Everflow Eastern Partners 10-K 28 Mar 17 2016 FY Annual report Financial data

Document And Entity Information

Document And Entity Information - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Apr. 05, 2017	Jun. 30, 2016
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, 2016
Document Fiscal Year Focus	2,016
Document Fiscal Period Focus	FY
Amendment Flag	false

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($)	Dec. 31, 2016	Dec. 31, 2015
CURRENT ASSETS
Cash and equivalents	$ 11,224,865	$ 22,734,047
Investments	10,080,608	0
Accounts receivable:
Production	1,014,946	572,502
Joint venture partners	3,366	4,151
Employees' notes receivable	41,000	35,000
Other	52,831	45,838
Total current assets	22,417,616	23,391,538
PROPERTY AND EQUIPMENT
Proved properties (successful efforts accounting method)	181,447,571	181,293,110
Pipeline and support equipment	682,135	631,757
Corporate and other	2,116,482	2,114,844
Gross property and equipment	184,246,188	184,039,711
Less accumulated depreciation, depletion, amortization and write down	173,979,881	169,093,931
Net property and equipment	10,266,307	14,945,780
OTHER ASSETS
Employees' notes receivable	46,045	89,437
Other	176,558	176,442
Total other assets	222,603	265,879
TOTAL ASSETS	32,906,526	38,603,197
CURRENT LIABILITIES
Accounts payable	1,703,441	1,839,816
Accrued expenses	1,137,290	1,130,772
Total current liabilities	2,840,731	2,970,588
DEFERRED INCOME TAXES	74,000	74,000
JOINT VENTURE PARTNER ADVANCES	1,053,582	1,004,953
ASSET RETIREMENT OBLIGATIONS	16,740,630	16,393,560
COMMITMENTS AND CONTINGENCIES
LIMITED PARTNERS' EQUITY, SUBJECT TO REPURCHASE RIGHT
Authorized - 8,000,000 Units Issued and outstanding - 5,587,616	12,052,848	17,944,611
GENERAL PARTNER'S EQUITY	144,735	215,485
Total partners' equity	12,197,583	18,160,096
TOTAL LIABILITIES AND PARTNERS' EQUITY	$ 32,906,526	$ 38,603,197

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parentheticals) - shares	Dec. 31, 2016	Dec. 31, 2015
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, 2016	Dec. 31, 2015
REVENUES
Crude oil and natural gas sales	$ 3,439,081	$ 5,728,206
Well management and operating	409,454	499,898
Other	32,719	109,408
Total revenues	3,881,254	6,337,512
DIRECT COST OF REVENUES
Production costs	2,164,682	2,734,789
Well management and operating	239,815	296,712
Depreciation, depletion and amortization	4,753,321	12,363,647
Accretion expense	393,535	583,792
Write down/impairment and abandonment of crude oil and natural gas properties	88,329	9,575,275
Total direct cost of revenues	7,639,682	25,554,215
GENERAL AND ADMINISTRATIVE EXPENSE	2,315,882	2,709,530
Total cost of revenues	9,955,564	28,263,745
LOSS FROM OPERATIONS	(6,074,310)	(21,926,233)
OTHER INCOME
Interest and dividend income	92,216	34,222
Gain on sale of property and equipment		13,298
Gain on sale of other assets		239,652
Total other income	92,216	287,172
LOSS BEFORE INCOME TAXES	(5,982,094)	(21,639,061)
INCOME TAX EXPENSE (BENEFIT)
Current	(19,581)	10,600
Deferred		(120,000)
Total income tax benefit	(19,581)	(109,400)
NET LOSS	(5,962,513)	(21,529,661)
Allocation of Partnership Net Loss:
Limited Partners	(5,891,763)	(21,274,495)
General Partner	(70,750)	(255,166)
NET LOSS	$ (5,962,513)	$ (21,529,661)
Net loss per unit (in dollars per share)	$ (1.05)	$ (3.80)

Consolidated Statements of Part

Consolidated Statements of Partners' Equity	USD ($)
PARTNERS' EQUITY – BEGINNING OF YEAR at Dec. 31, 2014	$ 43,714,129
Net loss	(21,529,661)
Cash distributions ($0.70 per unit in 2015)	(3,963,328)
Repurchase of Units	(122,089)
Options exercised	61,045
PARTNERS' EQUITY – END OF YEAR at Dec. 31, 2015	18,160,096
Net loss	(5,962,513)
Cash distributions ($0.70 per unit in 2015)
Repurchase of Units
Options exercised
PARTNERS' EQUITY – END OF YEAR at Dec. 31, 2016	$ 12,197,583

Consolidated Statements of Par6

Consolidated Statements of Partners' Equity (Parentheticals) - $ / shares	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Cash distributions, per unit (in dollars per share)		$ 0.70

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
CASH FLOWS FROM OPERATING ACTIVITIES
Net loss	$ (5,962,513)	$ (21,529,661)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization	4,840,987	12,452,899
Accretion expense	393,535	583,792
Write down/impairment and abandonment of crude oil and natural gas properties	88,329	9,575,275
Gain on sale of property and equipment		(13,298)
Gain on sale of other assets		(239,652)
Deferred income taxes		(120,000)
Changes in assets and liabilities:
Accounts receivable	(441,659)	892,004
Other current assets	(6,993)	10,600
Other assets	(116)	860
Accounts payable	(136,375)	19,884
Accrued expenses	(41,091)	(458,779)
Joint venture partner advances	48,629	48,881
Total adjustments	4,745,246	22,752,466
Net cash provided by (used in) operating activities	(1,217,267)	1,222,805
CASH FLOWS FROM INVESTING ACTIVITIES
Purchase of investments	(10,080,608)
Payments received on notes receivables from employees	37,392	30,283
Advances disbursed to employees		(14,171)
Purchase of property and equipment	(248,699)	(101,084)
Proceeds from sale of property and equipment		17,355
Proceeds from sale of other assets		249,652
Net cash provided by (used in) investing activities	(10,291,915)	182,035
CASH FLOWS FROM FINANCING ACTIVITIES
Distributions		(3,963,328)
Repurchase of Units		(122,089)
Proceeds from options exercised		61,045
Net cash used in financing activities		(4,024,372)
NET CHANGE IN CASH AND EQUIVALENTS	(11,509,182)	(2,619,532)
CASH AND EQUIVALENTS AT BEGINNING OF YEAR	22,734,047	25,353,579
CASH AND EQUIVALENTS AT END OF YEAR	11,224,865	22,734,047
Supplemental disclosures of cash flow information:
Income taxes	$ 390	$ 12,270

Note 1 - Organization and Summa

Note 1 - Organization and Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2016
Notes to Financial Statements
Organization, Consolidation and Presentation of Financial Statements Disclosure and Significant Accounting Policies [Text Block]	Note 1. 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 assets other than its general partner's interest in Everflow, nor does it have any liabilities. In addition, EML has no separate operations or role apart from its role as the Company's general partner. 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, $1,053,582 $1,004,953 December 31, 2016 2015, 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 Company did not hold any investments during 2015. 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 further interest in) that do not find proved reserves and geological and geophysical costs are expensed. The Company has not participated in exploratory drilling and owns no interest in unproved properties. 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 $4,709,814 $12,318,335 2016 2015, 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 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 observable in the market and therefore the fair value of the oil and gas properties is classified as Level III. The Company wrote down crude oil and natural gas properties by $88,329 $9,575,275 2016 2015, Additions to proved properties include changes to asset retirement obligations (see Note 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 $43,507 $45,312 December 31, 2016 2015, $87,666 $89,252 December 31, 2016 2015, 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. At December 31, 2015, The Company has no assets legally restricted for purposes of settling asset retirement obligations. The Company has determined that there are no other material retirement obligations associated with tangible long-lived assets. The schedule below is a reconciliation of the Company's liability for the years ended December 31: 2016 2015 Beginning of period $ 16,736,560 $ 11,108,044 Liabilities incurred 1,144 432 Liabilities settled (6,609 ) (79,620 ) Accretion expense 393,535 583,792 Revisions in estimated cash flows - 5,123,912 End of period $ 17,124,630 $ 16,736,560 The current portion of asset retirement obligations of $384,000 $343,000 December 31, 2016 2015, 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 material gas imbalances at December 31, 2016 2015. The Company participates (and may 6). 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 a tax-paying entity and the net taxable income or loss, other than the taxable income or loss allocable to EEI, which is a C corporation owned by Everflow, will be allocated directly to its respective partners. The Company is not able to determine the net difference between the tax bases and the reported amounts of Everflow's assets and liabilities due to separate elections that were made by owners of the working interests and limited partnership interests that comprised the Programs. As referred to in Note 4, The Company believes that it has appropriate support for any tax positions taken and, as such, does not have any uncertain tax positions that are material to the financial statements. The Company's tax returns are subject to examination by the Internal Revenue Service, as well as various state and local taxing authorities, generally for three 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 calculations amount to 5,587,616 5,594,310 2016 2015, K. New Accounting Standards – In May 2014, 2014 09, 606)” 2014 09”). 2014 09 2014 09 2014 09, 2015 14, issued for annual periods beginning after December 31, 2017 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 of these standards will have a significant effect on current or future earnings or results of operations.

Note 2 - Current Liabilities

Note 2 - Current Liabilities	12 Months Ended
	Dec. 31, 2016
Notes to Financial Statements
Accounts Payable and Accrued Liabilities Disclosure [Text Block]	Note 2. The Company's accounts payable and accrued expenses consist of the following at December 31: 2016 2015 Accounts Payable: Production and related other $ 1,364,131 $ 1,501,647 Other 292,076 290,935 Joint venture partner deposits 47,234 47,234 $ 1,703,441 $ 1,839,816 Accrued Expenses: Payroll and retirement plan contributions $ 641,326 $ 679,934 Current portion of asset retirement obligations 384,000 343,000 Other 79,500 75,300 Federal, state and local taxes 32,464 32,538 $ 1,137,290 $ 1,130,772

Note 3 - Partners' Equity

Note 3 - Partners' Equity	12 Months Ended
	Dec. 31, 2016
Notes to Financial Statements
Partners' Capital Notes Disclosure [Text Block]	N ote 3. 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 listed for trading on any securities exchange nor are they quoted in the automated quotation system of a registered securities association. However, Unitholders may The partnership agreement provides that Everflow will repurchase for cash up to 10% May 1 June 30 December 31 66% 10% tendered tendered 2017 December 31, 2016 2017. January 2017. 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 grant any options in 2016. June 2015, The Company did not repurchase any Units pursuant to the Repurchase Right during 2016. two December 31, 2015, Per Unit Calculated Units Price for Less Outstanding Repurchase Interim Net Units Units Following Year Right Distributions Price Paid Repurchased Issued Units Activity 2014 $ 7.010 $ 0.500 $ 6.51 11,964 5,982 5,601,003 2015 $ 4.935 $ 0.375 $ 4.56 26,774 13,387 5,587,616 All Units repurchased pursuant to the Repurchase Right were retired except for those Units issued through the exercise of options pursuant to the Option Plan. There were no instruments outstanding at December 31, 2016 2015

Note 4 - Provision for Income T

Note 4 - Provision for Income Taxes	12 Months Ended
	Dec. 31, 2016
Notes to Financial Statements
Income Tax Disclosure [Text Block]	Note 4 . Provision for Income Taxes A reconciliation between taxes computed at the Federal statutory rate and the effective tax rate in the statements of operations follows: Year Ended December 31, 2016 2015 Amount % Amount % Provision based on the statutory rate $ (2,034,000 ) (34.0 ) $ (7,357,000 ) (34.0 ) Tax effect of: Non-taxable status of the Programs and Everflow 1,881,000 31.4 7,130,000 32.9 Excess statutory depletion - 0.0 (30,000 ) (0.1 ) Graduated tax rates, permanent differences between book and tax items, tax credits and other - net 133,400 2.2 147,600 0.7 Total $ (19,600 ) (0.4 ) $ (109,400 ) (0.5 ) As referred to in Note 1,

Note 5 - Retirement Plans

Note 5 - Retirement Plans	12 Months Ended
	Dec. 31, 2016
Notes to Financial Statements
Pension and Other Postretirement Benefits Disclosure [Text Block]	Note 5. The Company has a defined contribution plan pursuant to Section 401(k) $168,700 $187,000 December 31, 2016 2015, The Company had a qualified non-contributory cash balance defined benefit retirement plan covering certain eligible employees (the “Pension Plan”, or the “Plan”) that was terminated in December 2015. three 5%. Net periodic benefit cost recognized in the consolidated statements of operations consists of the following during the year ended December 31, 2015: Service cost $ 100,000 Interest cost 49,500 Expected return on plan assets (64,800 ) Settlements 40,900 Net periodic benefit cost $ 125,600 The projected benefit obligation (the “PBO”) and accumulated benefit obligation are determined as the actuarial present value of the vested benefits to which the employees are currently entitled but based on their expected date of separation or retirement. The change in the projected benefit obligation of the Pension Plan and the change in assets at fair value are as follows during the year ended December 31, 2015: Change in PBO: PBO, beginning of year $ 990,700 Service cost 100,000 Interest cost 49,500 Actuarial (gain) loss (24,700 ) Settlements (1,115,500 ) Benefits paid - PBO, end of year $ - Change in Plan assets: Fair value, beginning of year 640,600 Actual return on plan assets (800 ) Company contributions 475,700 Benefits paid (1,115,500 ) Fair value, end of year $ - Funded status at December 31, 2015 $ - The Company’s funding policy for the Plan was to fund at least the amount actuarially determined necessary to comply with the minimum funding standards as defined by the Employee Retirement Income Security Act. Assumptions used in accounting for the projected benefit obligation at January 1, 2015 5% 7%. The Plan's investment policy reflected the long-term nature of the plan's funding obligations. The assets were invested to provide the opportunity for both income and growth of principal. This objective was pursued as a long-term goal designed to provide required benefits for participants without undue risk. It was expected that this objective would be achieved through a well-diversified asset portfolio. As such, the Plan’s assets, which were classified as Level I assets, were invested in a publicly traded mutual fund with a domestic blend of stocks and bonds at January 1, 2015. 2015,

Note 6 - Related Party Transact

Note 6 - Related Party Transactions	12 Months Ended
	Dec. 31, 2016
Notes to Financial Statements
Related Party Transactions Disclosure [Text Block]	Note 6. 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 four Employees remain obligated for the entire loan amount regardless of a dry-hole event or otherwise insufficient production. The loans carry no loan forgiveness provisions, and no loans have ever been forgiven. The loans accrue interest at the prime rate, which was 3.75% December 31, 2016. In accordance with the Sarbanes-Oxley Act of 2002, 2002. December 31, 2016 2015, two December 2010 December 2015. 3 December 31, 2016. $87,045 $124,437 December 31, 2016 2015,

Note 7 - Business Segments, Ris

Note 7 - Business Segments, Risks and Major Customers	12 Months Ended
	Dec. 31, 2016
Notes to Financial Statements
Segment Reporting Disclosure [Text Block]	Note 7. 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 limited to, the ability to acquire additional economically recoverable oil and gas reserves, the inherent risks of the search for, development of and production of oil and gas, the ability 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 gas sales accounted for 61% 65% 2016 2015, 76% 69% 2016 2015, two December 31, 2016 2015. Natural Gas Purchaser 2016 2015 Dominion Field Services, Inc. ("Dominion") 25 % 27 % Interstate Gas Supply, Inc. ("IGS") 13 14 38 % 41 % As of December 31, 2016, 460 200 63% 2016 2015, 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 view such concentration as an unusual credit risk. However, the Company does not require collateral from its customers and could incur losses if its customers fail to pay. As a result of management's review of current and historical credit losses and economic activity, a valuation allowance was not deemed necessary at December 31, 2016 2015. 2017. third may The Company has multiple contracts with Dominion and IGS (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 510,000 January 2017 October 2017 $2.45

Note 8 - Commitments and Contin

Note 8 - Commitments and Contingencies	12 Months Ended
	Dec. 31, 2016
Notes to Financial Statements
Commitments and Contingencies Disclosure [Text Block]	Note 8 . Commitments and Contingencies The Company has natural gas delivery commitments to the Gas Purchasers (see Note 7). may may In conjunction with the sale of approximately 28,800 2012, five five $1,250 three December 31, 2016. 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 have a material adverse effect on its consolidated financial position, results of operations, or liquidity.

Note 9 - Supplemental Informati

Note 9 - Supplemental Information Relating to Oil and Gas Producing Activities (Unaudited)	12 Months Ended
	Dec. 31, 2016
Notes to Financial Statements
Oil and Gas Exploration and Production Industries Disclosures [Text Block]	Note 9. 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, 2016 2015 Proved oil and gas properties $ 181,447,571 $ 181,293,110 Pipeline and support equipment 682,135 631,757 Gross capitalized costs 182,129,706 181,924,867 Accumulated depreciation, depletion, amortization and write down 172,885,338 168,088,105 Net capitalized costs $ 9,244,368 $ 13,836,762 COSTS INCURRED IN OIL AND GAS PRODUCING ACTIVITIES Years ended December 31, 2016 2015 Property acquisition costs $ 20,363 $ 29,037 Development costs 136,274 72,047 The Company had no purchases of producing oil and gas properties in 2016 2015. RESULTS OF OPERATIONS FOR OIL AND GAS PRODUCING ACTIVITIES Years ended December 31, 2016 2015 Crude oil and natural gas sales $ 3,439,081 $ 5,728,206 Production costs (2,164,682 ) (2,734,789 ) Depreciation, depletion and amortization (4,753,321 ) (12,363,647 ) Accretion expense (393,535 ) (583,792 ) Write down/impairment and abandonment of crude oil and natural gas properties (88,329 ) (9,575,275 ) Results of operations before income tax expense (benefit) (3,960,786 ) (19,529,297 ) Income tax expense (benefit) (20,000 ) 11,000 Results of operations for oil and gas producing activities (excluding corporate overhead and financing costs) $ (3,940,786 ) $ (19,540,297 ) 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, 2015 511,000 23,724,000 Extensions, discoveries and other additions 2,000 5,000 Production (44,000 ) (1,616,000 ) Revision of previous estimates (192,000 ) (14,122,000 ) Balance, December 31, 2015 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 PROVED DEVELOPED RESERVES: December 31, 2014 511,000 23,724,000 December 31, 2015 277,000 7,991,000 December 31, 2016 244,000 5,280,000 The Company has not determined proved reserves associated with its proved and other undeveloped properties, including its deep property interests. At December 31, 2016 2015, 46 91 $36,200 $35,700 December 31, 2016 2015, STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS December 31, 2016 2015 (Thousands of Dollars) Future cash inflows from sales of oil and gas $ 17,014 $ 23,821 Future production and development costs (10,853 ) (15,446 ) Future asset retirement obligations, net of salvage (16,451 ) (16,443 ) Future income tax expense (95 ) (144 ) Future net cash flows (10,385 ) (8,212 ) Effect of discounting future net cash flows at 10% per annum 461 1 Standardized measure of discounted future net cash flows $ (9,924 ) $ (8,211 ) CHANGES IN THE STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS Years Ended December 31, 2016 2015 (Thousands of Dollars) Balance, beginning of year $ (8,211 ) $ 28,157 Extensions, discoveries and other additions 85 30 Revision of quantity estimates (184 ) (2,562 ) Sales of crude oil and natural gas, net of production costs (1,274 ) (2,993 ) Net change in income taxes 32 573 Net changes in prices and production costs (1,080 ) (31,254 ) Accretion of discount (821 ) 2,816 Other 1,529 (2,978 ) Balance, end of year $ (9,924 ) $ (8,211 ) 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 intended to be representative of the fair market value of the Company's proved reserves. The valuation of revenues and costs does not necessarily reflect the amounts to be received or expended by the Company. In addition to the valuations used, numerous other factors are considered in evaluating known and prospective oil and gas reserves. Average adjusted natural gas prices used in the estimation of proved reserves were $1.41 $1.37 December 31, 2016 2015, $39.33 $46.40 December 31, 2016 2015,

Significant Accounting Policies

Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2016
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 assets other than its general partner's interest in Everflow, nor does it have any liabilities. In addition, EML has no separate operations or role apart from its role as the Company's general partner. 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, $1,053,582 $1,004,953 December 31, 2016 2015,
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 Company did not hold any investments during 2015. 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 further interest in) that do not find proved reserves and geological and geophysical costs are expensed. The Company has not participated in exploratory drilling and owns no interest in unproved properties. 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 $4,709,814 $12,318,335 2016 2015, 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 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 observable in the market and therefore the fair value of the oil and gas properties is classified as Level III. The Company wrote down crude oil and natural gas properties by $88,329 $9,575,275 2016 2015, Additions to proved properties include changes to asset retirement obligations (see Note 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 $43,507 $45,312 December 31, 2016 2015, $87,666 $89,252 December 31, 2016 2015, 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 Obligations, Policy [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. At December 31, 2015, The Company has no assets legally restricted for purposes of settling asset retirement obligations. The Company has determined that there are no other material retirement obligations associated with tangible long-lived assets. The schedule below is a reconciliation of the Company's liability for the years ended December 31: 2016 2015 Beginning of period $ 16,736,560 $ 11,108,044 Liabilities incurred 1,144 432 Liabilities settled (6,609 ) (79,620 ) Accretion expense 393,535 583,792 Revisions in estimated cash flows - 5,123,912 End of period $ 17,124,630 $ 16,736,560 The current portion of asset retirement obligations of $384,000 $343,000 December 31, 2016 2015,
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 material gas imbalances at December 31, 2016 2015. The Company participates (and may 6). 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 a tax-paying entity and the net taxable income or loss, other than the taxable income or loss allocable to EEI, which is a C corporation owned by Everflow, will be allocated directly to its respective partners. The Company is not able to determine the net difference between the tax bases and the reported amounts of Everflow's assets and liabilities due to separate elections that were made by owners of the working interests and limited partnership interests that comprised the Programs. As referred to in Note 4, The Company believes that it has appropriate support for any tax positions taken and, as such, does not have any uncertain tax positions that are material to the financial statements. The Company's tax returns are subject to examination by the Internal Revenue Service, as well as various state and local taxing authorities, generally for three
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 calculations amount to 5,587,616 5,594,310 2016 2015,
New Accounting Pronouncements, Policy [Policy Text Block]	K. New Accounting Standards – In May 2014, 2014 09, 606)” 2014 09”). 2014 09 2014 09 2014 09, 2015 14, issued for annual periods beginning after December 31, 2017 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 of these standards will have a significant effect on current or future earnings or results of operations.

Note 1 - Organization and Sum18

Note 1 - Organization and Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2016
Notes Tables
Schedule of Asset Retirement Obligations [Table Text Block]	2016 2015 Beginning of period $ 16,736,560 $ 11,108,044 Liabilities incurred 1,144 432 Liabilities settled (6,609 ) (79,620 ) Accretion expense 393,535 583,792 Revisions in estimated cash flows - 5,123,912 End of period $ 17,124,630 $ 16,736,560

Note 2 - Current Liabilities (T

Note 2 - Current Liabilities (Tables)	12 Months Ended
	Dec. 31, 2016
Notes Tables
Schedule of Accounts Payable and Accrued Liabilities [Table Text Block]	2016 2015 Accounts Payable: Production and related other $ 1,364,131 $ 1,501,647 Other 292,076 290,935 Joint venture partner deposits 47,234 47,234 $ 1,703,441 $ 1,839,816 Accrued Expenses: Payroll and retirement plan contributions $ 641,326 $ 679,934 Current portion of asset retirement obligations 384,000 343,000 Other 79,500 75,300 Federal, state and local taxes 32,464 32,538 $ 1,137,290 $ 1,130,772

Note 3 - Partners' Equity (Tabl

Note 3 - Partners' Equity (Tables)	12 Months Ended
	Dec. 31, 2016
Notes Tables
Units Repurchased and Issued [Table Text Block]	Per Unit Calculated Units Price for Less Outstanding Repurchase Interim Net Units Units Following Year Right Distributions Price Paid Repurchased Issued Units Activity 2014 $ 7.010 $ 0.500 $ 6.51 11,964 5,982 5,601,003 2015 $ 4.935 $ 0.375 $ 4.56 26,774 13,387 5,587,616

Note 4 - Provision for Income21

Note 4 - Provision for Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2016
Notes Tables
Schedule of Effective Income Tax Rate Reconciliation [Table Text Block]	Year Ended December 31, 2016 2015 Amount % Amount % Provision based on the statutory rate $ (2,034,000 ) (34.0 ) $ (7,357,000 ) (34.0 ) Tax effect of: Non-taxable status of the Programs and Everflow 1,881,000 31.4 7,130,000 32.9 Excess statutory depletion - 0.0 (30,000 ) (0.1 ) Graduated tax rates, permanent differences between book and tax items, tax credits and other - net 133,400 2.2 147,600 0.7 Total $ (19,600 ) (0.4 ) $ (109,400 ) (0.5 )

Note 5 - Retirement Plans (Tabl

Note 5 - Retirement Plans (Tables)	12 Months Ended
	Dec. 31, 2016
Notes Tables
Schedule of Net Benefit Costs [Table Text Block]	Service cost $ 100,000 Interest cost 49,500 Expected return on plan assets (64,800 ) Settlements 40,900 Net periodic benefit cost $ 125,600
Changes in Projected Benefit Obligations, Fair Value of Plan Assets, and Funded Status of Plan [Table Text Block]	Change in PBO: PBO, beginning of year $ 990,700 Service cost 100,000 Interest cost 49,500 Actuarial (gain) loss (24,700 ) Settlements (1,115,500 ) Benefits paid - PBO, end of year $ - Change in Plan assets: Fair value, beginning of year 640,600 Actual return on plan assets (800 ) Company contributions 475,700 Benefits paid (1,115,500 ) Fair value, end of year $ - Funded status at December 31, 2015 $ -

Note 7 - Business Segments, R23

Note 7 - Business Segments, Risks and Major Customers (Tables)	12 Months Ended
	Dec. 31, 2016
Notes Tables
Schedule of Revenue by Major Customers by Reporting Segments [Table Text Block]	Natural Gas Purchaser 2016 2015 Dominion Field Services, Inc. ("Dominion") 25 % 27 % Interstate Gas Supply, Inc. ("IGS") 13 14 38 % 41 %

Note 9 - Supplemental Informa24

Note 9 - Supplemental Information Relating to Oil and Gas Producing Activities (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2016
Notes Tables
Capitalized Costs Relating to Oil and Gas Producing Activities Disclosure [Table Text Block]	CAPITALIZED COSTS RELATING TO OIL AND GAS PRODUCING ACTIVITIES Years ended December 31, 2016 2015 Proved oil and gas properties $ 181,447,571 $ 181,293,110 Pipeline and support equipment 682,135 631,757 Gross capitalized costs 182,129,706 181,924,867 Accumulated depreciation, depletion, amortization and write down 172,885,338 168,088,105 Net capitalized costs $ 9,244,368 $ 13,836,762
Cost Incurred in Oil and Gas Property Acquisition, Exploration, and Development Activities Disclosure [Table Text Block]	COSTS INCURRED IN OIL AND GAS PRODUCING ACTIVITIES Years ended December 31, 2016 2015 Property acquisition costs $ 20,363 $ 29,037 Development costs 136,274 72,047
Results of Operations for Oil and Gas Producing Activities Disclosure [Table Text Block]	RESULTS OF OPERATIONS FOR OIL AND GAS PRODUCING ACTIVITIES Years ended December 31, 2016 2015 Crude oil and natural gas sales $ 3,439,081 $ 5,728,206 Production costs (2,164,682 ) (2,734,789 ) Depreciation, depletion and amortization (4,753,321 ) (12,363,647 ) Accretion expense (393,535 ) (583,792 ) Write down/impairment and abandonment of crude oil and natural gas properties (88,329 ) (9,575,275 ) Results of operations before income tax expense (benefit) (3,960,786 ) (19,529,297 ) Income tax expense (benefit) (20,000 ) 11,000 Results of operations for oil and gas producing activities (excluding corporate overhead and financing costs) $ (3,940,786 ) $ (19,540,297 )
Schedule of Proved Developed and Undeveloped Oil and Gas Reserve Quantities [Table Text Block]	ESTIMATED QUANTITIES OF PROVED OIL AND GAS RESERVES Oil Gas (BBLS) (MCF) Balance, January 1, 2015 511,000 23,724,000 Extensions, discoveries and other additions 2,000 5,000 Production (44,000 ) (1,616,000 ) Revision of previous estimates (192,000 ) (14,122,000 ) Balance, December 31, 2015 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 PROVED DEVELOPED RESERVES: December 31, 2014 511,000 23,724,000 December 31, 2015 277,000 7,991,000 December 31, 2016 244,000 5,280,000
Standardized Measure of Discounted Future Cash Flows Relating to Proved Reserves Disclosure [Table Text Block]	STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS December 31, 2016 2015 (Thousands of Dollars) Future cash inflows from sales of oil and gas $ 17,014 $ 23,821 Future production and development costs (10,853 ) (15,446 ) Future asset retirement obligations, net of salvage (16,451 ) (16,443 ) Future income tax expense (95 ) (144 ) Future net cash flows (10,385 ) (8,212 ) Effect of discounting future net cash flows at 10% per annum 461 1 Standardized measure of discounted future net cash flows $ (9,924 ) $ (8,211 )
Schedule of Changes in Standardized Measure of Discounted Future Net Cash Flows [Table Text Block]	CHANGES IN THE STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS Years Ended December 31, 2016 2015 (Thousands of Dollars) Balance, beginning of year $ (8,211 ) $ 28,157 Extensions, discoveries and other additions 85 30 Revision of quantity estimates (184 ) (2,562 ) Sales of crude oil and natural gas, net of production costs (1,274 ) (2,993 ) Net change in income taxes 32 573 Net changes in prices and production costs (1,080 ) (31,254 ) Accretion of discount (821 ) 2,816 Other 1,529 (2,978 ) Balance, end of year $ (9,924 ) $ (8,211 )

Note 1 - Organization and Sum25

Note 1 - Organization and Summary of Significant Accounting Policies (Details Textual)	12 Months Ended
	Dec. 31, 2016USD ($)shares	Dec. 31, 2015USD ($)shares
Customer Advances, Noncurrent	$ 1,053,582	$ 1,004,953
Depletion, Depreciation and Amortization on Proved Properties	4,709,814	12,318,335
Impairment of Oil and Gas Properties	88,329	9,575,275
Buildings and Improvements, Gross	1,536,288
Asset Retirement Obligation, Current	384,000	343,000
General Partner, Assets	0
General Partner, Liabilities	$ 0
Period Open to Tax Returns Examination	3 years
General Partner, Operations	0
Cash and Equivalents Maturity Period	90 days
Short-term Investments	$ 10,080,608	0
Asset Retirement Obligation, Legally Restricted Assets, Fair Value	0
Other Material Retirement Obligations Associated with Tangible Long-lived Assets	$ 0
Number of Uncertain Tax Positions	0
Gas Balancing Payable	$ 0	$ 0
Limited Partner [Member]
Initial Percentage of Revenue and Cost Allocation	99.00%
Weighted Average Limited Partnership Units Outstanding, Basic | shares	5,587,616	5,594,310
General Partner [Member]
Initial Percentage of Revenue and Cost Allocation	1.00%
Pipeline and Support Equipment [Member]
Depreciation	$ 43,507	$ 45,312
Other Corporate Property [Member] | General and Administrative Expense [Member]
Depreciation	$ 87,666	$ 89,252
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 Sum26

Note 1 - Organization and Summary of Significant Accounting Policies - Reconciliation of Company's Asset Retirement Obligations (Details) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Beginning of period	$ 16,736,560	$ 11,108,044
Liabilities incurred	1,144	432
Liabilities settled	(6,609)	(79,620)
Accretion expense	393,535	583,792
Revisions in estimated cash flows		5,123,912
End of period	$ 17,124,630	$ 16,736,560

Note 2 - Current Liabilities -

Note 2 - Current Liabilities - Components of Accounts Payable and Accrued (Details) - USD ($)	Dec. 31, 2016	Dec. 31, 2015
Production and related other	$ 1,364,131	$ 1,501,647
Other	292,076	290,935
Joint venture partner deposits	47,234	47,234
Total Accounts Payable	1,703,441	1,839,816
Payroll and retirement plan contributions	641,326	679,934
Current portion of asset retirement obligations	384,000	343,000
Other	79,500	75,300
Federal, state and local taxes	32,464	32,538
Total Accrued Expenses	$ 1,137,290	$ 1,130,772

Note 3 - Partners' Equity (Deta

Note 3 - Partners' Equity (Details Textual) - shares	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
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%
Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period, Gross	0
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Number	0	0
Number of Units Repurchased	0	26,774	11,964

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, 2016	Dec. 31, 2015	Dec. 31, 2014
Calculated price for Repurchase Right (in dollars per share)		$ 4.935	$ 7.01
Interim distributions (in dollars per share)		0.375	0.50
Net price paid (in dollars per share)		$ 4.56	$ 6.51
Number of Units Repurchased	0	26,774	11,964
Units issued (in shares)		13,387	5,982
Units outstanding following units activity (in shares)	5,587,616	5,587,616	5,601,003

Note 4 - Provision for Income30

Note 4 - Provision for Income Taxes - Reconciliation Taxes Computed at Federal Statutory Rate and Effective Tax Rate in Statements of Operations (Details) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Provision based on the statutory rate	$ (2,034,000)	$ (7,357,000)
Provision based on the statutory rate	(34.00%)	(34.00%)
Tax effect of:
Non-taxable status of the Programs and Everflow	$ 1,881,000	$ 7,130,000
Non-taxable status of the Programs and Everflow	31.40%	32.90%
Excess statutory depletion		$ (30,000)
Excess statutory depletion	0.00%	(0.10%)
Graduated tax rates, permanent differences between book and tax items, tax credits and other - net	$ 133,400	$ 147,600
Graduated tax rates, permanent differences between book and tax items, tax credits and other - net	2.20%	0.70%
Total	$ (19,581)	$ (109,400)
Total	(0.40%)	(0.50%)

Note 5 - Retirement Plans (Deta

Note 5 - Retirement Plans (Details Textual) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Defined Contribution Plan, Employer Discretionary Contribution Amount	$ 168,700	$ 187,000
Defined Benefit Pension Plan, Vesting Period		3 years
Defined Benefit Plan, Interest Credits		5.00%
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate			5.00%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Expected Long-term Return on Assets			7.00%

Note 5 - Retirement Plans - Sch

Note 5 - Retirement Plans - Schedule of Net Periodic Benefit Cost (Details)	12 Months Ended
	Dec. 31, 2015USD ($)
Service cost	$ 100,000
Interest cost	49,500
Expected return on plan assets	(64,800)
Settlements	40,900
Net periodic benefit cost	$ 125,600

Note 5 - Retirement Plans - S33

Note 5 - Retirement Plans - Schedule of Change in Projected Benefit Obligation of Pension Plan and Change in Assets at Fair Value (Details) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2015
PBO, beginning of year	$ 990,700
Service cost	100,000
Interest cost	49,500
Actuarial (gain) loss	(24,700)
Settlements	(1,115,500)
PBO, end of year
Fair value, beginning of year	640,600
Actual return on plan assets	(800)
Company contributions	475,700
Benefits paid	(1,115,500)
Fair value, end of year	640,600
Funded status at December 31, 2015

Note 6 - Related Party Transa34

Note 6 - Related Party Transactions (Details Textual) - Employee [Member]	12 Months Ended
	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)
Term of Employee Receivables	4 years
Related Party Transaction, Rate	3.75%
Due from Employees	$ 87,045	$ 124,437
Loan Forgiveness Provisions	0
Loans Forgiven	0
Number of Employees to Whom Loans have been Extended	2
Subsequent Addenda	3

Note 7 - Business Segments, R35

Note 7 - Business Segments, Risks and Major Customers (Details Textual)	12 Months Ended
	Dec. 31, 2016Mcf$ / Mcf	Dec. 31, 2015
Oil and Gas Delivery Commitments and Contracts, Significant Supplies Dedicated or Contracted to Entity | Mcf	510,000
Oil and Gas Delivery Commitments and Contracts, Fixed Price | $ / Mcf	2.45
Interstate Gas Supply, Inc. [Member]
Productive Gas Wells, Number of Wells, Gross	200
Dominion Field Services, Inc. [Member]
Productive Gas Wells, Number of Wells, Gross	460
Product Concentration Risk [Member] | Sales Revenue, Product Line [Member] | Product, Natural Gas [Member]
Concentration Risk, Percentage	61.00%	65.00%
Product Concentration Risk [Member] | Sales Revenue, Product Line [Member] | Crude Oil and Natural Gas from Operated Wells [Member]
Concentration Risk, Percentage	76.00%	69.00%
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	63.00%	63.00%

Note 7 - Business Segments, R36

Note 7 - 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, 2016	Dec. 31, 2015
Concentration Risk, Percentage	38.00%	41.00%
Dominion Field Services, Inc. [Member]
Concentration Risk, Percentage	25.00%	27.00%
Interstate Gas Supply, Inc. [Member]
Concentration Risk, Percentage	13.00%	14.00%

Note 8 - Commitments and Cont37

Note 8 - Commitments and Contingencies (Details Textual) $ in Thousands	12 Months Ended
	Dec. 31, 2016USD ($)$ / a	Dec. 31, 2012a
Acreage Sold with Production Requirements | a		28,800
Refund price per acre | $ / a	1,250
Lease Renewal Period	90 days
Reserve for Potential Refunded Acreage | $	$ 0
Minimum [Member]
Contingency Period for Producing Leases	5 years

Note 9 - Supplemental Informa38

Note 9 - Supplemental Information Relating to Oil and Gas Producing Activities (Unaudited) (Details Textual)	12 Months Ended
	Dec. 31, 2016USD ($)a$ / bbl$ / Mcf	Dec. 31, 2015USD ($)a$ / bbl$ / Mcf
Proved Undeveloped Carrying Cost	$ 36,200	$ 35,700
Fair Value Inputs, Discount Rate	10.00%	10.00%
Estimate of Proved Reserves Natural Gas Price | $ / Mcf	1.41	1.37
Estimate of Proved Reserves Crude Oil Price | $ / bbl	39.33	46.4
Costs Incurred, Acquisition of Oil and Gas Properties with Proved Reserves	$ 0	$ 0
Gas and Oil Area, Undeveloped, Net | a	46	91

Note 9 - Supplemental Informa39

Note 9 - Supplemental Information Relating to Oil and Gas Producing Activities (Unaudited) - Capitalized Costs Relating to Oil and Gas Producing Activities (Details) - USD ($)	Dec. 31, 2016	Dec. 31, 2015
Proved oil and gas properties	$ 181,447,571	$ 181,293,110
Pipeline and support equipment	682,135	631,757
Gross capitalized costs	182,129,706	181,924,867
Accumulated depreciation, depletion, amortization and write down	172,885,338	168,088,105
Net capitalized costs	$ 9,244,368	$ 13,836,762

Note 9 - Supplemental Informa40

Note 9 - 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, 2016	Dec. 31, 2015
Property acquisition costs	$ 20,363	$ 29,037
Development costs	$ 136,274	$ 72,047

Note 9 - Supplemental Informa41

Note 9 - 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, 2016	Dec. 31, 2015
Crude oil and natural gas sales	$ 3,439,081	$ 5,728,206
Production costs	(2,164,682)	(2,734,789)
Depreciation, depletion and amortization	(4,753,321)	(12,363,647)
Accretion expense	(393,535)	(583,792)
Write down/impairment and abandonment of crude oil and natural gas properties	(88,329)	(9,575,275)
Results of operations before income tax expense (benefit)	(3,960,786)	(19,529,297)
Income tax expense (benefit)	(20,000)	11,000
Results of operations for oil and gas producing activities (excluding corporate overhead and financing costs)	$ (3,940,786)	$ (19,540,297)

Note 9 - Supplemental Informa42

Note 9 - Supplemental Information Relating to Oil and Gas Producing Activities (Unaudited) - Estimated Quantities of Proved Oil and Gas Reserves (Details)	12 Months Ended
	Dec. 31, 2016bblMcf	Dec. 31, 2015bblMcf	Dec. 31, 2014bblMcf
Oil [Member]
Beginning Balance | bbl	277,000	511,000
Extensions, discoveries and other additions | bbl	5,000	2,000
Production | bbl	(34,000)	(44,000)
Revision of previous estimates | bbl	(4,000)	(192,000)
Ending Balance | bbl	244,000	277,000
PROVED DEVELOPED RESERVES:
Proved developed reserves | bbl	244,000	277,000	511,000
Natural Gas [Member]
Beginning Balance | Mcf	7,991,000	23,724,000
Extensions, discoveries and other additions | Mcf	13,000	5,000
Production | Mcf	(1,157,000)	(1,616,000)
Revision of previous estimates | Mcf	(1,567,000)	(14,122,000)
Ending Balance | Mcf	5,280,000	7,991,000
PROVED DEVELOPED RESERVES:
Proved developed reserves | Mcf	5,280,000	7,991,000	23,724,000

Note 9 - Supplemental Informa43

Note 9 - 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, 2016	Dec. 31, 2015	Dec. 31, 2014
Future cash inflows from sales of oil and gas	$ 17,014	$ 23,821
Future production and development costs	(10,853)	(15,446)
Future asset retirement obligations, net of salvage	(16,451)	(16,443)
Future income tax expense	(95)	(144)
Future net cash flows	(10,385)	(8,212)
Effect of discounting future net cash flows at 10% per annum	461	1
Standardized measure of discounted future net cash flows	$ (9,924)	$ (8,211)	$ 28,157

Note 9 - Supplemental Informa44

Note 9 - 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, 2016	Dec. 31, 2015
Fair value inputs, discount rate	10.00%	10.00%

Note 9 - Supplemental Informa45

Note 9 - 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, 2016	Dec. 31, 2015
Balance, beginning of year	$ (8,211)	$ 28,157
Extensions, discoveries and other additions	85	30
Revision of quantity estimates	(184)	(2,562)
Sales of crude oil and natural gas, net of production costs	(1,274)	(2,993)
Net change in income taxes	32	573
Net changes in prices and production costs	(1,080)	(31,254)
Accretion of discount	(821)	2,816
Other	1,529	(2,978)
Balance, end of year	$ (9,924)	$ (8,211)