participates (and may no 5 Accounts payable to joint venture partners consist principally of deposits received from joint venture partners for drilling and development costs (see Note 2 |
Income Tax, Policy [Policy Text Block] | I. Income Taxes – Everflow is not not EEI accounts for income taxes under generally accepted accounting principles, which require income taxes be provided for all items (as they relate to EEI) in the consolidated statements of operations regardless of the period when such items are reported for income tax purposes. Therefore, deferred tax assets and liabilities are recognized for temporary differences between the financial reporting basis and tax basis of certain EEI assets and liabilities. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which the temporary differences are expected to be recovered or settled. The impact on deferred taxes of changes in tax rates and laws, if any, is reflected in the financial statements in the period of enactment. Items giving rise to deferred taxes consist of temporary differences arising from differences in financial reporting and tax reporting methods for EEI's proved properties and percentage depletion credits. The Company believes that it has appropriate support for any tax positions taken and, as such, does not |
Earnings Per Share, Policy [Policy Text Block] | J . Allocation of Income and Per Unit Data – Under the terms of the limited partnership agreement, initially 99% 1% may 3 Earnings per limited partner Unit have been computed based on the weighted average number of Units outstanding during each year presented. Average outstanding Units for earnings per Unit calculation s amount to 5,587,616 2017 2016, |
New Accounting Pronouncements, Policy [Policy Text Block] | K . New Accounting Standards – In May 2014, No. 2014 09, 606 2014 09” 2014 09 2014 09 2014 09, 2015 14, December 31, 2017 ( 606 January 1, 2018 not The Company has reviewed all other recently issued accounting standards in order to determine their effects, if any, on the consolidated financial statements. Based on that review, the Company believes that none |
Reclassification, Policy [Policy Text Block] | L. Reclassifications – Certain prior period amounts have been reclassified to conform with the current period’s presentation. |
Note 1 - Organization and Sum16
Note 1 - Organization and Summary of Significant Accounting Policies (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Notes Tables | |
Schedule of Asset Retirement Obligations [Table Text Block] | 2017 2016 Beginning of period $ 17,124,630 $ 16,736,560 Liabilities incurred 877 1,144 Liabilities settled (114,364 ) (6,609 ) Accretion expense 355,127 393,535 End of period $ 17,366,270 $ 17,124,630 |
Note 2 - Current Liabilities (T
Note 2 - Current Liabilities (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Notes Tables | |
Schedule of Accounts Payable and Accrued Liabilities [Table Text Block] | 2017 2016 Accounts Payable: Production and related other $ 1,615,606 $ 1,364,131 Other 295,507 292,076 Joint venture partner deposits 46,929 47,234 Total accounts payable $ 1,958,042 $ 1,703,441 Accrued Expenses: Current portion of asset retirement obligations $ 775,000 $ 384,000 Payroll and retirement plan contributions 664,384 641,326 Drilling 106,100 - Other 45,600 79,500 Federal, state and local taxes 33,121 32,464 Total accrued expenses $ 1,624,205 $ 1,137,290 |
Note 3 - Partners' Equity (Tabl
Note 3 - Partners' Equity (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Notes Tables | |
Units Repurchased and Issued [Table Text Block] | Per Unit Calculated Units Price for Less Outstanding Repurchase Interim Net Units Units Following Right Distributions Price Paid Repurchased Issued Units Activity $ 4.935 $ 0.375 $ 4.56 26,774 13,387 5,587,616 |
Note 6 - Business Segments, R19
Note 6 - Business Segments, Risks and Major Customers (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Notes Tables | |
Schedule of Revenue by Major Customers by Reporting Segments [Table Text Block] | Natural Gas Purchaser 2017 2016 Dominion Field Services, Inc. ("Dominion") 44 % 25 % Interstate Gas Supply, Inc. ("IGS") 12 13 56 % 38 % |
Note 8 - Supplemental Informa20
Note 8 - Supplemental Information Relating to Oil and Gas Producing Activities (Unaudited) (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Notes Tables | |
Capitalized Costs Relating to Oil and Gas Producing Activities Disclosure [Table Text Block] | Years ended December 31, 2017 2016 Proved oil and gas properties $ 179,141,990 $ 181,447,571 Pipeline and support equipment 682,135 682,135 Gross capitalized costs 179,824,125 182,129,706 Accumulated depreciation, depletion, amortization and write down 171,337,190 172,885,338 Net capitalized costs $ 8,486,935 $ 9,244,368 |
Cost Incurred in Oil and Gas Property Acquisition, Exploration, and Development Activities Disclosure [Table Text Block] | Years ended December 31, 2017 2016 Property acquisition costs $ 11,045 $ 20,363 Development costs 192,284 136,274 |
Results of Operations for Oil and Gas Producing Activities Disclosure [Table Text Block] | Years ended December 31, 2017 2016 Crude oil and natural gas sales $ 7,086,476 $ 3,439,081 Production costs (2,160,029 ) (2,133,282 ) Depreciation, depletion and amortization (940,143 ) (4,753,321 ) Accretion expense (355,127 ) (393,535 ) Write down/impairment and abandonment of crude oil and - (88,329 ) Results of operations before income tax benefit 3,631,177 (3,929,386 ) Income tax benefit (30,000 ) (20,000 ) Results of operations for oil and gas producing activities (excluding corporate overhead and financing costs) $ 3,661,177 $ (3,909,386 ) |
Schedule of Proved Developed and Undeveloped Oil and Gas Reserve Quantities [Table Text Block] | Oil Gas (BBLS) (MCF) Balance, January 1, 2016 277,000 7,991,000 Extensions, discoveries and other additions 5,000 13,000 Production (34,000 ) (1,157,000 ) Revision of previous estimates (4,000 ) (1,567,000 ) Balance, December 31, 2016 244,000 5,280,000 Extensions, discoveries and other additions 8,000 17,000 Production (40,000 ) (1,904,000 ) Revision of previous estimates 78,000 7,851,000 Balance, December 31, 2017 290,000 11,244,000 PROVED DEVELOPED RESERVES: December 31, 2015 277,000 7,991,000 December 31, 2016 244,000 5,280,000 December 31, 2017 290,000 11,244,000 |
Standardized Measure of Discounted Future Cash Flows Relating to Proved Reserves Disclosure [Table Text Block] | December 31, 2017 2016 (Thousands of Dollars) Future cash inflows from sales of oil and gas $ 37,232 $ 17,014 Future production and development costs (22,716 ) (10,853 ) Future asset retirement obligations, net of salvage (16,360 ) (16,451 ) Future income tax expense (132 ) (95 ) Future net cash flows (1,976 ) (10,385 ) Effect of discounting future net cash flows at 10% per annum (3,078 ) 461 Standardized measure of discounted future net cash flows $ (5,054 ) $ (9,924 ) |
Schedule of Changes in Standardized Measure of Discounted Future Net Cash Flows [Table Text Block] | Years Ended December 31, 2017 2016 (Thousands of Dollars) Balance, beginning of year $ (9,924 ) $ (8,211 ) Extensions, discoveries and other additions 197 85 Revision of quantity estimates 4,031 (184 ) Sales of crude oil and natural gas, net of production costs (4,926 ) (1,306 ) Net change in income taxes (20 ) 32 Net changes in prices and production costs 2,478 (1,080 ) Accretion of discount (992 ) (821 ) Other 4,102 1,561 Balance, end of year $ (5,054 ) $ (9,924 ) |
Note 1 - Organization and Sum21
Note 1 - Organization and Summary of Significant Accounting Policies (Details Textual) | 12 Months Ended | |
Dec. 31, 2017USD ($)shares | Dec. 31, 2016USD ($)shares | |
General Partner, Assets | $ 0 | |
General Partner, Liabilities | $ 0 | |
General Partner, Operations | 0 | |
Cash and Equivalents Maturity Period | 90 days | |
Customer Advances, Noncurrent | $ 1,513,924 | $ 1,053,582 |
Depletion, Depreciation and Amortization on Proved Properties | 889,794 | 4,709,814 |
Impairment of Oil and Gas Properties | 0 | 88,329 |
Buildings and Improvements, Gross | 1,536,288 | |
Asset Retirement Obligation, Legally Restricted Assets, Fair Value | 0 | 0 |
Other Material Retirement Obligations Associated with Tangible Long-lived Assets | 0 | |
Asset Retirement Obligation, Current | 775,000 | 384,000 |
Gas Balancing Payable | $ 0 | $ 0 |
Number of Uncertain Tax Positions | 0 | |
Limited Partner [Member] | ||
Initial Percentage of Revenue and Cost Allocation | 99.00% | |
Weighted Average Limited Partnership Units Outstanding, Basic | shares | 5,587,616 | 5,587,616 |
General Partner [Member] | ||
Initial Percentage of Revenue and Cost Allocation | 1.00% | |
Pipeline and Support Equipment [Member] | ||
Depreciation | $ 50,349 | $ 43,507 |
Other Corporate Property [Member] | ||
Depreciation | $ 86,029 | $ 87,666 |
Minimum [Member] | ||
Actual Processing Time for Sales Transaction | 60 days | |
Minimum [Member] | Pipeline and Support Equipment [Member] | ||
Property, Plant and Equipment, Useful Life | 10 years | |
Minimum [Member] | Other Corporate Equipment [Member] | ||
Property, Plant and Equipment, Useful Life | 3 years | |
Minimum [Member] | Building and Building Improvements [Member] | ||
Property, Plant and Equipment, Useful Life | 39 years | |
Maximum [Member] | ||
Actual Processing Time for Sales Transaction | 90 days | |
Maximum [Member] | Pipeline and Support Equipment [Member] | ||
Property, Plant and Equipment, Useful Life | 15 years | |
Maximum [Member] | Other Corporate Equipment [Member] | ||
Property, Plant and Equipment, Useful Life | 7 years | |
Maximum [Member] | Building and Building Improvements [Member] | ||
Property, Plant and Equipment, Useful Life | 40 years |
Note 1 - Organization and Sum22
Note 1 - Organization and Summary of Significant Accounting Policies - Reconciliation of Company's Asset Retirement Obligations (Details) - USD ($) | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Beginning of period | $ 17,124,630 | $ 16,736,560 |
Liabilities incurred | 877 | 1,144 |
Liabilities settled | (114,364) | (6,609) |
Accretion expense | 355,127 | 393,535 |
End of period | $ 17,366,270 | $ 17,124,630 |
Note 2 - Current Liabilities -
Note 2 - Current Liabilities - Components of Accounts Payable and Accrued (Details) - USD ($) | Dec. 31, 2017 | Dec. 31, 2016 |
Accounts Payable: | ||
Production and related other | $ 1,615,606 | $ 1,364,131 |
Other | 295,507 | 292,076 |
Joint venture partner deposits | 46,929 | 47,234 |
Total accounts payable | 1,958,042 | 1,703,441 |
Accrued Expenses: | ||
Current portion of asset retirement obligations | 775,000 | 384,000 |
Payroll and retirement plan contributions | 664,384 | 641,326 |
Drilling | 106,100 | |
Other | 45,600 | 79,500 |
Federal, state and local taxes | 33,121 | 32,464 |
Total accrued expenses | $ 1,624,205 | $ 1,137,290 |
Note 3 - Partners' Equity (Deta
Note 3 - Partners' Equity (Details Textual) - $ / shares shares in Thousands | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Maximum percentage of units to be repurchased | 10.00% | ||
Percentage of Adjusted Book Value of Company Allocable to the Repurchase Right Per Unit | 66.00% | ||
Minimum Percentage of Outstanding Units Tendered to Use Prorated Method for Calculating Actual Number of Units Acquired | 10.00% | ||
Net Repurchase Price of Partner Unit | $ 0.11 | $ 4.56 | |
Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period, Gross | 0 | 0 | |
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Number | 0 | 0 |
Note 3 - Partners' Equity - Uni
Note 3 - Partners' Equity - Units Repurchased Pursuant to Repurchase Right and Issued Pursuant to Option Repurchase Plan (Details) - $ / shares | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2015 | Dec. 31, 2016 | |
Calculated Price for Repurchase Right (in dollars per share) | $ 4.935 | ||
Interim distributions (in dollars per share) | 0.375 | ||
Net Repurchase Price of Partner Unit | $ 0.11 | $ 4.56 | |
Units repurchased (in shares) | 26,774 | ||
Units issued (in shares) | 13,387 | ||
Units outstanding following units activity (in shares) | 5,587,616 | 5,587,616 | 5,587,616 |
Note 4 - Retirement Plan (Detai
Note 4 - Retirement Plan (Details Textual) - USD ($) | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Defined Contribution Plan, Employer Discretionary Contribution Amount | $ 194,400 | $ 168,700 |
Note 5 - Related Party Transa27
Note 5 - Related Party Transactions (Details Textual) | 12 Months Ended | |
Dec. 31, 2017USD ($) | Dec. 31, 2016USD ($) | |
Related Party Deposit Liabilities | $ 180,300 | $ 40,300 |
Employee [Member] | ||
Term of Employee Receivables | 4 years | |
Loan Forgiveness Provisions | 0 | |
Loans Forgiven | 0 | |
Related Party Transaction, Rate | 4.50% | |
Number of Employees to Whom Loans have been Extended | 3 | 2 |
Subsequent Addenda | 2 | |
Due from Employees | $ 46,742 | $ 87,045 |
Note 6 - Business Segments, R28
Note 6 - Business Segments, Risks and Major Customers (Details Textual) | 12 Months Ended | |
Dec. 31, 2017$ / Mcf | Dec. 31, 2016 | |
Oil and Gas Delivery Commitments and Contracts, Significant Supplies Dedicated or Contracted to Entity | 90,000 | |
Oil and Gas Delivery Commitments and Contracts, Fixed Price | 3.35 | |
Dominion Field Services, Inc. [Member] | ||
Productive Gas Wells, Number of Wells, Gross | 500 | |
Interstate Gas Supply, Inc. [Member] | ||
Productive Gas Wells, Number of Wells, Gross | 160 | |
Product Concentration Risk [Member] | Sales Revenue, Product Line [Member] | Product, Natural Gas [Member] | ||
Concentration Risk, Percentage | 73.00% | 61.00% |
Product Concentration Risk [Member] | Sales Revenue, Product Line [Member] | Crude Oil and Natural Gas from Operated Wells [Member] | ||
Concentration Risk, Percentage | 83.00% | 76.00% |
Customer Concentration Risk [Member] | Sales Revenue, Product Line [Member] | Product, Natural Gas [Member] | ||
Number of Major Customers | 2 | 2 |
Customer Concentration Risk [Member] | Natural Gas Sales from Operated Wells [Member] | Gas Purchasers [Member] | ||
Concentration Risk, Percentage | 76.00% | 63.00% |
Note 6 - Business Segments, R29
Note 6 - Business Segments, Risks and Major Customers - Table of Natural Gas Sales to Significant Purchasers as a Percentage of Consolidated Crude Oil and Natural Gas Sale (Details) - Customer Concentration Risk [Member] - Natural Gas Sales [Member] | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Concentration Risk, Percentage | 56.00% | 38.00% |
Dominion Field Services, Inc. [Member] | ||
Concentration Risk, Percentage | 44.00% | 25.00% |
Interstate Gas Supply, Inc. [Member] | ||
Concentration Risk, Percentage | 12.00% | 13.00% |
Note 8 - Supplemental Informa30
Note 8 - Supplemental Information Relating to Oil and Gas Producing Activities (Unaudited) (Details Textual) | 12 Months Ended | |
Dec. 31, 2017USD ($)a$ / Mcf$ / bbl | Dec. 31, 2016USD ($)a$ / Mcf$ / bbl | |
Costs Incurred, Acquisition of Oil and Gas Properties with Proved Reserves | $ 0 | $ 0 |
Gas and Oil Area, Undeveloped, Net | a | 14 | 46 |
Proved Undeveloped Carrying Cost | $ 35,700 | $ 36,200 |
Fair Value Inputs, Discount Rate | 10.00% | 10.00% |
Estimate of Proved Reserves Natural Gas Price | $ / Mcf | 2.09 | 1.41 |
Estimate of Proved Reserves Crude Oil Price | $ / bbl | 47.48 | 39.33 |
Note 8 - Supplemental Informa31
Note 8 - Supplemental Information Relating to Oil and Gas Producing Activities (Unaudited) - Capitalized Costs Relating to Oil and Gas Producing Activities (Details) - USD ($) | Dec. 31, 2017 | Dec. 31, 2016 |
Proved oil and gas properties | $ 179,141,990 | $ 181,447,571 |
Pipeline and support equipment | 682,135 | 682,135 |
Gross capitalized costs | 179,824,125 | 182,129,706 |
Accumulated depreciation, depletion, amortization and write down | 171,337,190 | 172,885,338 |
Net capitalized costs | $ 8,486,935 | $ 9,244,368 |
Note 8 - Supplemental Informa32
Note 8 - Supplemental Information Relating to Oil and Gas Producing Activities (Unaudited) - Costs Incurred in Oil and Gas Producing Activities (Details) - USD ($) | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Property acquisition costs | $ 11,045 | $ 20,363 |
Development costs | $ 192,284 | $ 136,274 |
Note 8 - Supplemental Informa33
Note 8 - Supplemental Information Relating to Oil and Gas Producing Activities (Unaudited) - Results of Operations for Oil and Gas Producing Activities (Details) - USD ($) | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Crude oil and natural gas sales | $ 7,086,476 | $ 3,439,081 |
Production costs | (2,160,029) | (2,133,282) |
Depreciation, depletion and amortization | (940,143) | (4,753,321) |
Accretion expense | (355,127) | (393,535) |
Write down/impairment and abandonment of crude oil and natural gas properties | (88,329) | |
Results of operations before income tax benefit | 3,631,177 | (3,929,386) |
Income tax benefit | (30,000) | (20,000) |
Results of operations for oil and gas producing activities (excluding corporate overhead and financing costs) | $ 3,661,177 | $ (3,909,386) |
Note 8 - Supplemental Informa34
Note 8 - Supplemental Information Relating to Oil and Gas Producing Activities (Unaudited) - Estimated Quantities of Proved Oil and Gas Reserves (Details) | 12 Months Ended | ||
Dec. 31, 2017bblMcf | Dec. 31, 2016bblMcf | Dec. 31, 2015bblMcf | |
Oil [Member] | |||
Beginning Balance | bbl | 244,000 | 277,000 | |
Extensions, discoveries and other additions | bbl | 8,000 | 5,000 | |
Production | bbl | (40,000) | (34,000) | |
Revision of previous estimates | bbl | 78,000 | (4,000) | |
Ending Balance | bbl | 290,000 | 244,000 | |
PROVED DEVELOPED RESERVES: | |||
Proved developed reserves | bbl | 290,000 | 244,000 | 277,000 |
Natural Gas [Member] | |||
Beginning Balance | Mcf | 5,280,000 | 7,991,000 | |
Extensions, discoveries and other additions | Mcf | 17,000 | 13,000 | |
Production | Mcf | (1,904,000) | (1,157,000) | |
Revision of previous estimates | Mcf | 7,851,000 | (1,567,000) | |
Ending Balance | Mcf | 11,244,000 | 5,280,000 | |
PROVED DEVELOPED RESERVES: | |||
Proved developed reserves | Mcf | 11,244,000 | 5,280,000 | 7,991,000 |
Note 8 - Supplemental Informa35
Note 8 - Supplemental Information Relating to Oil and Gas Producing Activities (Unaudited) - Standardized Measure of Discounted Future Net Cash Flow (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Future cash inflows from sales of oil and gas | $ 37,232 | $ 17,014 | |
Future production and development costs | (22,716) | (10,853) | |
Future asset retirement obligations, net of salvage | (16,360) | (16,451) | |
Future income tax expense | (132) | (95) | |
Future net cash flows | (1,976) | (10,385) | |
Effect of discounting future net cash flows at 10% per annum | (3,078) | 461 | |
Standardized measure of discounted future net cash flows | $ (5,054) | $ (9,924) | $ (8,211) |
Note 8 - Supplemental Informa36
Note 8 - Supplemental Information Relating to Oil and Gas Producing Activities (Unaudited) - Standardized Measure of Discounted Future Net Cash Flow (Details) (Parentheticals) | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Fair value inputs, discount rate | 10.00% | 10.00% |
Note 8 - Supplemental Informa37
Note 8 - Supplemental Information Relating to Oil and Gas Producing Activities (Unaudited) - Changes in Standardized Measure of Discounted Future Net Cash Flows (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Balance, beginning of year | $ (9,924) | $ (8,211) |
Extensions, discoveries and other additions | 197 | 85 |
Revision of quantity estimates | 4,031 | (184) |
Sales of crude oil and natural gas, net of production costs | (4,926) | (1,306) |
Net change in income taxes | (20) | 32 |
Net changes in prices and production costs | 2,478 | (1,080) |
Accretion of discount | (992) | (821) |
Other | 4,102 | 1,561 |
Balance, end of year | $ (5,054) | $ (9,924) |