Yuma Energy (YUMAQ) 10-K 2 Apr 19 2018 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2018	Mar. 29, 2019	Jun. 30, 2018
Document And Entity Information
Entity Registrant Name	Yuma Energy, Inc.
Entity Central Index Key	0001672326
Document Type	10-K
Document Period End Date	Dec. 31, 2018
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Is Entity a Well-known Seasoned Issuer?	No
Is Entity a Voluntary Filer?	No
Is Entity's Reporting Status Current?	Yes
Entity Filer Category	Non-accelerated Filer
Entity Emerging Growth Company	false
Entity Small Business	true
Entity Shell Company	false
Entity Public Float			$ 9,222,288
Entity Common Stock, Shares Outstanding		23,163,165
Document Fiscal Period Focus	FY
Document Fiscal Year Focus	2018

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($)	Dec. 31, 2018	Dec. 31, 2017
CURRENT ASSETS:
Cash and cash equivalents	$ 1,634,492	$ 137,363
Accounts receivable, net of allowance for doubtful accounts:
Trade	3,183,806	4,496,316
Officers and employees	12,748	53,979
Other	183,026	1,004,479
Commodity derivative instruments	751,158	0
Prepayments	1,152,126	976,462
Other deferred charges	256,261	347,490
Total current assets	7,173,617	7,016,089
OIL AND GAS PROPERTIES (full cost method):
Proved properties	504,139,740	494,216,531
Unproved properties - not subject to amortization	0	6,794,372
Subtotal	504,139,740	501,010,903
Less: accumulated depreciation, depletion and amortization	(436,642,215)	(421,165,400)
Net oil and gas properties	67,497,525	79,845,503
OTHER PROPERTY AND EQUIPMENT:
Assets held for sale	1,691,588	0
Land, buildings and improvements	0	1,600,000
Other property and equipment	1,793,397	2,845,459
Total	3,484,985	4,445,459
Less: accumulated depreciation and amortization	(1,355,639)	(1,409,535)
Net other property and equipment	2,129,346	3,035,924
OTHER ASSETS AND DEFERRED CHARGES:
Commodity derivative instruments	13,028	0
Deposits	467,592	467,592
Other noncurrent assets	79,997	270,842
Total other assets and deferred charges	560,617	738,434
TOTAL ASSETS	77,361,105	90,635,950
CURRENT LIABILITIES:
Current maturities of debt	34,742,953	651,124
Accounts payable, principally trade	8,008,017	11,931,218
Commodity derivative instruments	0	903,003
Asset retirement obligations	128,539	277,355
Other accrued liabilities	1,275,473	2,295,438
Total current liabilities	44,154,982	16,058,138
LONG-TERM DEBT	0	27,700,000
OTHER NONCURRENT LIABILITIES:
Asset retirement obligations	11,143,320	10,189,058
Commodity derivative instruments	0	336,406
Deferred rent	250,891	290,566
Employee stock awards	40,153	191,110
Total other noncurrent liabilities	11,434,364	11,007,140
COMMITMENTS AND CONTINGENCIES (Notes 2 and 19)
EQUITY:
Series D convertible preferred stock ($0.001 par value, 7,000,000 authorized, 2,041,240 issued and outstanding as of December 31, 2018, and 1,904,391 issued and outstanding as of December 31, 2017)	2,041	1,904
Common stock ($0.001 par value, 100 million shares authorized, 23,240,833 outstanding as of December 31, 2018 and 22,661,758 outstanding as of December 31, 2017)	23,241	22,662
Additional paid-in capital	58,449,149	55,064,685
Treasury stock at cost (380,525 shares as of December 31, 2018 and 13,343 shares as of December 31, 2017)	(439,099)	(25,278)
Accumulated earnings (deficit)	(36,263,573)	(19,193,301)
Total equity	21,771,759	35,870,672
TOTAL LIABILITIES AND EQUITY	$ 77,361,105	$ 90,635,950

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) - $ / shares	Dec. 31, 2018	Dec. 31, 2017
Statement of Financial Position [Abstract]
Preferred stock, par value	$ 0.001	$ 0.001
Preferred stock, authorized	7,000,000	7,000,000
Preferred stock, issued	2,041,240	1,904,391
Preferred stock, outstanding	2,041,240	1,904,391
Common stock, par value	$ .001	$ 0.001
Common stock, authorized	100,000,000	100,000,000
Common stock, outstanding	23,240,833	22,661,758
Treasury stock	380,525	13,343

CONSOLIDATED STATEMENTS OF OPER

CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
REVENUES:
Sales of natural gas and crude oil	$ 21,471,093	$ 25,443,601
EXPENSES:
Lease operating and production costs	10,561,464	11,037,313
General and administrative - stock-based compensation	582,344	2,381,365
General and administrative - other	6,138,330	6,934,381
Deposit forfeiture	(275,000)	0
Depreciation, depletion and amortization	8,539,554	10,955,203
Asset retirement obligation accretion expense	560,922	557,683
Impairment of oil and gas properties	7,049,216	0
Impairment of other property and equipment	794,623	0
Bad debt expense	433,769	335,567
Total expenses	34,385,222	32,201,512
LOSS FROM OPERATIONS	(12,914,129)	(6,757,911)
OTHER INCOME (EXPENSE):
Net gains (losses) from commodity derivatives	(415,708)	2,554,934
Interest expense	(2,313,654)	(1,734,807)
Gain (loss) on other property and equipment	0	484,768
Other, net	88,702	60,248
Total other income (expense)	(2,640,660)	1,365,143
LOSS BEFORE INCOME TAXES	(15,554,789)	(5,392,768)
Income tax expense - deferred	0	0
NET LOSS	(15,554,789)	(5,392,768)
PREFERRED STOCK:
Dividends paid in kind	1,515,483	1,413,865
NET LOSS ATTRIBUTABLE TO COMMON STOCKHOLDERS	$ (17,070,272)	$ (6,806,633)
LOSS PER COMMON SHARE:
Basic	$ (0.74)	$ (0.46)
Diluted	$ (0.74)	$ (0.46)
WEIGHTED AVERAGE NUMBER OF COMMON SHARES OUTSTANDING:
Basic	23,023,066	14,815,991
Diluted	23,023,066	14,815,991

CONSOLIDATED STATEMENTS OF CHAN

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY - USD ($)	Preferred Stock	Common Stock	Paid-in-Capital	Treasury Stock	Accumulated Deficit	Total
Beginning Balance, Amount at Dec. 31, 2016	$ 1,777	$ 12,202	$ 43,877,563	$ 0	$ (12,386,668)	$ 31,504,874
Beginning Balance, Shares at Dec. 31, 2016	1,776,718	12,201,884
Net loss					(5,392,768)	(5,392,768)
Payment of Series "D" dividends in kind, Amount	$ 127		1,413,738		(1,413,865)
Payment of Series "D" dividends in kind, Shares	127,673
Public offering proceeds net of $1.4 million costs, Amount		$ 10,100	8,737,447			8,747,547
Public offering proceeds net of $1.4 million costs, Shares		10,100,000
Stock awards vested, Amount		$ 33	(33)
Stock awards vested, Shares		32,596
Restricted stock awards issued, Amount		$ 329	(329)
Restricted stock awards issued, Shares		329,491
Restricted stock awards forfeited, Amount		$ (2)	2
Restricted stock awards forfeited, Shares		(2,213)
Treasury stock (surrendered to settle employee tax liabilities)				(25,278)		(25,278)
Stock-based compensation			1,036,297			1,036,297
Ending Balance, Amount at Dec. 31, 2017	$ 1,904	$ 22,662	55,064,685	(25,278)	(19,193,301)	35,870,672
Ending Balance, Shares at Dec. 31, 2017	1,904,391	22,661,758
Net loss					(15,554,789)	(15,554,789)
Payment of Series "D" dividends in kind, Amount	$ 137		1,515,346		(1,515,483)	0
Payment of Series "D" dividends in kind, Shares	136,849
Stock awards vested, Amount		$ 963	(963)			0
Stock awards vested, Shares		963,313
Restricted stock awards forfeited, Amount		$ (17)	17			0
Restricted stock awards forfeited, Shares		(17,056)
Restricted stock awards repurchased, Amount		$ (367)	367			0
Restricted stock awards repurchased, Shares		(367,182)
Stock-based compensation			1,869,697			1,869,697
Treasury stock (surrendered to settle employee tax liabilities)				(413,821)		(413,821)
Ending Balance, Amount at Dec. 31, 2018	$ 2,041	$ 23,241	$ 58,449,149	$ (439,099)	$ (36,263,573)	$ 21,771,759
Ending Balance, Shares at Dec. 31, 2018	2,041,240	23,240,833

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Reconciliation of net income (loss) to net cash provided by (used in) operating activities
Net income (loss)	$ (15,554,789)	$ (5,392,768)
Depreciation, depletion and amortization of property and equipment	8,539,554	10,955,203
Impairment of oil and gas properties	7,049,216	0
Impairment of other property and equipment	794,623	0
Amortization of debt issuance costs	416,650	363,485
Deferred rent liability, net	10,771	279,795
Stock-based compensation	582,344	2,381,365
Settlement of asset retirement obligations	(590,709)	(1,045,257)
Accretion of asset retirement obligation	560,922	557,683
Bad debt expense	433,769	335,567
Net gains (losses) from commodity derivatives	415,708	(2,554,934)
(Gain) loss on sales of fixed assets	0	(556,141)
Loss on write-off of abandoned facilities	0	71,373
(Gain) loss on write-off of liabilities net of assets	(113,225)	(58,994)
Changes in assets and liabilities:
Decrease in accounts receivable	1,354,652	285,051
Decrease in prepaids, deposits and other assets	(256,962)	86,670
Decrease in accounts payable and other current and non-current liabilities	176,648	(2,462,040)
NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES	3,819,172	3,246,058
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures on property and equipment	(8,189,465)	(10,704,535)
Proceeds from sale of oil and gas properties	2,372,767	5,400,563
Proceeds from sale of other fixed assets	0	645,791
Derivative settlements	(2,419,303)	1,238,341
NET CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES	(8,236,001)	(3,419,840)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings on senior credit facility	14,300,000	13,275,000
Repayment of borrowings on senior credit facility	(8,000,000)	(25,075,000)
Proceeds from borrowings - insurance financing	902,357	763,244
Repayments of borrowings - insurance financing	(810,528)	(711,461)
Debt issuance costs	0	(353,593)
Net proceeds (expenses) from common stock offering	(64,050)	8,812,547
Treasury stock repurchases	(413,821)	(25,278)
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES	5,913,958	(3,314,541)
NET CHANGE IN CASH AND CASH EQUIVALENTS	1,497,129	(3,488,323)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD	137,363	3,625,686
CASH AND CASH EQUIVALENTS AT END OF PERIOD	1,634,492	137,363
Supplemental disclosure of cash flow information:
Interest payments (net of interest capitalized)	1,685,709	1,369,353
Interest capitalized	133,772	317,691
Income tax refund	0	20,699
Supplemental disclosure of significant non-cash activity:
(Increase) decrease in capital expenditures financed by accounts payable	$ 4,026,996	$ (2,608,232)

ORGANIZATION AND BASIS OF PRESE

ORGANIZATION AND BASIS OF PRESENTATION	12 Months Ended
	Dec. 31, 2018
Organization, Consolidation and Presentation of Financial Statements [Abstract]
ORGANIZATION AND BASIS OF PRESENTATION	Yuma Energy, Inc., a Delaware corporation (“YEI” and collectively with its subsidiaries, the “Company”), is an independent Houston-based exploration and production company focused on acquiring, developing and exploring for conventional and unconventional oil and natural gas resources. Historically, the Company’s operations have focused on onshore properties located in central and southern Louisiana and southeastern Texas where it has a long history of drilling, developing and producing both oil and natural gas assets. In 2017, it acquired acreage in Yoakum County, Texas, with plans to explore and develop additional oil and natural gas assets in the Permian Basin of west Texas. Finally, the Company has operated positions in Kern County, California, and non-operated positions in the East Texas Woodbine. Basis of Presentation The accompanying financial statements include the accounts of YEI on a consolidated basis. All significant intercompany accounts and transactions between YEI and its wholly owned subsidiaries have been eliminated in the consolidation. YEI and its subsidiaries maintain their accounts on the accrual method of accounting in accordance with the Generally Accepted Accounting Principles of the United States of America (“GAAP”). Each of YEI and its subsidiaries has a fiscal year ending December 31. See Note 2 – Liquidity and Going Concern for further discussion about basis of presentation and accounting. The Consolidation YEI has 10 subsidiaries as listed below. Their financial statements are consolidated with those of YEI. State of Date of Company Name Reference Incorporation Incorporation The Yuma Companies, Inc. “YCI” Delaware 10/30/1996 Yuma Exploration and Production Company, Inc. “Exploration” Delaware 01/16/1992 Davis Petroleum Acquisition Corp. “DPAC” Delaware 01/18/2006 Davis Petroleum Pipeline LLC “DPP” Delaware 11/15/1999 Davis GOM Holdings, LLC “Davis GOM” Delaware 07/25/2014 Davis Petroleum Corp. “DPC” Delaware 07/08/1986 Yuma Petroleum Company “Petroleum” Delaware 12/19/1991 Texas Southeastern Gas Marketing Company “TSM” Texas 09/12/1996 Pyramid Oil LLC “POL” California 08/08/2014 YCI, PDMS and DPAC are wholly owned subsidiaries of YEI, and YCI is the parent corporation of Exploration, Petroleum and TSM. Exploration is the parent corporation of POL. Exploration and DPC are the Company’s two main operating companies. DPAC was formed for the purpose of acquiring equity interests of DPC and DPP. Petroleum has been inactive since 1998 due to the transfer of substantially all exploration and production activities to Exploration. TSM was primarily engaged in the marketing of natural gas in Louisiana. Since October 26, 2016 (the date of the Reincorporation Merger and the Davis Merger), TSM has been dormant due to the fact that it no longer markets natural gas volumes. POL is primarily engaged in holding assets located in the State of California. Davis GOM has been inactive since 2017.

LIQUIDITY AND GOING CONCERN

LIQUIDITY AND GOING CONCERN	12 Months Ended
	Dec. 31, 2018
Liquidity And Going Concern
LIQUIDITY AND GOING CONCERN	The factors and uncertainties described below, as well as other factors which include, but are not limited to, declines in the Company’s production, the Company’s failure to establish commercial production on our Permian properties, no available capital to maintain and develop our properties, and its substantial working capital deficit of approximately $37.0 million, raise substantial doubt about the Company’s ability to continue as a going concern. The Consolidated Financial Statements have been prepared on a going concern basis of accounting, which contemplates continuity of operations, realization of assets, and satisfaction of liabilities and commitments in the normal course of business. The Consolidated Financial Statements do not include any adjustments that might result from the outcome of the going concern uncertainty. On October 26, 2016, the Company and three of its subsidiaries, as the co-borrowers, entered into a credit agreement providing for a $75.0 million three-year senior secured revolving credit facility (the “Credit Agreement”) with Société Générale (“SocGen”), as administrative agent, SG Americas Securities, LLC, as lead arranger and bookrunner, and the lenders signatory thereto (collectively with SocGen, the “Lender”). The borrowing base of the credit facility was $34.0 million as of December 31, 2018, and the Company was and is fully drawn under the credit facility leaving no availability on the line of credit. All of the obligations under the Credit Agreement, and the guarantees of those obligations, are secured by substantially all of the Company’s assets. The Credit Agreement contains a number of covenants that, among other things, restrict, subject to certain exceptions, the Company’s ability to incur additional indebtedness, create liens on assets, make investments, enter into sale and leaseback transactions, pay dividends and distributions or repurchase its capital stock, engage in mergers or consolidations, sell certain assets, sell or discount any notes receivable or accounts receivable, and engage in certain transactions with affiliates. The Credit Agreement contains customary financial and affirmative covenants and defines events of default for credit facilities of this type, including failure to pay principal or interest, breach of covenants, breach of representations and warranties, insolvency, judgment default, and a change of control. Upon the occurrence and continuance of an event of default, the Lender has the right to accelerate repayment of the loans and exercise its remedies with respect to the collateral. At December 31, 2018, the Company was not in compliance under the credit facility with its (i) total debt to EBITDAX covenant for the trailing four quarter period, (ii) current ratio covenant, (iii) EBITDAX to interest expense covenant for the trailing four quarter period, (iv) the liquidity covenant requiring the Company to maintain unrestricted cash and borrowing base availability of at least $4.0 million, and (v) obligation to make an interest only payment for the quarter ended December 31, 2018. In addition, the Company currently is not making payments of interest under the credit facility and anticipate future non-compliance under the credit facility going forward. Due to this non-compliance, as well as the credit facility maturity in 2019, the Company classified its entire bank debt as a current liability in its financial statements as of December 31, 2018. On October 9, 2018, the Company received a notice and reservation of rights from the administrative agent under the Credit Agreement advising that an event of default had occurred and continues to exist by reason of the Company’s noncompliance with the liquidity covenant requiring us to maintain cash and cash equivalents and borrowing base availability of at least $4.0 million. As a result of the default, the Lender may accelerate the outstanding balance under the Credit Agreement, increase the applicable interest rate by 2.0% per annum or commence foreclosure on the collateral securing the loans. As of the date of this report, the Lender has not accelerated the outstanding amount due and payable on the loans, increased the applicable interest rate or commenced foreclosure proceedings, but may exercise one or more of these remedies in the future. As required under the Credit Agreement, the Company previously entered into hedging arrangements with SocGen and BP Energy Company (“BP”) pursuant to International Swaps and Derivatives Association Master Agreements (“ISDA Agreements”). On March 14, 2019, the Company received a notice of an event of default under its ISDA Agreement with SocGen (the “SocGen ISDA”). Due to the default under the ISDA Agreement, SocGen unwound all of the Company’s hedges with them. The notice provides for a payment of approximately $347,129 to settle the Company’s outstanding obligations thereunder related to SocGen’s hedges (of which $-0- is included in accounts payable at December 31, 2018). On March 19, 2019, the Company received a notice of an event of default under its ISDA Agreement with BP (the “BP ISDA”). Due to the default under the ISDA Agreement, BP also unwound all of the Company’s hedges with them. The notice provides for a payment of approximately $775,725 to settle the Company’s outstanding obligations thereunder related to BP’s hedges (of which $-0- is included in accounts payable at December 31, 2018). The Company has initiated several strategic alternatives to mitigate its limited liquidity (defined as cash on hand and undrawn borrowing base), its financial covenant compliance issues, and to provide it with additional working capital to develop its existing assets. During the first quarter of 2019, the Company agreed to sell its Kern County, California properties for $2.1 million in gross proceeds and the buyer’s assumption of certain plugging and abandonment liabilities of approximately $864,000, and received a non-refundable deposit of $150,000. As additional consideration for the sale of the assets, if WTI Index for oil equals or exceeds $65 in six months following closing and maintains that average for twelve consecutive months then Buyer shall pay to the seller $250,000. Upon closing, the Company anticipates that the proceeds will be applied to the repayment of borrowings under the credit facility and/or working capital; however, there can be no assurance that the transaction will close. On August 20, 2018, the Company sold its 3.1% leasehold interest consisting of 9.8 net acres in one section in Eddy County, New Mexico for $127,400. On October 23, 2018, the Company sold substantially all of its Bakken assets in North Dakota for approximately $1.16 million in gross proceeds and the buyer’s assumption of certain plugging and abandonment liabilities of approximately $15,200. The Bakken assets represent approximately 12 barrels of oil equivalent per day of the Company’s production in the third quarter. On October 24, 2018, the Company sold certain deep rights in undeveloped acreage located in Grady County, Oklahoma for approximately $120,000. Proceeds of $1.0 million from these non-core asset sales were applied to the repayment of borrowings under the credit facility in October 2018. The Company continues to reduce personnel, consultants, and other non-essential services in an effort to reduce its general and administrative costs, as well as curtailing its capital expenditures planned for 2019. On October 22, 2018, the Company retained Seaport Global Securities LLC, an investment banking firm, to advise the Company on its strategic and tactical alternatives, including possible acquisitions and divestitures. The Company plans to take further steps to mitigate its limited liquidity, which may include, but are not limited to, further reducing or eliminating capital expenditures; selling additional assets; further reducing general and administrative expenses; seeking merger and acquisition related opportunities; and potentially raising proceeds from capital markets transactions, including the sale of debt or equity securities. There can be no assurance that the exploration of strategic alternatives will result in a transaction or otherwise improve the Company’s limited liquidity and that the Company will continue as a going concern.

SUMMARY OF SIGNIFICANT ACCOUNTI

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	12 Months Ended
	Dec. 31, 2018
Accounting Policies [Abstract]
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	Management’s Use of Estimates In preparing financial statements in conformity with GAAP, management is required to make informed estimates and assumptions with consideration given to materiality. These estimates and assumptions 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 for the reporting period. Actual results could differ from these estimates, and changes in these estimates are recorded when known. Significant items subject to such estimates and assumptions include: estimates of proved reserves and related estimates of the present value of future cash flows associated with oil and gas properties; the carrying value of oil and gas properties; estimates of fair value; asset retirement obligations; income taxes; derivative financial instruments; valuation allowances for deferred tax assets; uncollectible receivables; useful lives for depreciation; obligations related to employee benefits such as accrued vacation; and legal and environmental risks and exposures. Fair Value Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The standard characterizes inputs used in determining fair value according to a hierarchy that prioritizes inputs based upon the degree to which they are observable. The three levels of the fair value hierarchy are as follows: Level 1 – inputs represent quoted prices in active markets for identical assets or liabilities (for example, exchange-traded commodity derivatives). Level 2 – inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly (for example, quoted market prices for similar assets or liabilities in active markets or quoted market prices for identical assets or liabilities in markets not considered to be active, inputs other than quoted prices that are observable for the asset or liability, or market-corroborated inputs). Level 3 – inputs that are not observable from objective sources, such as the Company’s internally developed assumptions about market participant assumptions used in pricing an asset or liability (for example, an estimate of future cash flows used in the Company’s internally developed present value of future cash flows model that underlies the fair value measurement). In determining fair value, the Company utilizes observable market data when available, or models that utilize observable market data. In addition to market information, the Company incorporates transaction-specific details that, in management’s judgment, market participants would take into account in measuring fair value. If the inputs used to measure the financial assets and liabilities fall within more than one level described above, the category is based on the lowest level input that is significant to the fair value measurement of the instrument (see Note 11 – Fair Value Measurements). The carrying amount of cash and cash equivalents, accounts receivable and accounts payable reported on the Consolidated Balance Sheets approximates fair value due to their short-term nature. The fair value of debt is estimated as the carrying amount of the Company’s credit facility (see Note 11 – Fair Value Measurements). Nonfinancial assets and liabilities initially measured at fair value include certain assets acquired in a business combination, asset retirement obligations and exit or disposal costs. Assets Held for Sale – the fair values of property, plant and equipment, classified as assets held for sale and related impairments are calculated using Level 3 inputs. Cash Equivalents Cash on hand, deposits in banks and short-term investments with original maturities of three months or less are considered cash and cash equivalents. Trade Receivables The Company’s accounts receivable are primarily receivables from joint interest owners and oil and natural gas purchasers. Accounts receivable are recorded at the amount due, less an allowance for doubtful accounts, when applicable. The Company establishes provisions for losses on accounts receivable if it determines that collection of all or part of the outstanding balance is doubtful. The Company regularly reviews collectability and establishes or adjusts the allowance for doubtful accounts as necessary using the specific identification method. Accounts receivable are stated net of allowance for doubtful accounts of $621,006 and $934,338 at December 31, 2018 and 2017, respectively. Management evaluates accounts receivable quarterly on an individual account basis, making individual assessments of collectability, and reserves those amounts it deems potentially uncollectible. Derivative Instruments The Company periodically enters into derivative contracts to hedge future crude oil and natural gas production in order to mitigate the risk of market price fluctuations. All derivatives are recognized on the balance sheet and measured at fair value. The Company does not designate its derivative contracts as hedges, as defined in ASC 815, Derivatives and Hedging Oil and Natural Gas Properties Oil and natural gas properties are accounted for using the full cost method of accounting, under which all productive and nonproductive costs directly associated with property acquisition, exploration and development activities are capitalized. Costs of reconditioning, repairing, or reworking producing properties are expensed as incurred. Costs of workovers adding proved reserves are capitalized. Projects to deepen existing wells, recomplete to a shallower horizon, or improve (not restore) production to proved reserves are capitalized. Sales of proved and unproved properties are accounted for as adjustments of capitalized costs with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves. Abandonments of properties are accounted for as adjustments of capitalized costs with no loss or gain recognized. Depreciation, Depletion and Amortization (“DD&A”) Impairments Unproved oil and natural gas properties not subject to amortization consist of undeveloped leaseholds, wells in progress and related capitalized interest. Management reviews the costs of these properties quarterly to determine whether and to what extent developed proved reserves have been assigned to the properties, or if an impairment has occurred, in which case the related costs, along with associated capitalized interest, are reclassified to proved properties subject to amortization. Factors considered by management in impairment assessments include drilling results by the Company and other operators, the terms of oil and gas leases not held by production, the intent to drill the project or prospect in the future, the economic viability of the development of the project or prospect, the technical evaluation of the project or prospect, as well as the available funds for exploration and development. Capitalized Interest Capitalized Internal Costs The Company develops oil and natural gas drilling projects called “prospects” by industry participants and markets participation in these projects. The Company also assembles 3-D seismic survey projects and markets participating interests in the projects. The proceeds from the sale of the 3-D seismic survey along with the quarterly G&A reimbursements are included in unproved oil and natural gas properties not subject to amortization. Other Property and Equipment Other property and equipment is generally recorded at cost. Expenditures for major additions and improvements are capitalized, while maintenance, repairs and minor replacements which do not improve or extend the life of such assets are charged to operations as incurred. Depreciation and amortization is calculated using the straight-line method over the estimated useful lives of the respective assets. Property and equipment sold, retired or otherwise disposed of are removed at cost less accumulated depreciation, and any resulting gain or loss is reflected in “Other” in “Other income (expense)” in the accompanying Consolidated Statements of Operations. In the event that facts and circumstances indicate that the carrying value of other property and equipment may be impaired, an evaluation of recoverability is performed. If an evaluation is required, the estimated future undiscounted cash flows associated with the asset are compared to the asset’s carrying amount to determine if a write-down to market value (measured using discounted cash flows) is required. Assets Held for Sale – The fair values of property, plant and equipment, classified as assets held for sale, are included in Other Property and Equipment. During the year, the Company recorded an impairment of $794,623 related to the write-down of the Company’s assets held for sale to the lower of carrying value and fair value less the cost to sell. Accounts Payable Accounts payable consist principally of trade payables and costs associated with oil and natural gas activities. Commitments and Contingencies Liabilities for loss contingencies arising from claims, assessments, litigation or other sources, along with liabilities for environmental remediation or restoration claims, are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated. Expenditures related to environmental matters are expensed or capitalized in accordance with the Company’s accounting policy for property and equipment. Revenue Recognition – Adoption of ASC 606, “Revenue from Contracts with Customers” The Company recognizes revenues to depict the transfer of control of promised goods or services to its customers in an amount that reflects the consideration to which it expects to be entitled to in exchange for those goods or services. On January 1, 2018, the Company adopted Accounting Standards Codification (“ASC”) 606 using the full retrospective method applied to those contracts which were not completed as of December 31, 2016. As a result of electing the full retrospective adoption approach as described above, results for reporting periods beginning after December 31, 2016 are presented under ASC 606. There was no material impact upon the adoption of ASC 606, and the Company did not record any adjustments to opening retained earnings as of January 1, 2017, because its revenue is primarily products sales revenue accounted for at a point in time. Crude oil and condensate are sold through month-to-month evergreen contracts. The price for Louisiana production is tied to an index or a weighted monthly average of posted prices with certain adjustments for gravity, Basic Sediment and Water (“BS&W”) and transportation. Generally, the index or posting is based on customary industry spot prices. Pricing for the Company’s California properties is based on an average of specified posted prices, adjusted for gravity and transportation. The Company’s natural gas is sold under month-to-month contracts with pricing tied to either first of the month index or a monthly weighted average of purchaser prices received. Natural gas liquids are sold under month-to-month or year-to-year contracts usually tied to the related natural gas contract. Pricing is based on published prices for each product or a monthly weighted average of purchaser prices received. Sales of crude oil, condensates, natural gas and natural gas liquids (“NGLs”) are recognized at the point control of the product is transferred to the customer. Virtually all of the Company’s contracts’ pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality of the oil or natural gas, and prevailing supply and demand conditions. As a result, the price of the crude oil, condensate, natural gas, and NGLs fluctuates to remain competitive with other available crude oil, natural gas, and NGLs supplies. Revenue is measured based on consideration specified in the contract with the customer, and excludes any amounts collected on behalf of third parties. The Company recognizes revenue in the amount that reflects the consideration it expects to be entitled to in exchange for transferring control of those goods to the customer. The contract consideration in the Company’s variable price contracts is typically allocated to specific performance obligations in the contract according to the price stated in the contract. Amounts allocated in the Company’s fixed price contracts are based on the stand-alone selling price of those products in the context of long-term, fixed price contracts, which generally approximates the contract price. The Company records revenue in the month production is delivered to the purchaser. However, settlement statements for certain natural gas and NGL sales may not be received for 30 to 90 days after the date production is delivered, and as a result, the Company is required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. The Company records the differences between its estimates and the actual amounts received for product sales in the month that payment is received from the purchaser. Any identified differences between its revenue estimates and actual revenue received historically have not been significant. For the year ended December 31, 2017 and the year ended December 31, 2018, revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material. Gain or loss on derivative instruments is outside the scope of ASC 606 and is not considered revenue from contracts with customers subject to ASC 606. The Company may use financial or physical contracts accounted for as derivatives as economic hedges to manage price risk associated with normal sales, or in limited cases may use them for contracts the Company intends to physically settle but do not meet all of the criteria to be treated as normal sales. Natural Gas and Natural Gas Liquids Sales Under the Company’s natural gas processing contracts, it delivers natural gas to a midstream processing entity at the wellhead or the inlet of the midstream processing entity’s system. The midstream processing entity gathers and processes the natural gas and remits proceeds to the Company for the resulting sales of NGLs and residue gas. In these scenarios, the Company evaluates whether it is the principal or the agent in the transaction. For those contracts where the Company has concluded it is the principal and the ultimate third party is its customer, the Company recognizes revenue on a gross basis, with transportation, gathering, processing and compression fees presented as an expense in its lease operating and production costs in the Consolidated Statements of Operations. In certain natural gas processing agreements, the Company may elect to take its residue gas and/or NGLs in-kind at the tailgate of the midstream entity’s processing plant and subsequently market the product. Through the marketing process, the Company delivers product to the ultimate third-party purchaser at a contractually agreed-upon delivery point and receives a specified index price from the purchaser. In this scenario, the Company recognizes revenue when control transfers to the purchaser at the delivery point based on the index price received from the purchaser. The gathering, processing and compression fees attributable to the gas processing contract, as well as any transportation fees incurred to deliver the product to the purchaser, are presented as lease operating and production costs in the Consolidated Statements of Operations. Crude Oil and Condensate Sales The Company sells oil production at the wellhead and collects an agreed-upon index price, net of pricing differentials. In this scenario, revenue is recognized when control transfers to the purchaser at the wellhead at the net price received. The following table presents the Company’s revenues disaggregated by product source. Sales taxes are excluded from revenues. Years Ended December 31, 2018 2017 Sales of natural gas and crude oil: Crude oil and condensate $ 11,565,706 $ 12,596,983 Natural gas 6,678,666 9,425,676 Natural gas liquids 3,226,721 3,420,942 Total revenues $ 21,471,093 $ 25,443,601 Transaction Price Allocated to Remaining Performance Obligations A significant number of the Company’s product sales are short-term in nature with a contract term of one year or less. For those contracts, the Company has utilized the practical expedient in ASC 606-10-50-14 exempting the Company from disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less. For the Company’s product sales that have a contract term greater than one year, it has utilized the practical expedient in ASC 606-10-50-14(a) which states that the Company is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under these sales contracts, each unit of product generally represents a separate performance obligation; therefore future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required. Contract Balances Receivables from contracts with customers are recorded when the right to consideration becomes unconditional, generally when control of the product has been transferred to the customer. Receivables from contracts with customers were $2,282,200 and $2,636,867 as of December 31, 2018 and December 31, 2017, respectively, and are reported in trade accounts receivable, net on the Consolidated Balance Sheets. The Company currently has no other assets or liabilities related to its revenue contracts, including no upfront or rights to deficiency payments. Practical Expedients The Company has made use of certain practical expedients in adopting ASC 606, including not disclosing the value of unsatisfied performance obligations for (i) contracts with an original expected length of one year or less, (ii) contracts for which the Company recognizes revenue at the amount to which the Company has the right to invoice, (iii) variable consideration which is allocated entirely to a wholly unsatisfied performance obligation and meets the variable allocation criteria in the standard and (iv) only contracts that are not completed at transition. The Company has not adjusted the promised amount of consideration for the effects of a significant financing component if the Company expects, at contract inception, that the period between when the Company transfers a promised good or service to the customer and when the customer pays for that good or service will be one year or less. Income Taxes The Company files a consolidated federal tax return. Deferred taxes have been provided for temporary timing differences. These differences create taxable or tax-deductible amounts for future periods. Income taxes are provided based on earnings reported for tax return purposes in addition to a provision for deferred income taxes. Deferred income taxes are provided to reflect the tax consequences in future years of differences between the financial statement and tax bases of assets and liabilities. A valuation allowance is established to reduce deferred tax assets if it is more likely-than-not that the related tax benefits will not be realized (see Note 18 – Income Taxes). Other Taxes The Company reports oil and natural gas sales on a gross basis and, accordingly, includes net production, severance, and ad valorem taxes on the accompanying Consolidated Statements of Operations as a component of lease operating expenses. The Company accrues sales tax on applicable purchases of materials, and remits funds directly to the taxing jurisdictions. General and Administrative Expenses – Stock-Based Compensation This includes payments to employees in the form of restricted stock awards, restricted stock units, stock appreciation rights and stock options. As such, these amounts are non-cash Company stock-based awards. The Company adopted the 2014 Long-Term Incentive Plan effective October 26, 2016, and adopted an Annual Incentive Plan for fiscal year 2017 . The Company adopted the 2018 Long-Term Incentive Plan effective June 7, 2018 (see Note 14 – Stock-Based Compensation). The Company grants both liability classified and equity-classified awards including stock options, stock appreciation rights, as well as vested and non-vested equity shares (restricted stock awards and units). The fair value of stock option awards and stock appreciation rights is determined using the Black-Scholes option-pricing model. Restricted stock awards and units are valued using the Company’s stock price on the grant date. The Company records compensation cost, net of estimated forfeitures, for non-vested stock units over the requisite service period using the straight-line method. An adjustment is made to compensation cost for any difference between the estimated forfeitures and the actual forfeitures related to the awards. For liability-classified share-based compensation awards, expense is recognized for those awards expected to ultimately be paid. The amount of expense reported for liability-classified awards is adjusted for fair-value changes so that the expense recognized for each award is equivalent to the amount to be paid (see Note 14 – Stock-Based Compensation). Other Noncurrent Assets Other noncurrent assets at December 31, 2018 are comprised of $79,997 related to the S-3 offering. In 2017, the balance included $254,894 of deferred debt issuance costs related to the establishment of the new Société Générale (“SocGen”) credit facility which expires on October 26, 2019, and S-3 offering costs of $15,948. Earnings per Share The Company’s basic earnings per share (“EPS”) is computed based on the weighted average number of shares of common stock outstanding for the period. Diluted EPS includes the effect of the Company’s outstanding stock awards, if the inclusion of these items is dilutive (see Note 15 – Net Income (Loss) per Common Share). Treasury Stock The Company records treasury stock purchases at cost. Amounts are recorded as reductions to stockholders’ equity. Shares of common stock are repurchased by the Company as they are surrendered by employees to pay withholding tax upon the vesting of restricted stock awards. Recently Issued Accounting Pronouncements The accounting standard-setting organizations frequently issue new or revised accounting rules. The Company regularly reviews new pronouncements to determine their impact, if any, on the financial statements. Accounting Pronouncement Yet to Be Adopted In February 2016, the FASB issued ASU 2016-02, Leases (ASC Topic 842). Under this guidance, lessees are required to recognize on the balance sheet a lease liability and a right-of-use asset for all leases, with the exception of short-term leases with terms of twelve months or less. The lease liability represents the lessee’s obligation to make lease payments arising from a lease, and will be measured as the present value of the lease payments. The right-of-use asset represents the lessee’s right to use a specified asset for the lease term, and will be measured at the lease liability amount, adjusted for lease prepayment, lease incentives received and the lessee’s initial direct costs. The new guidance is effective for fiscal years beginning after December 15, 2018. The Company plans to adopt this guidance in the first quarter of 2019 using the optional transition method. Consequently, the Company's reporting for the comparative periods presented in the financial statements will continue to be in accordance with ASC Topic 840, Leases. The adoption of this guidance will result in the addition of right-of-use assets and corresponding lease obligations to the consolidated balance sheet and will not have a material impact on the Company’s results of operations or cash flows. The Company has substantially completed its evaluation of the impact on the Company’s lease portfolio. ASU 2016-02 provides for certain practical expedients when adopting the guidance. The Company plans to elect the package of practical expedients allowing the Company to not reassess whether any expired or existing contracts are, or contain, leases, the lease classification for any expired or existing leases or initial direct costs for any expired or existing leases. The Company also plans to apply the hindsight practical expedient allowing the Company to use hindsight when determining the lease term (i.e., evaluating the Company’s option to renew or terminate the lease or to purchase the underlying asset) and assessing impairment of expired or existing leases. The Company additionally plans to apply the land easements practical expedient allowing the Company to not assess whether any expired or existing land easements are, or contain, leases if they were not previously accounted for as leases under the existing leasing guidance. Instead, it will continue to apply its existing accounting policies to historical land easements. The Company also elects to apply the short-term lease exception, therefore it will not record a right-of-use asset or corresponding lease liability for leases with a term of twelve months or less and instead recognize a single lease cost allocated over the lease term, generally on a straight-line basis. The Company plans to elect the practical expedient to not separate lease components from non-lease components and instead account for both as a single lease component for all asset classes. As part of the Company’s assessment, it formed an implementation work team, conducted training for the relevant staff regarding the potential impacts of Topic 842 and has concluded its contract analyses and policy review. The Company engaged external resources to assist in its efforts to complete the analysis of potential changes to current accounting practices and is in the process of implementing a new lease accounting system in connection with the adoption of the updated guidance. The Company also evaluated the impact of Topic 842 on its internal control over financial reporting and other changes in business practices and processes. The Company is in the process of finalizing its catalog of existing lease contracts and implementing changes to its systems. Upon adoption, the Company expects to record operating lease right-of-use assets of approximately $4.1 million representing the present value of future lease payments under operating leases with terms of greater than twelve months. The Company is continuing to evaluate the impact the pronouncement will have on the related disclosures. Accounting Pronouncements Recently Adopted In August 2016, the FASB issued ASU 2016-15, “Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments,” which provides clarification on how certain cash receipts and cash payments are presented and classified on the statement of cash flows. This ASU is effective for annual and interim periods beginning after December 15, 2017 and is required to be adopted using a retrospective approach if practicable, with early adoption permitted. The Company adopted this update, as required, beginning in the first quarter of 2018, and the adoption did not have a material impact on its consolidated financial statements. In January 2017, the FASB issued ASU 2017-01, “Business Combinations (Topic 805): Clarifying the Definition of a Business,” which assists in determining whether a transaction should be accounted for as an acquisition or disposal of assets or as a business. This ASU is effective for annual and interim periods beginning in 2018 and is required to be adopted using a prospective approach, with early adoption permitted for transactions not previously reported in issued financial statements. The Company adopted this ASU on January 1, 2017, and expects that the adoption of this ASU could have a material impact on future consolidated financial statements, as future oil and gas asset acquisitions may not be considered businesses. In March 2016, the FASB issued ASU 2016-09, “Compensation—Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting,” In May 2014, the FASB issued ASU 2014 09 “Revenue from Contracts with Customers” (Topic 606) (ASC 606, as subsequently amended). ASC 606 supersedes the revenue recognition requirements in topic 605, Revenue Recognition, and requires entities to recognize revenue when control of the promised goods or services is transferred to customers at an amount that reflects the consideration to which an entity expects to be entitled to in exchange for those goods or services. The Company adopted ASC 606 with an effective date of January 2018 using the full retrospective approach. For public entities, ASC 606 became effective for fiscal years beginning after December 15, 2017. The adoption of this standard did not have a material effect on the Company’s consolidated results of operations, financial position or cash flows.

PREPAYMENTS

PREPAYMENTS	12 Months Ended
	Dec. 31, 2018
Prepaid Expense and Other Assets [Abstract]
PREPAYMENTS	At December 31, prepayments consisted of the following: December 31, 2018 2017 Prepaid insurance $ 1,009,216 $ 828,648 Prepaid taxes 1,394 28,158 Other prepayments 141,516 119,656 Total prepayments $ 1,152,126 $ 976,462

ACQUISITIONS AND DIVESTMENTS

ACQUISITIONS AND DIVESTMENTS	12 Months Ended
	Dec. 31, 2018
Business Combinations [Abstract]
ACQUISITIONS AND DIVESTMENTS	Divestments During 2018, the Company made the following divestments: ● Eddy County, New Mexico – The Company sold its 3.1% leasehold interest consisting of 9.8 net acres in one section for $127,400. ● Bakken – the Company sold substantially all of its Bakken assets in North Dakota for approximately $1.16 million in gross proceeds and the buyer’s assumption of certain plugging and abandonment liabilities of approximately $15,200. The Bakken assets represent approximately 12 barrels of oil equivalent per day of the Company’s production. ● Grady County, Oklahoma – The Company sold certain deep rights in undeveloped acreage located in Grady County, Oklahoma for approximately $120,000. During 2017, the Company made the following divestments: ● El Halcón – The Company sold certain oil and natural gas properties for $5.5 million gross located in Brazos County, Texas known as the El Halcón property. The El Halcón property consisted of an average working interest of approximately 8.5% (1,557 net acres). ● Cat Canyon – In May 2017, the Company sold all of its interest in 149 acres located in Santa Barbara County, California, to Texican Energy Corporation for $165,000, along with the assumption of plugging and abandonment obligations for three of four wells on the property. ● Mario – In December 2017, the Company sold a 12.5% working interest in ten sections of the project in Yoakum County, Texas, known as Mario, for $500,000, which is recorded at December 31, 2017 in “Other receivables” in the accompanying Consolidated Balance Sheets.

ASSET IMPAIRMENTS

ASSET IMPAIRMENTS	12 Months Ended
	Dec. 31, 2018
Asset Impairments
ASSET IMPAIRMENTS	Capitalized costs (net of accumulated DD&A and deferred income taxes) of proved oil and natural gas properties subject to amortization are subject to a full cost ceiling limitation. The ceiling limits these costs to an amount equal to the present value, discounted at 10%, of estimated future net cash flows from estimated proved reserves and estimated related future income taxes. The oil and natural gas prices used to calculate the full cost ceiling at December 31, 2018 were $65.56/Bbl for oil and $3.10/MMBtu for natural gas. In accordance with SEC rules, these prices are the 12-month average prices, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period, unless prices are defined by contractual arrangements. Prices are adjusted for “basis” or location differentials. Prices are held constant over the life of the reserves. If unamortized costs capitalized within the cost pool exceed the ceiling, the excess is charged to expense and separately disclosed during the period in which the excess occurs. During the year ended December 31, 2018, the Company recorded a full cost ceiling impairment $7.05 million due primarily to the Company writing off its PUD reserves during the year because development of such reserves is highly uncertain given the Company's severe liquidity constraints. No impairment was recorded during the year ended December 31, 2017.

PROPERTY, PLANT, AND EQUIPMENT,

PROPERTY, PLANT, AND EQUIPMENT, NET	12 Months Ended
	Dec. 31, 2018
Property, Plant and Equipment, Net [Abstract]
PROPERTY, PLANT, AND EQUIPMENT, NET	Oil and Gas Properties The following table sets forth the capitalized costs and associated accumulated depreciation, depletion and amortization (including impairments), relating to the Company’s oil and natural gas properties at December 31: December 31, 2018 2017 Subject to amortization (proved properties) $ 504,139,740 $ 494,216,531 Less: Accumulated depreciation, depletion, and amortization (436,642,215 ) (421,165,400 ) Proved properties, net $ 67,497,525 $ 73,051,131 Not subject to amortization (unproved properties) Leasehold acquisition costs - 3,133,162 Exploration and development - 3,368,339 Capitalized Interest - 292,871 Total unproved properties - 6,794,372 Oil and gas properties, net $ 67,497,525 $ 79,845,503 Unproved properties not subject to amortization Costs not being amortized are transferred to the Company’s proved properties subject to amortization as its drilling program is executed or costs are evaluated and deemed impaired. During 2018, the Company moved all of its unproved properties to the full cost pool. A summary of the Company’s reported value of unproved properties not subject to amortization by year incurred is as follows: Year Incurred 2018 2017 and prior Leasehold acquisition costs $ - $ 3,133,162 Exploration and development - 3,368,339 Capitalized interest - 292,871 Total $ - $ 6,794,372 Other Other property and equipment consists of the following: Assets Held for Sale – The fair values of property, plant and equipment classified as assets held for sale are $1,691,588. Estimated useful December 31, life in years 2018 2017 Land n/a $ - $ 1,314,000 Software and IT equipment 3 - 5 979,389 979,389 Drilling and operating equipment 15 - 837,013 Furniture and fixtures 7 - 10 704,758 712,692 Buildings 25 - 286,000 Automobiles 3 - 7 24,990 232,105 Office leasehold improvements 10 84,260 84,260 Total other property and equipment 1,793,397 4,445,459 Less: Accumulated depreciation and leasehold improvement amortization (1,355,639 ) (1,409,535 Net book value $ 437,758 $ 3,035,924 Depreciation and leasehold improvement amortization expense related to other property and equipment outside of oil and natural gas properties totaled $111,955 and $230,236 for the years ended December 31, 2018 and 2017, respectively, and is included on the Consolidated Statements of Operations in Depreciation, depletion and amortization.

ASSET RETIREMENT OBLIGATIONS

ASSET RETIREMENT OBLIGATIONS	12 Months Ended
	Dec. 31, 2018
Asset Retirement Obligation Disclosure [Abstract]
ASSET RETIREMENT OBLIGATIONS	The Company’s asset retirement obligations (“AROs”) represent the present value of the estimated cash flows expected to be incurred to plug, abandon and remediate producing properties, excluding salvage values, at the end of their productive lives in accordance with applicable laws. Revisions in estimated liabilities during the period relate primarily to changes in estimates of timing. Revisions in estimated liabilities can also include, but are not limited to, revisions of estimated inflation rates, changes in property lives, and the expected asset retirement cost. The changes in the asset retirement obligations for the years ended December 31, 2018 and 2017 were as follows: December 31, 2018 2017 Beginning of year balance $ 10,466,413 $ 10,196,383 Liabilities incurred during year 69,021 6,663 Liabilities settled during year (295,146 ) (389,765 ) Liabilities sold during year (15,203 ) (418,527 ) Accretion expense 560,922 557,683 Revisions in estimated cash flows 485,852 513,976 End of year balance $ 11,271,859 $ 10,466,413 Liabilities sold during 2018 include the sale of the Bakken properties. Liabilities settled include plugging and abandoning one well in California.

ACCOUNTS RECEIVABLE FROM CHIEF

ACCOUNTS RECEIVABLE FROM CHIEF EXECUTIVE OFFICER AND EMPLOYEES	12 Months Ended
	Dec. 31, 2018
Accounts Receivable, after Allowance for Credit Loss [Abstract]
ACCOUNTS RECEIVABLE FROM CHIEF EXECUTIVE OFFICER AND EMPLOYEES	The following table provides information with respect to related party transactions with the former Chief Executive Officer (“CEO”) of the Company and employees at December 31, 2018 and December 31, 2017. The receivable from the former CEO at December 31, 2018 is primarily for invoiced costs on prospects and wells as part of his normal joint interest billings (see Note 10 – Related Party Transactions). December 31, 2018 2017 Receivables from CEO and employees: Current: CEO $ 12,748 $ 53,979 Employees - - Total $ 12,748 $ 53,979

RELATED PARTY TRANSACTIONS

RELATED PARTY TRANSACTIONS	12 Months Ended
	Dec. 31, 2018
Related Party Transactions [Abstract]
RELATED PARTY TRANSACTIONS	In 2011, Yuma California entered into a Working Interest Incentive Plan (“WIIP”) with Mr. Sam L. Banks, the CEO of Yuma California and the Company at December 31, 2018. The Board of Directors of Yuma California terminated the WIIP effective September 21, 2015; however, Mr. Banks retains working interests in certain of the Company’s properties.

FAIR VALUE MEASUREMENTS

FAIR VALUE MEASUREMENTS	12 Months Ended
	Dec. 31, 2018
Fair Value Disclosures [Abstract]
FAIR VALUE MEASUREMENTS	Certain financial instruments are reported at fair value on the Consolidated Balance Sheets. Under fair value measurement accounting guidance, fair value is defined as the amount that would be received from the sale of an asset or paid for the transfer of a liability in an orderly transaction between market participants, i.e., an exit price. To estimate an exit price, a three-level hierarchy is used. The fair value hierarchy prioritizes the inputs, which refer broadly to assumptions market participants would use in pricing an asset or a liability, into three levels (see the Fair Value section of Note 3 – Summary of Significant Accounting Policies). The Company uses a market valuation approach based on available inputs and the following methods and assumptions to measure the fair values of its assets and liabilities, which may or may not be observable in the market. Fair Value of Financial Instruments (other than Commodity Derivative, see below) – Derivatives Fair value measurements at December 31, 2018 Significant Quoted prices other Significant in active observable unobservable markets inputs inputs (Level 1) (Level 2) (Level 3) Total Assets: Commodity derivatives – oil $ - $ 922,562 $ - $ 922,562 Commodity derivatives – gas - (158,376 ) - $ (158,376 ) Total liabilities $ - $ 764,186 $ - $ 764,186 Fair value measurements at December 31, 2017 Significant Quoted prices other Significant in active observable unobservable markets inputs inputs (Level 1) (Level 2) (Level 3) Total Liabilities: Commodity derivatives – oil $ - $ 1,517,410 $ - $ 1,517,410 Commodity derivatives – gas - (278,001 ) - $ (278,001 ) Total liabilities $ - $ 1,239,409 $ - $ 1,239,409 Derivative instruments listed above include swaps, collars, and three-way collars (see Note 12 – Commodity Derivative Instruments). Debt Asset Retirement Obligations Assets Held for Sale

COMMODITY DERIVATIVE INSTRUMENT

COMMODITY DERIVATIVE INSTRUMENTS	12 Months Ended
	Dec. 31, 2018
Derivative Instruments and Hedging Activities Disclosure [Abstract]
COMMODITY DERIVATIVE INSTRUMENTS	Objectives and Strategies for Using Commodity Derivative Instruments As required under the Credit Agreement, the Company previously entered into hedging arrangements with SocGen and BP Energy Company (“BP”) pursuant to International Swaps and Derivatives Association Master Agreements (“ISDA Agreements”). On March 14, 2019, the Company received a notice of an event of default under its ISDA Agreement with SocGen (the “SocGen ISDA”). Due to the default under the ISDA Agreement, SocGen unwound all of the Company’s hedges with them. The notice provides for a payment of approximately $347,129 to settle the Company’s outstanding obligations thereunder related to SocGen’s hedges (of which $-0- is included in accounts payable at December 31, 2018). On March 19, 2019, The Company received a notice of an event of default under its ISDA Agreement with BP (the “BP ISDA”). Due to the default under the ISDA Agreement, BP also unwound all of the Company’s hedges with them. The notice provides for a payment of approximately $775,725 to settle the Company’s outstanding obligations thereunder related to BP’s hedges (of which $-0- is included in accounts payable at December 31, 2018). Futures contracts and commodity price swap agreements are used to fix the price of expected future oil and natural gas sales at major industry trading locations such as Henry Hub, Louisiana for natural gas and Cushing, Oklahoma for oil. Basis swaps are used to fix or float the price differential between product prices at one market location versus another. Options are used to establish a floor price, a ceiling price, or a floor and ceiling price (collar) for expected future oil and natural gas sales. A three-way collar is a combination of three options: a sold call, a purchased put, and a sold put. The sold call establishes the maximum price that the Company will receive for the contracted commodity volumes. The purchased put establishes the minimum price that the Company will receive for the contracted volumes unless the market price for the commodity falls below the sold put strike price, at which point the minimum price equals the reference price (e.g., NYMEX) plus the excess of the purchased put strike price over the sold put strike price. While these instruments mitigate the cash flow risk of future reductions in commodity prices, they may also curtail benefits from future increases in commodity prices. The Company does not apply hedge accounting to any of its derivative instruments. As a result, gains and losses associated with derivative instruments are recognized currently in earnings. Counterparty Credit Risk Commodity derivative instruments open as of December 31, 2018 are provided below. Natural gas prices are New York Mercantile Exchange (“NYMEX”) Henry Hub prices, and crude oil prices are NYMEX West Texas Intermediate (“WTI”). 2019 2020 Settlement Settlement NATURAL GAS (MMBtu): Swaps Volume 1,660,297 1,095,430 Price $ 2.75 $ 2.68 CRUDE OIL (Bbls): Swaps Volume 139,823 Price $ 53.95 Derivatives for each commodity are netted on the Consolidated Balance Sheets. The following table presents the fair value and balance sheet location of each classification of commodity derivative contracts on a gross basis without regard to same-counterparty netting: Fair value as of December 31, 2018 2017 Asset commodity derivatives: Current assets $ 1,031,614 $ 295,304 Noncurrent assets 98,530 118 1,130,144 295,422 Liability commodity derivatives: Current liabilities (280,456 ) (1,198,307 ) Noncurrent liabilities (85,502 ) (336,524 ) (365,958 ) (1,534,831 ) Total commodity derivative instruments $ 764,186 $ (1,239,409 ) Net gains (losses) from commodity derivatives on the Consolidated Statements of Operations are comprised of the following: Years Ended December 31, 2018 2017 Derivative settlements $ (2,419,303 ) $ 1,238,341 Mark to market on commodity derivatives 2,003,595 1,316,593 Net gains (losses) from commodity derivatives $ (415,708 ) $ 2,554,934

PREFERRED STOCK

PREFERRED STOCK	12 Months Ended
	Dec. 31, 2018
Preferred Stock Abstract
PREFERRED STOCK	As part of the closing of the Davis Merger, YCI issued an aggregate of 1,754,179 shares of Series D Preferred Stock as part of the completion of the Davis Merger to former holders of Series A Preferred Stock of Davis, which is convertible into shares of YCI’s common stock. Each share of Series D Preferred Stock is convertible into a number of shares of common stock determined by dividing the original issue price, which was $11.0741176, by the conversion price, which is currently $6.5838109 due to the Company’s common stock offering in September and October of 2017. The conversion price is subject to adjustment for stock splits, stock dividends, reclassification, and certain issuances of common stock for less than the conversion price. As of December 31, 2018, the Series D Preferred Stock had a liquidation preference of approximately $22.6 million. The Series D Preferred Stock provides for cumulative dividends of 7.0% per annum, payable in-kind. The Company issued 136,849 shares of Series D Preferred Stock during the year ended December 31, 2018.

STOCK-BASED COMPENSATION

STOCK-BASED COMPENSATION	12 Months Ended
	Dec. 31, 2018
Share-based Payment Arrangement [Abstract]
STOCK-BASED COMPENSATION	2006 Stock Incentive Plan On October 26, 2016, the Company assumed the Yuma California 2006 Equity Incentive Plan (“2006 Plan”). The 2006 Plan provided, among other things, for the granting of stock options to key employees, officers, directors, and consultants of Yuma California by its board of directors. As of the closing of the Reincorporation Merger, there were stock option awards for 5,000 shares of common stock outstanding that were assumed by the Company. Further, on September 11, 2014, the board of directors of Yuma California determined that no additional awards would be granted under the 2006 Plan, and that the 2014 Plan would be used going forward. All outstanding awards under the 2006 Plan expired in October 2018. 2011 Stock Option Plan On October 26, 2016, the Company assumed the Yuma California 2011 Stock Option Plan (“2011 Plan”). The 2011 Plan provided, among other things, for the granting of up to 227,201 shares of common stock as awards to key employees, officers, directors, and consultants of Yuma California by its board of directors. An award could take the form of stock options, stock appreciation rights, restricted stock awards or restricted stock units. As of the closing of the Reincorporation Merger, there were awards for approximately 2,878 shares of common stock outstanding that were assumed by the Company. Further, on September 11, 2014, the board of directors of Yuma California determined that no additional awards would be granted under the 2011 Plan, and that the 2014 Plan would be used going forward. 2014 Long-Term Incentive Plan On October 26, 2016, Yuma assumed the Yuma Energy, Inc., a California corporation (“Yuma California”), 2014 Long-Term Incentive Plan (the “2014 Plan”), which was approved by the shareholders of Yuma California. Under the 2014 Plan, Yuma could grant stock options, restricted stock awards (“RSAs”), restricted stock units (“RSUs”), stock appreciation rights (“SARs”), performance units, performance bonuses, stock awards and other incentive awards to employees of Yuma and its subsidiaries and affiliates. At December 31, 2018, 17,056 shares of the 2,495,000 shares of common stock originally authorized under the 2014 Plan remained available for future issuance. However, upon adoption of the Company’s 2018 Long-Term Incentive Plan on June 7, 2018, none of these remaining shares will be issued. 2018 Long-Term Incentive Plan The Company’s Board adopted the Yuma Energy, Inc. 2018 Long-Term Incentive Plan (the “2018 Plan”), and its stockholders approved the 2018 Plan at the Annual Meeting on June 7, 2018. The 2018 Plan will replace the 2014 Plan; however, the terms and conditions of the 2014 Plan and related award agreements will continue to apply to all awards granted under the 2014 Plan. The 2018 Plan expires on June 7, 2028, and no awards may be granted under the 2018 Plan after that date. However, the terms and conditions of the 2018 Plan will continue to apply after that date to all 2018 Plan awards granted prior to that date until they are no longer outstanding. Under the 2018 Plan, the Company may grant stock options, RSAs, RSUs, SARs, performance units, performance bonuses, stock awards and other incentive awards to employees or those of the Company’s subsidiaries or affiliates, subject to the terms and conditions set forth in the 2018 Plan. The Company may also grant nonqualified stock options, RSAs, RSUs, SARs, performance units, stock awards and other incentive awards to any persons rendering consulting or advisory services and non-employee directors, subject to the conditions set forth in the 2018 Plan. Generally, all classes of the Company’s employees are eligible to participate in the 2018 Plan. The 2018 Plan provides that a maximum of 4,000,000 shares of the Company’s common stock may be issued in conjunction with awards granted under the 2018 Plan. Shares of common stock cancelled, settled in cash, forfeited, withheld, or tendered by a participant to satisfy exercise prices or tax withholding obligations will be available for delivery pursuant to other awards. At December 31, 2018, all of the 4,000,000 shares of common stock authorized under the 2018 Plan remain available for future issuance. The Company accounts for stock-based compensation in accordance with FASB ASC Topic 718, “Compensation – Stock Compensation”. RSAs, SARs and Stock Options granted to officers and employees generally vest in one-third increments over a three-year period, or with three year cliff vesting, and are contingent on the recipient’s continued employment. RSAs granted to directors generally vest in quarterly increments over a one-year period. Restricted Stock – Number of Weighted average unvested grant-date RSA shares fair value Unvested shares as of January 1, 2018 274,450 $2.78 per share Granted on February 6, 2018 930,916 $1.15 per share Vested on February 6, 2018 (930,916 ) $1.15 per share Vested on February 6, 2018 (80,687 ) $1.15 per share Vested on May 31, 2018 (31,147 ) $0.40 per share Vested on July 20, 2018 (1,250 ) $0.46 per share Forfeited (17,056 ) $2.56 per share Unvested shares as of December 31, 2018 144,310 $2.56 per share At December 31, 2018, total unrecognized RSA compensation cost of $203,144 is expected to be recognized over a weighted average remaining service period of approximately one years. Stock Appreciation Rights – Stock Settled – Weighted Number of average unvested grant-date SARs fair value Unvested shares as of January 1, 2018 28,081 $2.35 per share Vested on May 31, 2018 (28,081 ) $2.35 per share Forfeited - Unvested shares as of December 31, 2018 - Assumptions used to estimate fair value of the above SARs assumed were expected life of 5.8 years, 84.2% volatility, 1.42% risk-free rate, and zero annual dividends. The SARs in the table above have a weighted average exercise price of $12.10 and an aggregate intrinsic value of zero. The Company intends to settle these SARs in equity, as opposed to cash. Stock Appreciation Rights – Cash Settled – Number of unvested Weighted average SARs fair value Unvested shares as of January 1, 2018 1,623,371 $0.06 per share Vested February 6, 2018 (159,092 ) $0.06 per share Forfeited - Unvested shares as of December 31, 2018 1,464,279 $0.06 per share The cash settled SARs vest under the same terms and conditions as stock options; however, they are settled in cash equal to their settlement date fair value. As a result, the cash settled SARs are recorded in the Company’s consolidated balance sheets as a liability until the date of exercise. The fair value of each SAR award is estimated using an option pricing model. In accordance with ASC Topic 718, “Stock Compensation,” the fair value of each SAR award is recalculated at the end of each reporting period and the liability and expense adjusted based on the new fair value and the percent vested. The Company did not grant any cash settled SARs during 2018. The assumptions used to determine the fair value of the cash settled SAR awards at December 31, 2018 were expected life of 3.3 years, 143.6% volatility, 2.45% risk-free rate, and zero annual dividends. Stock Options – During 2017, the Company granted stock options under the 2014 Plan. The options vest in three equal annual installments beginning on February 6, 2018 and after vesting are exercisable until the tenth anniversary of the grant date. The following is a summary of the Company’s stock option activity. Weighted- Weighted- average average remaining Aggregate exercise contractual intrinsic Options price life (years) value Outstanding at December 31, 2017 898,617 $ 3.12 9.25 $ - Granted - - - - Exercised - - - - Forfeited - - - - Expired (5,000 ) $ 103.20 - - Outstanding at December 31, 2018 893,617 $ 2.56 8.30 $ - Vested at December 31, 2018 297,874 $ 2.56 8.30 $ - Exercisable at December 31, 2018 297,874 $ 2.56 8.30 $ - The Company uses the Black-Scholes option pricing model to calculate the fair value of its stock options. Assumptions used to estimate fair values for the options granted were expected life of 5.9 years, 84.2% volatility, 1.9% risk-free rate, and zero annual dividends. As of December 31, 2018, there were 595,745 unvested stock options and $595,777 unrecognized stock option expenses, with a weighted average remaining service period of 1.1 years. Total share-based compensation expense recognized for the years ended December 31, 2018 and 2017 was $582,344 and $2,381,365, respectively, and is reflected in general and administrative expenses in the Consolidated Statements of Operations.

NET INCOME (LOSS) PER COMMON SH

NET INCOME (LOSS) PER COMMON SHARE	12 Months Ended
	Dec. 31, 2018
LOSS PER COMMON SHARE:
NET INCOME (LOSS) PER COMMON SHARE	Net Income (Loss) per common share – Basic is calculated by dividing net loss by the weighted average number of shares of common stock outstanding during the period. Net loss per common share – Diluted assumes the conversion of all potentially dilutive securities, and is calculated by dividing net loss by the sum of the weighted average number of shares of common stock outstanding plus potentially dilutive securities. Net loss per common share – Diluted considers the impact of potentially dilutive securities except in periods where their inclusion would have an anti-dilutive effect. A reconciliation of loss per common share is as follows: Years Ended December 31, 2018 2017 Net loss attributable to common stockholders $ (17,070,271 ) $ (6,806,633 ) Net loss per common share: Basic $ (0.74 ) $ (0.46 ) Diluted $ (0.74 ) $ (0.46 ) Weighted average common shares outstanding Basic 23,023,066 14,815,991 Add potentially dilutive securities: Unvested restricted stock awards - - Stock appreciation rights - - Stock options - - Series D preferred stock - - Diluted weighted average common shares outstanding 23,023,066 14,815,991 For the year ended December 31, 2018, the Company excluded 144,310 shares of unvested restricted stock awards, 1,707,619 stock appreciation rights, 893,617 stock options, and 2,041,240 shares of Series D Preferred Stock in calculating diluted earnings per share, as the effect was anti-dilutive. For the year ended December 31, 2017, the Company excluded 274,450 shares of unvested restricted stock awards, 1,707,619 stock appreciation rights, 898,617 stock options, and 1,904,391 shares of Series D Preferred Stock in calculating diluted earnings per share, as the effect was anti-dilutive.

DEBT AND INTEREST EXPENSE

DEBT AND INTEREST EXPENSE	12 Months Ended
	Dec. 31, 2018
Debt Disclosure [Abstract]
DEBT AND INTEREST EXPENSE	Long-term debt at December 31 consisted of the following: December 31, 2018 2017 Senior credit facility $ 34,000,000 $ 27,700,000 Installment loan due 7/22/19 originating from the financing of insurance premiums at 6.14% interest rate 742,953 - Installment loan due 7/22/18 originating from the financing of insurance premiums at 5.14% interest rate - 651,124 Total debt 34,742,953 28,351,124 Less: current maturities (34,742,953 ) (651,124 ) Total long-term debt $ - $ 27,700,000 Senior Credit Facility The Company is currently in default under its credit facility due to non-compliance with the financial covenants and failure to pay interest. As of December 31, 2018, the credit facility had a borrowing base of $34.0 million and the Company was fully drawn under the credit facility leaving no availability. On October 26, 2016, the Company and three of its subsidiaries, as the co-borrowers, entered into a credit agreement providing for a $75.0 million three-year senior secured revolving credit facility (the “Credit Agreement”) with Société Générale (“SocGen”), as administrative agent, SG Americas Securities, LLC, as lead arranger and bookrunner, and the lenders signatory thereto (collectively with SocGen, the “Lender”). The Company’s obligations under the Credit Agreement are guaranteed by its subsidiaries and are secured by liens on substantially all of the Company’s assets, including a mortgage lien on oil and natural gas properties covering at least 95% of the PV-10 value of the proved oil and gas properties included in the determination of the borrowing base. The borrowing base is generally subject to redetermination on April 1st and October 1st of each year, as well as special redeterminations described in the Credit Agreement. The amounts borrowed under the Credit Agreement bear annual interest rates at either (a) the London Interbank Offered Rate (“LIBOR”) plus 3.00% to 4.00% or (b) the prime lending rate of SocGen plus 2.00% to 3.00%, depending on the amount borrowed under the credit facility and whether the loan is drawn in U.S. dollars or Euro dollars. The interest rate for the credit facility at December 31, 2018 was 6.53% for LIBOR-based debt and 8.507.00% for prime-based debt. Principal amounts outstanding under the credit facility are due and payable in full at maturity on October 26, 2019. All of the obligations under the Credit Agreement, and the guarantees of those obligations, are secured by substantially all of the Company’s assets. Additional payments due under the Credit Agreement include paying a commitment fee to the Lender in respect of the unutilized commitments thereunder. The commitment rate is 0.50% per year of the unutilized portion of the borrowing base in effect from time to time. We are also required to pay customary letter of credit fees. The Credit Agreement contains a number of covenants that, among other things, restrict, subject to certain exceptions, the Company’s ability to incur additional indebtedness, create liens on assets, make investments, enter into sale and leaseback transactions, pay dividends and distributions or repurchase the Company’s capital stock, engage in mergers or consolidations, sell certain assets, sell or discount any notes receivable or accounts receivable, and engage in certain transactions with affiliates. In addition, the Credit Agreement requires the Company to maintain the following financial covenants: a current ratio of not less than 1.0 to 1.0 on the last day of each quarter, a ratio of total debt to earnings before interest, taxes, depreciation, depletion, amortization and exploration expenses (“EBITDAX”) ratio of not greater than 3.5 to 1.0 for the four fiscal quarters ending on the last day of the fiscal quarter immediately preceding such date of determination, and a ratio of EBITDAX to interest expense of not less than 2.75 to 1.0 for the four fiscal quarters ending on the last day of the fiscal quarter immediately preceding such date of determination, and cash and cash equivalent investments together with borrowing availability under the Credit Agreement of at least $4.0 million. The Credit Agreement contains customary affirmative covenants and defines events of default for credit facilities of this type, including failure to pay principal or interest, breach of covenants, breach of representations and warranties, insolvency, judgment default, and a change of control. Upon the occurrence and continuance of an event of default, the Lender has the right to accelerate repayment of the loans and exercise its remedies with respect to the collateral. At December 31, 2018, the Company was not in compliance under the credit facility with its (i) total debt to EBITDAX covenant for the trailing four quarter period, (ii) current ratio covenant, (iii) EBITDAX to interest expense covenant for the trailing four quarter period, (iv) the liquidity covenant requiring the Company to maintain unrestricted cash and borrowing base availability of at least $4.0 million, and (v) obligation to make an interest only payment for the quarter ended December 31, 2018. In addition, the Company currently is not making payments of interest under the credit facility and anticipate future non-compliance under the credit facility going forward. Due to this non-compliance as well as the credit facility maturity in 2019, the Company classified its entire bank debt as a current liability in the consolidated financial statements. On October 9, 2018, the Company received a notice and reservation of rights from the administrative agent under the Credit Agreement advising that an event of default has occurred and continues to exist by reason of the Company’s noncompliance with the liquidity covenant requiring the Company to maintain cash and cash equivalents and borrowing base availability of at least $4.0 million. As a result of the default, the Lender may accelerate the outstanding balance under the Credit Agreement, increase the applicable interest rate by 2.0% per annum or commence foreclosure on the collateral securing the loans. As of the date of this report, the Lender has not accelerated the outstanding amount due and payable on the loans, increased the applicable interest rate or commenced foreclosure proceedings, but may exercise one or more of these remedies in the future. The Company has commenced discussions with the Lender concerning a forbearance agreement or waiver of the event of default; however, there can be no assurance that the Lender and the Company will come to any agreement regarding a forbearance or waiver of the event of default. As required under the Credit Agreement, the Company previously entered into hedging arrangements with SocGen and BP Energy Company (“BP”) pursuant to International Swaps and Derivatives Association Master Agreements (“ISDA Agreements”). On March 14, 2019, the Company received a notice of an event of default under the Company’s ISDA Agreement with SocGen (the “SocGen ISDA”). Due to the default under the SocGen Agreement, SocGen unwound all of the Company’s hedges with them. The notice provides for a payment of approximately $347,129 to settle the Company’s outstanding obligations thereunder related to SocGen’s hedges (of which $-0- is included in accounts payable at December 31, 2018). On March 19, 2019, the Company received a notice of an event of default under the Company’s ISDA Agreement with BP (the “BP ISDA”). Due to the default under the BP ISDA, BP also unwound all of the Company’s hedges with them. The notice provides for a payment of approximately $775,725 to settle the Company’s outstanding obligations thereunder, related to BP’s hedges (of which $-0- is included in accounts payable at December 31, 2018). The Company incurred commitment fees of $19,170 and $41,404 during 2018 and 2017, respectively.

STOCKHOLDERS' EQUITY

STOCKHOLDERS' EQUITY	12 Months Ended
	Dec. 31, 2018
EQUITY:
STOCKHOLDERS' EQUITY	The Company is authorized to issue up to 100,000,000 shares of common stock, $0.001 par value per share, and 20,000,000 shares of preferred stock, $0.001 par value per share. The holders of common stock are entitled to one vote for each share of common stock, except as otherwise required by law. The Company has designated 7,000,000 shares of preferred stock as Series D Preferred Stock. The Company assumed the 2006 Plan, the 2011 Plan, and the 2014 Plan upon the completion of the Reincorporation Merger as described in Note 14 – Stock-Based Compensation, which describes outstanding stock options, restricted stock awards and stock appreciation rights granted under the 2006 Plan, the 2011 Plan and the 2014 Plan. In September and October 2017, the Company completed a public offering of 10,100,000 shares of common stock (including 500,000 shares purchased pursuant to the underwriter’s overallotment option), at a public offering price of $1.00 per share. The Company received net proceeds from this offering of approximately $8.7 million, after deducting underwriters’ fees and offering expenses of $1.4 million.

INCOME TAXES

INCOME TAXES	12 Months Ended
	Dec. 31, 2018
Income Tax Disclosure [Abstract]
INCOME TAXES	The provision for income taxes for the years ended December 31 is as follows: December 31, 2018 2017 Current expense (benefit) Federal $ - $ - State - - Deferred expense (benefit) Federal - - State - - Total income tax expense $ - $ - A reconciliation of the federal statutory income tax rate to the effective income tax rate for the years ended December 31 is as follows: December 31, 2018 2017 U.S. statutory rate 21.00 % 35.00 % State income taxes (net of federal benefit) 6.96 % (9.21 %) Nondeductible transaction costs 0.00 % (1.61 %) Stock compensation 0.00 % (0.03 %) Prior year differences 0.00 % 7.38 % Change in tax rates 0.00 % (429.43 %) Valuation allowance (27.91 %) 397.96 % Other (0.05 %) (0.06 %) Effective tax rate (0.00 %) 0.00 % Deferred income tax (liabilities) assets at December 31 follow: December 31, 2018 2017 Deferred income tax liabilities Property and equipment $ (4,884,966 ) $ (4,599,347 ) Commodity derivative instruments (130,856 ) - (5,015,822 ) (4,599,347 ) Deferred income tax assets Net operating loss carryforward 46,370,912 41,368,982 Commodity derivative instruments - 326,893 Financial accruals and other 145,031 246,001 Asset retirement obligation 2,789,434 2,476,370 Stock-based compensation 141,759 270,366 Valuation allowance (44,431,314 ) (40,089,265 ) 5,015,822 4,599,347 Deferred income taxes, net $ - $ - At December 31, 2018, the Company had federal net operating loss carryforwards of approximately $187.8 million, of which $173.2 million expire between 2022 and 2038. Of this amount, approximately $59.5 million is subject to limitation under Section 382 of the Code, which could result in a significant portion of the $59.5 million expiring prior to being utilized. The remaining $14.6 million of federal net operating loss may be carried forward indefinitely. The Company has $87.6 million of state net operating losses which expire between 2022 and 2038. Realization of a deferred tax asset is dependent, in part, on generating sufficient taxable income prior to expiration of the loss carryforwards. At December 31, 2018, the Company has recorded a full valuation allowance against its federal and state net deferred tax assets of $44.4 million because the Company believes it is more likely than not that the assets will not be utilized based on losses over the most recent three-year period. At December 31, 2018, the Company does not have any unrecognized tax benefits and does not anticipate any unrecognized tax benefits during the next twelve months. The tax years of the Company that remain subject to examination by the Internal Revenue Service and other income tax authorities are fiscal years 2014 to 2018. Recently Enacted U.S. Tax Legislation Comprehensive tax reform legislation enacted in December 2017, the Tax Cuts and Jobs Act (the “Tax Act”), made significant changes to U.S. federal income tax laws. The Tax Act, among other things, reduced the corporate income tax rate from 35% to 21%, partially limits the deductibility of future net operating losses, and allows for the immediate deduction of certain new investments instead of deductions for depreciation expense over time. The main effect of the Tax Act on the Company was the re-measurement of the deferred tax assets and liabilities from 35% to 21% as of December 31, 2017, which resulted in an impact to the effective tax rate of (429.43%). Since the Company is in a full valuation allowance, no income tax expense or benefit was recorded in connection with the re-measurement of the deferred tax assets and liabilities. The results of the re-measurement were offset with a corresponding change in the valuation allowance. The Company’s analysis is complete and no further adjustments were made during 2018.

COMMITMENTS AND CONTINGENCIES

COMMITMENTS AND CONTINGENCIES	12 Months Ended
	Dec. 31, 2018
Commitments and Contingencies Disclosure [Abstract]
COMMITMENTS AND CONTINGENCIES	Joint Development Agreement On March 27, 2017, the Company entered into a Joint Development Agreement (“JDA”) with two privately held companies, both unaffiliated entities, covering an area of approximately 52 square miles (33,280 acres) in the Permian Basin of Yoakum County, Texas. In connection with the JDA, the Company now holds a 62.5% working interest in approximately 4,823 acres (3,014 net acres) as of December 31, 2018. As the operator of the property covered by the JDA, the Company was committed as of December 31, 2018 to spend an additional $241,649 by March 2020. Throughput Commitment Agreement On August 1, 2014, Crimson Energy Partners IV, LLC, as operator of the Company’s Chalktown properties, in which the Company has a working interest, entered into a throughput commitment (the “Commitment”) with ETC Texas Pipeline, Ltd. effective April 1, 2015 for a five year throughput commitment. In connection with the Commitment, the operator and the Company failed to reach the volume commitments in year two, and the Company anticipates that a shortfall will exist through the expiration of the five year term, which expires in March 2020. Accordingly, the Company is accruing the expected volume commitment shortfall amounts of approximately $29,000 per month to lease operating expense (“LOE”) based on production, which represents the maximum amounts that could be owed based upon the Commitment. Lease Agreements On July 26, 2017, the Company entered into a tenth amendment to its office lease whereby the term of the lease was extended to August 31, 2023. The lease amendment covers a period of 68 calendar months and went into effect on January 1, 2018. In addition, the lease amendment included seven months of abated rent and operating expenses from June 1, 2017 through February 1, 2018, as well as other incentives, including abated parking cost and tenant lease improvement allowances. The base rent amount (which began on January 1, 2018) starts at $258,060 per annum and escalates to $288,420 per annum during the final 19 months of the lease extension. In addition to the base rent amount, the Company is responsible for additional operating expenses of the building as well as parking charges. The Company accounts for the lease as an operating lease under GAAP. The Company also currently leases approximately 3,200 square feet of office space at an off-site location as a storage facility. The current lease expires on April 30, 2020. Aggregate rental expense for the years ended December 31, 2018 and 2017 was $504,046 and $507,331, respectively. As of December 31, 2018, future minimum base rentals (including estimated operating expenses) under all noncancellable operating leases are as follows: 2019 $ 532,147 2020 $ 520,297 2021 $ 524,044 2022 $ 530,990 2023 $ 351,392 Certain Legal Proceedings From time to time, the Company is party to various legal proceedings arising in the ordinary course of business. The Company expenses or accrues legal costs as incurred. A summary of the Company’s legal proceedings is as follows: Yuma Energy, Inc. v. Cardno PPI Technology Services, LLC Arbitration On May 20, 2015, counsel for Cardno PPI Technology Services, LLC (“Cardno PPI”) sent a notice of the filing of liens totaling $304,209 on the Company’s Crosby 14 No. 1 Well and Crosby 14 SWD No. 1 Well in Vernon Parish, Louisiana. The Company disputed the validity of the liens and of the underlying invoices, and notified Cardno PPI that applicable credits had not been applied. The Company invoked mediation on August 11, 2015 on the issues of the validity of the liens, the amount due pursuant to terms of the parties’ Master Service Agreement (“MSA”), and PPI Cardno’s breaches of the MSA. Mediation was held on April 12, 2016; no settlement was reached. On May 12, 2016, Cardno filed a lawsuit in Louisiana state court to enforce the liens; the Court entered an Order Staying Proceeding on June 13, 2016, ordering that the lawsuit “be stayed pending mediation/arbitration between the parties.” On June 17, 2016, the Company served a Notice of Arbitration on Cardno PPI, stating claims for breach of the MSA billing and warranty provisions. On July 15, 2016, Cardno PPI served a Counterclaim for $304,209 plus attorneys’ fees. The parties selected an arbitrator, and the arbitration hearing was held on March 29, April 12 and April 13, 2018. The parties submitted closing statements on April 30, 2018, and are awaiting a ruling by the arbitrator. Management intends to pursue the Company’s claims and to defend the counterclaim vigorously. At this point in the legal process, no evaluation of the likelihood of an unfavorable outcome or associated economic loss can be made; therefore no liability has been recorded on the Company’s consolidated financial statements. The Parish of St. Bernard v. Atlantic Richfield Co., et al On October 13, 2016, two subsidiaries of the Company, Yuma Exploration and Production Company, Inc. (“Exploration”) and Yuma Petroleum Company (“YPC”), were named as defendants, among several other defendants, in an action by the Parish of St. Bernard in the Thirty-Fourth Judicial District of Louisiana. The petition alleges violations of the State and Local Coastal Resources Management Act of 1978, as amended, in the St. Bernard Parish. The Company has notified its insurance carrier of the lawsuit. Management intends to defend the plaintiffs’ claims vigorously. The case was removed to federal district court for the Eastern District of Louisiana. A motion to remand was filed and the Court officially remanded the case on July 6, 2017. Exceptions for Exploration, YPC and the other defendants were filed; however, the hearing for such exceptions was continued from the original date of October 6, 2017 to November 22, 2017. The November 22, 2017 hearing was continued without date because the parties agreed the case will be de-cumulated into subcases, but the details of this are yet to be determined. The case was removed again on other grounds on May 23, 2018. On May 25, 2018, a Motion was filed on behalf of certain defendants with the United States Judicial Panel for Multi District Litigation (“JPMDL”) for consolidated proceedings for all 41 pending cases filed in Louisiana with claims that are substantially the same as those in this case. A 42nd case has been added as a “tag-along”. In the interim, plaintiffs timely filed their Motion to Remand in the case. Hearing on the Motion before the JPMDL was held on July 26, 2018 in Santa Fe, New Mexico, and the JPMDL denied centralization by Order dated July 31, 2018. The Order indicates Plaintiffs may be willing to consolidate all cases pending in the Western District with those in the Eastern District, although Defendants may not be amenable to same. That did not occur and this case remains stayed. In the interim, an Order was issued in another of the coastal cases pending in the Eastern District of Louisiana lifting the stay and setting a schedule for briefing for plaintiffs’ motion to remand ( Parish of Plaquemines v. Riverwood Production Company, et al., No. 2:18-cv-05217, Eastern District of Louisiana Riverwood Riverwood Auster Riverwood Cameron Parish vs. BEPCO LP, et al & Cameron Parish vs. Alpine Exploration Companies, Inc., et al The Parish of Cameron, Louisiana, filed a series of lawsuits against approximately 190 oil and gas companies alleging that the defendants, including Davis Petroleum Acquisition Corp. (“Davis”), have failed to clear, revegetate, detoxify, and restore the mineral and production sites and other areas affected by their operations and activities within certain coastal zone areas to their original condition as required by Louisiana law, and that such defendants are liable to Cameron Parish for damages under certain Louisiana coastal zone laws for such failures; however, the amount of such damages has not been specified. Two of these lawsuits, originally filed February 4, 2016 in the 38th Judicial District Court for the Parish of Cameron, State of Louisiana, name Davis as defendant, along with more than 30 other oil and gas companies. Both cases have been removed to federal district court for the Western District of Louisiana. The Company denies these claims and intends to vigorously defend them. Davis has become a party to the Joint Defense and Cost Sharing Agreements for these cases. Motions to remand were filed and the Magistrate Judge recommended that the cases be remanded. The Company was advised that the new District Judge assigned to these cases is Judge Terry A. Doughty, and on May 9, 2018, Judge Doughty agreed with the Magistrate Judge’s recommendation and the cases were remanded to the 38th Judicial District Court, Cameron Parish, Louisiana. The cases were removed again on other grounds on May 23, 2018. On May 25, 2018, a Motion was filed on behalf of certain defendants with the United States Judicial Panel for Multi District Litigation (“JPMDL”) for consolidated proceedings for all 41 pending cases filed in Louisiana with claims that are substantially the same as those in these cases. A 42nd case has been added as a “tag-along”. In the interim, plaintiffs timely filed their Motion to Remand in the cases. Hearing on the Motion before the JPMDL was held on July 26, 2018 in Santa Fe, New Mexico, and the JPMDL denied centralization by Order dated July 31, 2018. The Order indicates Plaintiffs may be willing to consolidate all cases pending in the Western District with those in the Eastern District, although Defendants may not be amenable to same. That did not occur. On October 1, 2018, all of the coastal cases pending in the Western District of Louisiana, including these cases, were re-assigned to the newly appointed District Judge, Judge Robert R. Summerhays. On August 29, 2018, Magistrate Judge Kay signed an Order providing for staged briefing on the plaintiffs’ motion(s) to remand in all the coastal cases pending in the Western District, with the lowest numbered case (Parish of Cameron v. Auster, No. 18-677, Western District of Louisiana) to proceed first. In response to Defendants’ request for oral argument in the Auster case, Judge Kay issued an electronic Order on October 18, 2018, denying that request and further stating, “The issues have been thoroughly briefed and we do not find at this time that oral argument would be helpful.” As noted above, Magistrate Judge Kay previously recommended remand of these cases, which recommendation was adopted by the District Judge then assigned to the cases. Magistrate Judge Kay issued her Report and Recommendations recommending remand based on the timeliness of the second removal. Objections and replies were filed to the same and the District Judge now assigned to the cases granted and held oral argument on the objections to Magistrate Judge Kay’s Report and Recommendations on January 16, 2019. The District Judge has not yet ruled It is impossible to predict at this time whether this second removal will keep the cases in federal court. At this point in the legal process, no evaluation of the likelihood of an unfavorable outcome or associated economic loss can be made; therefore no liability has been recorded on the Company’s consolidated financial statements. Louisiana, et al Escheat Tax Audits The States of Louisiana, Texas, Minnesota, North Dakota and Wyoming have notified the Company that they will examine the Company’s books and records to determine compliance with each of the examining state’s escheat laws. The review is being conducted by Discovery Audit Services, LLC. The Company has engaged Ryan, LLC to represent it in this matter. The exposure related to the audits is not currently determinable and therefore, no liability has been recorded on the Company’s consolidated financial statements. Louisiana Severance Tax Audit The State of Louisiana, Department of Revenue, notified Exploration that it was auditing Exploration’s calculation of its severance tax relating to Exploration’s production from November 2012 through March 2016. The audit relates to the Department of Revenue’s recent interpretation of long-standing oil purchase contracts to include a disallowable “transportation deduction,” and thus to assert that the severance tax paid on crude oil sold during the contract term was not properly calculated. The Department of Revenue sent a proposed assessment in which they sought to impose $476,954 in additional state severance tax plus associated penalties and interest. Exploration engaged legal counsel to protest the proposed assessment and request a hearing. Exploration then entered a Joint Defense Group of operators challenging similar audit results. Since the Joint Defense Group is challenging the same legal theory, the Board of Tax Appeals proposed to hear a motion brought by one of the taxpayers (Avanti) that would address the rule for all through a test case. Exploration’s case has been stayed pending adjudication of the test case. The hearing for the Avanti test case was held on November 7, 2017, and on December 6, 2017, the Board of Tax Appeals rendered judgment in favor of the taxpayer in the first of these cases. The Department of Revenue filed an appeal to this decision on January 5, 2018. The Board of Tax Appeals case record has been lodged at the Louisiana Third Circuit Court of Appeal in the Avanti test case. . Oral argument was held at the Third Circuit on Tuesday, February 26, 2019, and a decision should be issued sometime in the next six to eight weeks. All other Board of Tax Appeals cases are stayed pending the final decision in the Avanti case. At this point in the legal process, no evaluation of the likelihood of an unfavorable outcome or associated economic loss can be made; therefore no liability has been recorded on the Company’s consolidated financial statements. Louisiana Department of Wildlife and Fisheries The Company received notice from the Louisiana Department of Wildlife and Fisheries (“LDWF”) in July 2017 stating that Exploration has open Coastal Use Permits (“CUPs”) located within the Louisiana Public Oyster Seed Grounds dating back from as early as November 1993 and through a period ending in November 2012. The majority of the claims relate to permits that were filed from 2000 to 2005. Pursuant to the conditions of each CUP, LDWF is alleging that damages were caused to the oyster seed grounds and that compensation of an aggregate amount of approximately $500,000 is owed by the Company. The Company is currently evaluating the merits of the claim, is reviewing the LDWF analysis, and has now requested that the LDWF revise downward the amount of area their claims of damages pertain to. At this point in the regulatory process, no evaluation of the likelihood of an unfavorable outcome or associated economic loss can be made; therefore no liability has been recorded on the Company’s consolidated financial statements. Miami Corporation – South Pecan Lake Field Area P&A The Company, along with several other exploration and production companies in the chain of title, received letters in June 2017 from representatives of Miami Corporation demanding the performance of well plugging and abandonment, facility removal and restoration obligations for wells in the South Pecan Lake Field Area, Cameron Parish, Louisiana. Apache is one of the other companies in the chain of title, and after taking a field tour of the area, has sent to the Company, along with BP and other companies in the chain of title, a proposed work plan to comply with the Miami Corporation demand. The Company is currently evaluating the merits of the claim and awaiting further information. At this point in the process, no evaluation of the likelihood of an unfavorable outcome or associated economic loss can be made; therefore no liability has been recorded on the Company’s consolidated financial statements. John Hoffman v. Yuma Exploration & Production Company, Inc., et al This lawsuit, filed on June 15, 2018 in Livingston Parish, Louisiana, against the Company, Precision Drilling and Dynamic Offshore relates to a slip and fall injury to Mr. Hoffman that occurred on August 28, 2017. Mr. Hoffman was apparently an employee of a subcontractor of a contractor performing services for the Company. Precision has made demand for defense and indemnity against the Company based on a contract entered into between the parties. The defense and indemnity demand is being contested, primarily on the grounds that the defense and indemnity obligation is barred by the Louisiana Anti-Indemnity Act. The Company believes that its contractor is responsible for injuries to employees of the contractor or subcontractor and that their insurance coverage, or insurance coverage maintained by the Company, should cover damages awarded to Mr. Hoffman. The Company has notified its insurance carrier of the lawsuit. Counsel believes that the claim will be successfully defended, but even if the defense and indemnity claim is legally enforceable, there is sufficient insurance in place to cover the exposure. Accordingly, the defense and indemnity claim does not represent any direct material exposure to the Company. Hall-Degravelles, L.L.C. v. Cockrell Oil Corporation, et al Avalon Plantation, Inc., et al v. Devon Energy Production Company, L.P., et al Avalon Plantation, Inc., et al v. American Midstream, et al The Company, as a successor in interest from another company years ago, along with 41 other companies in the chain of title, was named as a defendant in this lawsuit brought in St. Mary’s Parish, Louisiana on July 9, 2018. The substance of each of the petitions is virtually identical. In each case, the plaintiff(s) are seeking to recover damages to their property resulting from “oil and gas exploration and production activities.” The cited grounds for these actions include La. R.S. 30:29 (providing for restoration of property affected by oilfield contamination) and C.C. art. 2688 (notification by the lessee to the lessor when leased property is damaged). The plaintiffs are attempting to have these three cases consolidated. A hearing on motion to consolidate was held on January 15, 2019. At that time, Judge Sigur stated from the bench that he did not have sufficient information to order consolidation. A judgment to that effect has been submitted to the judge for signature. These cases are in the very early stages. At this point, not all of the named defendants have filed responsive pleadings. All of the defendants who have responded at this point have, inter alia, filed exceptions of vagueness due to the lack of specificity in the petitions which makes it impossible to determine what action(s) any individual defendant may have performed which would result in liability to the plaintiffs. The only exceptions that have been set for hearing are those jointly filed by XTO Energy, Inc., Exxon Mobil Oil Corporation and Exxon Mobil Corporation. The Company has sold the leases that appear to be involved in this litigation to Hilcorp Energy I, L.P., with an effective date of September 1, 2016. The conveyance includes an indemnity provision which appears to transfer liability for this type of damage to Hilcorp, and at some point it will be necessary to invoke this indemnity. The Company has notified its insurance carrier of the claim but believes that the suit is without merit. No evaluation of the likelihood of an unfavorable outcome or associated economic loss can be made at this early stage, therefore no liability has been recorded on the Company’s consolidated financial statements. Vintage Assets, Inc. v. Tennessee Gas Pipeline, L.L.C., et al On September 10, 2018, the Company received a Demand for Defense and Indemnity from High Point Gas Gathering, L.P. (HPGG) pursuant to the 2010 Purchase and Sale Agreement between Texas Southeastern Gas Gathering Company, et al and HPGG, et al. The demand related to a judgment and permanent injunction entered against HPGG and three other defendants on May 4, 2018 in the above referenced matter in the U.S. District Court in the Eastern District of Louisiana. The Company received a letter dated October 30, 2018 from HPGG informing it that the May 4, 2018 judgment had been vacated. No evaluation of the likelihood of an unfavorable outcome or associated economic loss can be made at this early stage, therefore, no liability has been recorded on Company’s consolidated financial statements. Texas General Land Office (“GLO”) On February 21, 2019, the GLO notified the Company that it would be conducting an audit of oil and gas production and royalty revenue for the period of September 2012 to August 2017 related to three of the Company’s leases located in Chambers County, Texas and four of the Company’s leases located in Jefferson County, Texas. The exposure related to the audit is not currently determinable and therefore, no liability has been recorded on the Company’s consolidated financial statements. See Note 23 - Subsequent Events for Sam Banks v. Yuma Energy, Inc. matter.

EMPLOYEE BENEFIT PLANS

EMPLOYEE BENEFIT PLANS	12 Months Ended
	Dec. 31, 2018
Retirement Benefits [Abstract]
EMPLOYEE BENEFIT PLANS	The Company has a defined contribution 401(k) plan (the “401(k) Plan”) for its qualified employees. Employees may contribute any amount of their compensation to the 401(k) Plan, subject to certain Internal Revenue Service annual limits and certain limitations for employees classified as high income. The 401(k) Plan provides for discretionary matching contributions by the Company, and the Company provided a match for employees at a rate of 100 percent of each employee’s contribution up to four percent of the employee’s base salary during 2017 and through August 31, 2018, when the Company resolved to discontinue matching contributions. The Company contributed $73,529 and $100,599 under the 401(k) Plan for the years ended December 31, 2018 and 2017, respectively. The Company provides medical, dental, and life insurance coverage for both employees and dependents, along with disability and accidental death and dismemberment coverage for employees only. The Company pays the full cost of coverage for all insurance benefits except medical. The Company’s contribution toward medical coverage is 90 percent for the employee portion of the premium, and 75 percent of the dependent portion. The Company offers paid vacations to employees in time increments determined by longevity and individual employment contracts. The Company policy provides a limited carry forward of vacation time not taken during the year. The Company recorded an accrued liability for compensated absences of $231,520 and $252,649 for the years ended December 31, 2018 and 2017, respectively. As of December 31, 2018, the Company had customary employment agreements with its three executive officers and several employees. Each agreement provides for an annual salary, possible annual incentive awards and benefits such as medical, dental and life insurance as described above. Each employment agreement is terminable at will by the Company provided that certain lump sum amounts and benefits are payable to the officers and employees upon death or disability or if they are terminated without cause, by the officer and employee for good reason or because of a change in control of the Company. In such events, the Company must pay certain salary termination, accrued bonus and COBRA benefits. In the unlikely event all executive officers and employees subject to employment agreements were to be terminated at once without cause, as of December 31, 2018, total costs and benefits payable by the Company could have been approximately $5.3 million, excluding acceleration of outstanding equity awards, accrued bonuses and COBRA benefits. If all executive officers and employees subject to employment agreements were to be terminated as of December 31, 2018 under the change of control provisions in the employment agreements, the total costs and benefits payable by the Company could have been approximately $8.0 million, excluding acceleration of outstanding equity awards, accrued bonuses and COBRA benefits.

FINANCIAL INSTRUMENTS WITH OFF-

FINANCIAL INSTRUMENTS WITH OFF-BALANCE SHEET RISK, CONCENTRATIONS OF CREDIT RISK, AND CONCENTRATIONS IN GEOLOGIC PROVINCES	12 Months Ended
	Dec. 31, 2018
Financial Instruments With Off-balance Sheet Risk Concentrations Of Credit Risk And Concentrations In Geologic Provinces
FINANCIAL INSTRUMENTS WITH OFF-BALANCE SHEET RISK, CONCENTRATIONS OF CREDIT RISK, AND CONCENTRATIONS IN GEOLOGIC PROVINCES	Off-Balance Sheet Risk The Company does not consider itself to have any material financial instruments with off-balance sheet risks. Concentrations of Credit Risk The Company maintains cash deposits with banks that at times exceed applicable insurance limits. The Company reduces its exposure to credit risk by maintaining such deposits with high quality financial institutions. The Company has not experienced any losses in such accounts. Substantially all of the Company’s accounts receivable result from oil and natural gas sales, joint interest billings and prospect sales to oil and natural gas industry partners. This concentration of customers, joint interest owners and oil and natural gas industry partners may impact the Company’s overall credit risk, either positively or negatively, in that these entities may be similarly affected by industry-wide changes in economic and other conditions. Such receivables are generally not collateralized; however, certain crude oil purchasers have been required to provide letters of guaranty from their parent companies. Concentrations in Geologic Provinces The Company has a portion of its crude oil production and associated infrastructure concentrated in state waters and coastal bays of Louisiana. These properties have exposure to named windstorms. The Company carries appropriate property coverage limits, but does not carry business interruption coverage for the potential lost production. The Company has changed its strategic direction to focus on onshore geological provinces which the Company believes have little or no hurricane exposure.

SALES TO MAJOR CUSTOMERS

SALES TO MAJOR CUSTOMERS	12 Months Ended
	Dec. 31, 2018
Risks and Uncertainties [Abstract]
SALES TO MAJOR CUSTOMERS	In 2018 and 2017, approximately 46% and 33%, respectively, of the Company’s natural gas, oil, and natural gas liquids production was transported and processed through pipeline and processing systems owned by EnLink Midstream Partners (formerly CrossTex Energy Partners). The Company takes steps to mitigate these risks through identification of alternative pipeline transportation. The Company expects to continue to transport a substantial portion of its future natural gas production through these pipeline systems. During the years ended December 31, 2018, and 2017, sales to five customers accounted for approximately 80% and sales to five customers accounted for approximately 79%, respectively, of the Company’s total revenues. Management believes that the loss of these customers would not have a material adverse effect on its results of operations or its financial position since the market for the Company’s production is highly liquid with other willing buyers.

SUBSEQUENT EVENTS

SUBSEQUENT EVENTS	12 Months Ended
	Dec. 31, 2018
Subsequent Events [Abstract]
SUBSEQUENT EVENTS	The Lac Blanc LP#2 well located in the Lac Blanc Field, Vermilion Parish, Louisiana went off production on February 4, 2019. Prior to going off-line, this well was producing approximately 995 net Mcf/d, or $150,000 per month in cash flow. The Company is reviewing options to put this well back online, but given its preliminary evaluation of the well, it is likely that costs could be significant, and due to the Company’s limited liquidity and the economics associated with the workover, there is no assurance the Company can fund the work. The Company will produce the well intermittently at a rate estimated to be less than 20% of the prior rate. The LP #1 and #2 are in the same reservoir so total reserves recovered from both wells are not expected to be materially impacted, but due to the disparate working interest (LP #1 and #2 of 62.5% and 100%, respectively) the Company’s net reserves would decrease should the LP #2 well not be put back into service. In addition, the Company’s cash flows will be similarly impacted by this decreased production from the LP #2 well. Additionally, the Chandeleur Sound Blk 71, SL 18194 #1 well located in Main Pass 4, Vermilion Parish, Louisiana, was shut in on February 27, 2019. The Company is evaluating workover options to restore this well to production. Due to defaults under the Company’s ISDA Agreements with SocGen and BP, all of the Company’s hedges were unwound in March 2019 (see Note 12 – Commodity Derivative Instruments). An Asset Purchase and Sale Agreement dated March 21, 2019, was executed on behalf of Pyramid Oil, LLC and Yuma Energy, Inc. (Sellers) and an undisclosed buyer (Buyer) covering the sale of all of Seller’s assets in Kern County, California. The purchase price for the sale is $2.1 million and the Buyer’s assumption of certain plugging and abandonment liabilities of approximately $864,000. The effective date is April 1, 2019, and the parties expect to close the transaction by April 26, 2019. As additional consideration for the sale of the assets, if WTI Index for oil equals or exceeds $65 in the six months following closing and maintains that average for twelve consecutive months then Buyer shall pay to the Seller $250,000. Upon closing, the Company anticipates that the proceeds will be applied to the repayment of borrowings under the credit facility and/or working capital; however, there can be no assurance that the transaction will close. By letter dated March 27, 2019, the Company’s Board of Directors notified Sam L. Banks that it was terminating him as Chief Executive Officer of the Company pursuant to the terms of his amended and restated employment agreement dated April 20, 2017 (the “Employment Agreement”). Mr. Banks continues to serve on the board of directors of the Company. On March 28, 2019, Mr. Banks filed a petition (the “Petition”) in the 189 th

SUPPLEMENTARY INFORMATION ON OI

SUPPLEMENTARY INFORMATION ON OIL AND NATURAL GAS EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES (UNAUDITED)	12 Months Ended
	Dec. 31, 2018
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
SUPPLEMENTARY INFORMATION ON OIL AND NATURAL GAS EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES (UNAUDITED)	The following supplementary information concerning the Company’s oil and natural gas exploration, development and production activities reflects only those of the Company in the years ended December 31, 2018 and 2017. Reserves Proved oil and natural gas reserves are those quantities of oil and natural gas, which, by analysis of geosciences and engineering data, can be estimated with reasonable certainty to be economically producible – from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations – prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. Based on reserve reporting rules, the price is calculated using the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period (if the first day of the month occurs on a weekend or holiday, the previous business day is used), unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. A project to extract hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. The area of the reservoir considered as proved includes: (i) the area identified by drilling and limited by fluid contacts, if any, and (ii) adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or natural gas on the basis of available geosciences and engineering data. In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons as seen in a well penetration unless geosciences, engineering or performance data and reliable technology establish a lower contact with reasonable certainty. Where direct observation from well penetrations has defined a highest known oil elevation and the potential exists for an associated natural gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geosciences, engineering or performance data and reliable technology establish the higher contact with reasonable certainty. Developed oil and natural gas reserves are reserves of any category that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well. The information below on the Company’s oil and natural gas reserves is presented in accordance with regulations prescribed by the SEC, with guidelines established by the Society of Petroleum Engineers’ Petroleum Resource Management System, as in effect as of the date of such estimates. The Company’s reserve estimates are generally based upon extrapolation of historical production trends, analogy to similar properties and volumetric calculations. Accordingly, these estimates will change as future information becomes available and as commodity prices change. Such changes could be material and could occur in the near term. The Company does not prepare engineering estimates of proved oil and natural gas reserve quantities for all wells as some wells are shut in or uneconomic and do not conform to SEC classifications. Third Party Procedures and Methods Review At December 31, 2018 and 2017, NSAI performed an independent engineering evaluation in accordance with the definitions and regulations of the SEC to obtain an independent estimate of the Company’s proved reserves and future net revenues. In preparation of the reserve report, NSAI’s review consisted of 27 fields which included the Company’s major assets in the United States and encompassed 100 percent of the Company’s proved reserves and future net cash flows as of December 31, 2018 and 2017. The Vice President – Evaluations and Engineering, and the reservoir engineering staff presented NSAI with an overview of the data, methods and assumptions used in estimating reserves and future net revenues for each field. The data presented included pertinent seismic information, geologic maps, well logs, production tests, material balance calculations, well performance data, operating expenses and other relevant economic criteria. Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves The following information has been developed utilizing procedures from the FASB concerning disclosures about oil and natural gas producing activities, and based on crude oil and natural gas reserve and production volumes estimated by NSAI. It can be used for some comparisons, but should not be the only method used to evaluate the Company or its performance. Further, the information in the following table may not represent realistic assessments of future cash flows, nor should the standardized measure of discounted future net cash flows be viewed as representative of the current value of the Company. The Company believes that the following factors should be taken into account when reviewing the following information: ● future costs and oil and natural gas sales prices will probably differ from the average annual prices required to be used in these calculations; ● due to future market conditions and governmental regulations, actual rates of production in future years may vary significantly from the rate of production assumed in the calculations; ● a 10 percent discount rate may not be reasonable as a measure of the relative risk inherent in realizing future net oil and gas revenues; and ● future net revenues may be subject to different rates of income taxation. The standardized measure of discounted future net cash flows relating to the Company’s ownership interests in proved crude oil and natural gas reserves as of year-end is shown for the Company for fiscal years 2018 and 2017. Oil and Natural Gas Exploration and Production Activities Oil and natural gas sales reflect the market prices of net production sold or transferred with appropriate adjustments for royalties, net profits interest, and other contractual provisions. Lease operating expenses include lifting costs incurred to operate and maintain productive wells and related equipment including such costs as operating labor, repairs and maintenance, materials, supplies, and fuel consumed. Production taxes include production and severance taxes. Depletion of oil and natural gas properties relates to capitalized costs incurred in acquisition, exploration, and development activities. Results of operations do not include interest expense and general corporate amounts. Costs Incurred and Capitalized Costs The costs incurred in oil and natural gas acquisition, exploration, and development activities are as follows: Years Ended December 31, 2018 2017 Costs incurred for the year: Exploration (including geological and geophysical costs) $ 1,973,043 $ 5,216,304 Development 1,323,819 2,883,801 Acquisition of properties (1) - - Capitalized overhead 733,199 1,606,910 Lease acquisition costs, net of recoveries 589,351 2,462,233 Total costs incurred $ 4,619,412 $ 12,169,248 Capitalized costs for oil and natural gas properties are as follows: December 31, 2018 2017 Oil and natural gas properties Capitalized Unproved properties $ - $ 6,794,372 Proved properties 504,139,740 494,216,531 Total oil and gas properties 504,139,740 501,010,903 Less accumulated DD&A (436,642,215 ) (421,165,400 ) Net oil and natural gas properties capitalized $ 67,497,525 $ 79,845,503 Oil and Natural Gas Reserves and Related Financial Data The following tables present the Company’s independent petroleum engineers’ estimates of proved oil and natural gas reserves, all of which are located in the United States of America. The Company emphasizes that reserves are estimates that are expected to change as additional information becomes available. Reservoir engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact way and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Proved reserves are estimated quantities of crude oil and natural gas which geological and engineering data indicate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Oil (Bbls) NGL (Bbls) Gas (Mcf) Boe Proved reserves at December 31, 2016 2,975,900 1,348,300 23,978,900 8,320,700 Revisions of previous estimates 44,100 (57,800 ) 112,100 5,000 Extension, discoveries and other additions 235,900 157,200 2,677,700 839,400 Purchases of minerals in place - - - - Sales of minerals in place (643,500 ) (22,300 ) (87,600 ) (680,400 ) Production (250,300 ) (131,200 ) (3,085,600 ) (895,800 ) Proved reserves at December 31, 2017 2,362,100 1,294,200 23,595,500 7,588,900 Revisions of previous estimates (632,100 ) (379,300 ) (4,607,200 ) (1,779,200 ) Extension, discoveries and other additions - - - - Purchases of minerals in place - - - - Sales of minerals in place (27,200 ) (4,300 ) (17,900 ) (34,500 ) Production (171,600 ) (100,200 ) (2,095,000 ) (621,000 ) Proved reserves at December 31, 2018 1,531,200 810,400 16,875,400 5,154,200 Proved developed reserves December 31, 2016 2,203,000 1,061,000 21,918,700 6,917,100 December 31, 2017 1,763,200 1,009,200 21,130,900 6,294,300 December 31, 2018 1,531,200 810,400 16,875,400 5,154,200 Proved undeveloped reserves December 31, 2016 772,900 287,300 2,060,200 1,403,600 December 31, 2017 598,900 284,900 2,464,600 1,294,600 December 31, 2018 - - - - In 2018, downward revisions of previous estimates are due to the removal of PUDs attributed to the Company’s lack of liquidity, and reduction of proved reserves in the Bayou Hebert field. These revisions were partially offset by upward revisions due to pricing, with the Pyramid field being the biggest contributor. Sales of minerals in place included the divesting of the Company’s interest in Bakken (North Dakota) in the third quarter of 2018. It should also be noted that future calculations of our proved reserves may be materially affected by recent wells that have either been shut in or gone down due to mechanical issues, due to the Company’s lack of liquidity and cash flow and the Company’s inability to restore production as wells go down. In 2017, upward revisions of previous estimates are primarily due to price increases extending the economic life of assets. These revisions were partially offset by changes in timing of production. Additions include the reactivation of the SL 18090 #2 well in the Lac Blanc Field and extensions of existing discoveries in Kern County, California. Sales of minerals in place include divesting the Company’s interest in the El Halcón Field during the second quarter of 2017and the sale of proved undeveloped reserves in Santa Barbara County, California. The twelve-month unweighted arithmetic average of the first-day-of-the-month reference prices used in the Company’s reserve estimates at December 31, 2018 and 2017 were $3.10/MMbtu and $65.56/Bbl (WTI) and $2.98/MMbtu and $51.34/Bbl (WTI) for natural gas and oil, respectively. Standardized Measure of Discounted Future Net Cash Flows The following table presents a standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves. Future cash flows were computed by applying SEC prices of oil and natural gas, which are adjusted for applicable transportation and quality differentials, to the estimated year-end quantities of those reserves. Future production and development costs were computed by estimating those expenditures expected to occur in developing and producing the proved oil and natural gas reserves at the end of the year, based on year-end costs. Actual future cash flows may vary considerably, and the standardized measure does not necessarily represent the fair value of the Company’s oil and natural gas reserves. Year Ended December 31, 2018 2017 Future cash inflows $ 186,108,775 $ 222,266,300 Future oil and natural gas operating expenses (62,571,446 ) (78,791,900 ) Future development costs (16,914,730 ) (28,980,100 ) Future income tax expenses - - Future net cash flows 106,622,599 114,494,300 10% annual discount for estimated timing of cash flows (40,566,536 ) (41,591,600 ) Standardized measure of discounted future net cash flows $ 66,056,063 $ 72,902,700 The following is a summary of the changes in the Standardized Measure for the Company’s proved oil and natural gas reserves during each of the years in the two year period ended December 31, 2018: Year Ended December 31, 2018 2017 January 1 $ 72,902,700 $ 73,600,100 Changes due to current year operation: Sales of oil and natural gas, net of oil and natural gas operating expenses (10,909,630 ) (14,406,288 ) Extensions and discoveries - 11,776,109 Purchases of oil and natural gas properties - - Development costs incurred during the period that reduced future development costs 1,323,819 3,364,636 Changes due to revisions in standardized variables: Prices and operating expenses 21,240,259 18,601,781 Income taxes - - Estimated future development costs 5,227,340 (2,252,078 ) Quantity estimates (27,220,938 ) (1,199,960 ) Sale of reserves in place (588,217 ) (5,945,688 ) Accretion of discount 7,290,270 7,360,010 Production rates, timing and other (3,209,540 ) (17,995,922 ) Net change (6,846,637 ) (697,400 ) December 31 $ 66,056,063 $ 72,902,700

SUMMARY OF SIGNIFICANT ACCOUN_2

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)	12 Months Ended
	Dec. 31, 2018
Accounting Policies [Abstract]
Management's Use of Estimates	In preparing financial statements in conformity with GAAP, management is required to make informed estimates and assumptions with consideration given to materiality. These estimates and assumptions 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 for the reporting period. Actual results could differ from these estimates, and changes in these estimates are recorded when known. Significant items subject to such estimates and assumptions include: estimates of proved reserves and related estimates of the present value of future cash flows associated with oil and gas properties; the carrying value of oil and gas properties; estimates of fair value; asset retirement obligations; income taxes; derivative financial instruments; valuation allowances for deferred tax assets; uncollectible receivables; useful lives for depreciation; obligations related to employee benefits such as accrued vacation; and legal and environmental risks and exposures.
Fair Value	Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The standard characterizes inputs used in determining fair value according to a hierarchy that prioritizes inputs based upon the degree to which they are observable. The three levels of the fair value hierarchy are as follows: Level 1 – inputs represent quoted prices in active markets for identical assets or liabilities (for example, exchange-traded commodity derivatives). Level 2 – inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly (for example, quoted market prices for similar assets or liabilities in active markets or quoted market prices for identical assets or liabilities in markets not considered to be active, inputs other than quoted prices that are observable for the asset or liability, or market-corroborated inputs). Level 3 – inputs that are not observable from objective sources, such as the Company’s internally developed assumptions about market participant assumptions used in pricing an asset or liability (for example, an estimate of future cash flows used in the Company’s internally developed present value of future cash flows model that underlies the fair value measurement). In determining fair value, the Company utilizes observable market data when available, or models that utilize observable market data. In addition to market information, the Company incorporates transaction-specific details that, in management’s judgment, market participants would take into account in measuring fair value. If the inputs used to measure the financial assets and liabilities fall within more than one level described above, the category is based on the lowest level input that is significant to the fair value measurement of the instrument (see Note 11 – Fair Value Measurements). The carrying amount of cash and cash equivalents, accounts receivable and accounts payable reported on the Consolidated Balance Sheets approximates fair value due to their short-term nature. The fair value of debt is estimated as the carrying amount of the Company’s credit facility (see Note 11 – Fair Value Measurements). Nonfinancial assets and liabilities initially measured at fair value include certain assets acquired in a business combination, asset retirement obligations and exit or disposal costs. Assets Held for Sale – the fair values of property, plant and equipment, classified as assets held for sale and related impairments are calculated using Level 3 inputs.
Cash Equivalents	Cash on hand, deposits in banks and short-term investments with original maturities of three months or less are considered cash and cash equivalents.
Trade Receivables	The Company’s accounts receivable are primarily receivables from joint interest owners and oil and natural gas purchasers. Accounts receivable are recorded at the amount due, less an allowance for doubtful accounts, when applicable. The Company establishes provisions for losses on accounts receivable if it determines that collection of all or part of the outstanding balance is doubtful. The Company regularly reviews collectability and establishes or adjusts the allowance for doubtful accounts as necessary using the specific identification method. Accounts receivable are stated net of allowance for doubtful accounts of $621,006 and $934,338 at December 31, 2018 and 2017, respectively. Management evaluates accounts receivable quarterly on an individual account basis, making individual assessments of collectability, and reserves those amounts it deems potentially uncollectible.
Derivative Instruments	The Company periodically enters into derivative contracts to hedge future crude oil and natural gas production in order to mitigate the risk of market price fluctuations. All derivatives are recognized on the balance sheet and measured at fair value. The Company does not designate its derivative contracts as hedges, as defined in ASC 815, Derivatives and Hedging
Oil and Natural Gas Properties	Oil and natural gas properties are accounted for using the full cost method of accounting, under which all productive and nonproductive costs directly associated with property acquisition, exploration and development activities are capitalized. Costs of reconditioning, repairing, or reworking producing properties are expensed as incurred. Costs of workovers adding proved reserves are capitalized. Projects to deepen existing wells, recomplete to a shallower horizon, or improve (not restore) production to proved reserves are capitalized. Sales of proved and unproved properties are accounted for as adjustments of capitalized costs with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves. Abandonments of properties are accounted for as adjustments of capitalized costs with no loss or gain recognized. Depreciation, Depletion and Amortization (“DD&A”) Impairments Unproved oil and natural gas properties not subject to amortization consist of undeveloped leaseholds, wells in progress and related capitalized interest. Management reviews the costs of these properties quarterly to determine whether and to what extent developed proved reserves have been assigned to the properties, or if an impairment has occurred, in which case the related costs, along with associated capitalized interest, are reclassified to proved properties subject to amortization. Factors considered by management in impairment assessments include drilling results by the Company and other operators, the terms of oil and gas leases not held by production, the intent to drill the project or prospect in the future, the economic viability of the development of the project or prospect, the technical evaluation of the project or prospect, as well as the available funds for exploration and development. Capitalized Interest Capitalized Internal Costs The Company develops oil and natural gas drilling projects called “prospects” by industry participants and markets participation in these projects. The Company also assembles 3-D seismic survey projects and markets participating interests in the projects. The proceeds from the sale of the 3-D seismic survey along with the quarterly G&A reimbursements are included in unproved oil and natural gas properties not subject to amortization.
Other Property and Equipment	Other property and equipment is generally recorded at cost. Expenditures for major additions and improvements are capitalized, while maintenance, repairs and minor replacements which do not improve or extend the life of such assets are charged to operations as incurred. Depreciation and amortization is calculated using the straight-line method over the estimated useful lives of the respective assets. Property and equipment sold, retired or otherwise disposed of are removed at cost less accumulated depreciation, and any resulting gain or loss is reflected in “Other” in “Other income (expense)” in the accompanying Consolidated Statements of Operations. In the event that facts and circumstances indicate that the carrying value of other property and equipment may be impaired, an evaluation of recoverability is performed. If an evaluation is required, the estimated future undiscounted cash flows associated with the asset are compared to the asset’s carrying amount to determine if a write-down to market value (measured using discounted cash flows) is required. Assets Held for Sale – The fair values of property, plant and equipment, classified as assets held for sale, are included in Other Property and Equipment. During the year, the Company recorded an impairment of $794,623 related to the write-down of the Company’s assets held for sale to the lower of carrying value and fair value less the cost to sell.
Accounts Payable	Accounts payable consist principally of trade payables and costs associated with oil and natural gas activities.
Commitments and Contingencies	Liabilities for loss contingencies arising from claims, assessments, litigation or other sources, along with liabilities for environmental remediation or restoration claims, are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated. Expenditures related to environmental matters are expensed or capitalized in accordance with the Company’s accounting policy for property and equipment.
Revenue Recognition - Adoption of ASC 606, "Revenue from Contracts with Customers"	The Company recognizes revenues to depict the transfer of control of promised goods or services to its customers in an amount that reflects the consideration to which it expects to be entitled to in exchange for those goods or services. On January 1, 2018, the Company adopted Accounting Standards Codification (“ASC”) 606 using the full retrospective method applied to those contracts which were not completed as of December 31, 2016. As a result of electing the full retrospective adoption approach as described above, results for reporting periods beginning after December 31, 2016 are presented under ASC 606. There was no material impact upon the adoption of ASC 606, and the Company did not record any adjustments to opening retained earnings as of January 1, 2017, because its revenue is primarily products sales revenue accounted for at a point in time. Crude oil and condensate are sold through month-to-month evergreen contracts. The price for Louisiana production is tied to an index or a weighted monthly average of posted prices with certain adjustments for gravity, Basic Sediment and Water (“BS&W”) and transportation. Generally, the index or posting is based on customary industry spot prices. Pricing for the Company’s California properties is based on an average of specified posted prices, adjusted for gravity and transportation. The Company’s natural gas is sold under month-to-month contracts with pricing tied to either first of the month index or a monthly weighted average of purchaser prices received. Natural gas liquids are sold under month-to-month or year-to-year contracts usually tied to the related natural gas contract. Pricing is based on published prices for each product or a monthly weighted average of purchaser prices received. Sales of crude oil, condensates, natural gas and natural gas liquids (“NGLs”) are recognized at the point control of the product is transferred to the customer. Virtually all of the Company’s contracts’ pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality of the oil or natural gas, and prevailing supply and demand conditions. As a result, the price of the crude oil, condensate, natural gas, and NGLs fluctuates to remain competitive with other available crude oil, natural gas, and NGLs supplies. Revenue is measured based on consideration specified in the contract with the customer, and excludes any amounts collected on behalf of third parties. The Company recognizes revenue in the amount that reflects the consideration it expects to be entitled to in exchange for transferring control of those goods to the customer. The contract consideration in the Company’s variable price contracts is typically allocated to specific performance obligations in the contract according to the price stated in the contract. Amounts allocated in the Company’s fixed price contracts are based on the stand-alone selling price of those products in the context of long-term, fixed price contracts, which generally approximates the contract price. The Company records revenue in the month production is delivered to the purchaser. However, settlement statements for certain natural gas and NGL sales may not be received for 30 to 90 days after the date production is delivered, and as a result, the Company is required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. The Company records the differences between its estimates and the actual amounts received for product sales in the month that payment is received from the purchaser. Any identified differences between its revenue estimates and actual revenue received historically have not been significant. For the year ended December 31, 2017 and the year ended December 31, 2018, revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material. Gain or loss on derivative instruments is outside the scope of ASC 606 and is not considered revenue from contracts with customers subject to ASC 606. The Company may use financial or physical contracts accounted for as derivatives as economic hedges to manage price risk associated with normal sales, or in limited cases may use them for contracts the Company intends to physically settle but do not meet all of the criteria to be treated as normal sales. Natural Gas and Natural Gas Liquids Sales Under the Company’s natural gas processing contracts, it delivers natural gas to a midstream processing entity at the wellhead or the inlet of the midstream processing entity’s system. The midstream processing entity gathers and processes the natural gas and remits proceeds to the Company for the resulting sales of NGLs and residue gas. In these scenarios, the Company evaluates whether it is the principal or the agent in the transaction. For those contracts where the Company has concluded it is the principal and the ultimate third party is its customer, the Company recognizes revenue on a gross basis, with transportation, gathering, processing and compression fees presented as an expense in its lease operating and production costs in the Consolidated Statements of Operations. In certain natural gas processing agreements, the Company may elect to take its residue gas and/or NGLs in-kind at the tailgate of the midstream entity’s processing plant and subsequently market the product. Through the marketing process, the Company delivers product to the ultimate third-party purchaser at a contractually agreed-upon delivery point and receives a specified index price from the purchaser. In this scenario, the Company recognizes revenue when control transfers to the purchaser at the delivery point based on the index price received from the purchaser. The gathering, processing and compression fees attributable to the gas processing contract, as well as any transportation fees incurred to deliver the product to the purchaser, are presented as lease operating and production costs in the Consolidated Statements of Operations. Crude Oil and Condensate Sales The Company sells oil production at the wellhead and collects an agreed-upon index price, net of pricing differentials. In this scenario, revenue is recognized when control transfers to the purchaser at the wellhead at the net price received. The following table presents the Company’s revenues disaggregated by product source. Sales taxes are excluded from revenues. Years Ended December 31, 2018 2017 Sales of natural gas and crude oil: Crude oil and condensate $ 11,565,706 $ 12,596,983 Natural gas 6,678,666 9,425,676 Natural gas liquids 3,226,721 3,420,942 Total revenues $ 21,471,093 $ 25,443,601 Transaction Price Allocated to Remaining Performance Obligations A significant number of the Company’s product sales are short-term in nature with a contract term of one year or less. For those contracts, the Company has utilized the practical expedient in ASC 606-10-50-14 exempting the Company from disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less. For the Company’s product sales that have a contract term greater than one year, it has utilized the practical expedient in ASC 606-10-50-14(a) which states that the Company is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under these sales contracts, each unit of product generally represents a separate performance obligation; therefore future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required. Contract Balances Receivables from contracts with customers are recorded when the right to consideration becomes unconditional, generally when control of the product has been transferred to the customer. Receivables from contracts with customers were $2,282,200 and $2,636,867 as of December 31, 2018 and December 31, 2017, respectively, and are reported in trade accounts receivable, net on the Consolidated Balance Sheets. The Company currently has no other assets or liabilities related to its revenue contracts, including no upfront or rights to deficiency payments. Practical Expedients The Company has made use of certain practical expedients in adopting ASC 606, including not disclosing the value of unsatisfied performance obligations for (i) contracts with an original expected length of one year or less, (ii) contracts for which the Company recognizes revenue at the amount to which the Company has the right to invoice, (iii) variable consideration which is allocated entirely to a wholly unsatisfied performance obligation and meets the variable allocation criteria in the standard and (iv) only contracts that are not completed at transition. The Company has not adjusted the promised amount of consideration for the effects of a significant financing component if the Company expects, at contract inception, that the period between when the Company transfers a promised good or service to the customer and when the customer pays for that good or service will be one year or less.
Income Taxes	The Company files a consolidated federal tax return. Deferred taxes have been provided for temporary timing differences. These differences create taxable or tax-deductible amounts for future periods. Income taxes are provided based on earnings reported for tax return purposes in addition to a provision for deferred income taxes. Deferred income taxes are provided to reflect the tax consequences in future years of differences between the financial statement and tax bases of assets and liabilities. A valuation allowance is established to reduce deferred tax assets if it is more likely-than-not that the related tax benefits will not be realized (see Note 18 – Income Taxes).
Other Taxes	The Company reports oil and natural gas sales on a gross basis and, accordingly, includes net production, severance, and ad valorem taxes on the accompanying Consolidated Statements of Operations as a component of lease operating expenses. The Company accrues sales tax on applicable purchases of materials, and remits funds directly to the taxing jurisdictions.
General and Administrative Expenses - Stock-Based Compensation	This includes payments to employees in the form of restricted stock awards, restricted stock units, stock appreciation rights and stock options. As such, these amounts are non-cash Company stock-based awards. The Company adopted the 2014 Long-Term Incentive Plan effective October 26, 2016, and adopted an Annual Incentive Plan for fiscal year 2017 . The Company adopted the 2018 Long-Term Incentive Plan effective June 7, 2018 (see Note 14 – Stock-Based Compensation). The Company grants both liability classified and equity-classified awards including stock options, stock appreciation rights, as well as vested and non-vested equity shares (restricted stock awards and units). The fair value of stock option awards and stock appreciation rights is determined using the Black-Scholes option-pricing model. Restricted stock awards and units are valued using the Company’s stock price on the grant date. The Company records compensation cost, net of estimated forfeitures, for non-vested stock units over the requisite service period using the straight-line method. An adjustment is made to compensation cost for any difference between the estimated forfeitures and the actual forfeitures related to the awards. For liability-classified share-based compensation awards, expense is recognized for those awards expected to ultimately be paid. The amount of expense reported for liability-classified awards is adjusted for fair-value changes so that the expense recognized for each award is equivalent to the amount to be paid (see Note 14 – Stock-Based Compensation).
Other Noncurrent Assets	Other noncurrent assets at December 31, 2018 are comprised of $79,997 related to the S-3 offering. In 2017, the balance included $254,894 of deferred debt issuance costs related to the establishment of the new Société Générale (“SocGen”) credit facility which expires on October 26, 2019, and S-3 offering costs of $15,948.
Earnings per Share	The Company’s basic earnings per share (“EPS”) is computed based on the weighted average number of shares of common stock outstanding for the period. Diluted EPS includes the effect of the Company’s outstanding stock awards, if the inclusion of these items is dilutive (see Note 15 – Net Income (Loss) per Common Share).
Treasury Stock	The Company records treasury stock purchases at cost. Amounts are recorded as reductions to stockholders’ equity. Shares of common stock are repurchased by the Company as they are surrendered by employees to pay withholding tax upon the vesting of restricted stock awards.
Recently Issued Accounting Pronouncements	The accounting standard-setting organizations frequently issue new or revised accounting rules. The Company regularly reviews new pronouncements to determine their impact, if any, on the financial statements. Accounting Pronouncement Yet to Be Adopted In February 2016, the FASB issued ASU 2016-02, Leases (ASC Topic 842). Under this guidance, lessees are required to recognize on the balance sheet a lease liability and a right-of-use asset for all leases, with the exception of short-term leases with terms of twelve months or less. The lease liability represents the lessee’s obligation to make lease payments arising from a lease, and will be measured as the present value of the lease payments. The right-of-use asset represents the lessee’s right to use a specified asset for the lease term, and will be measured at the lease liability amount, adjusted for lease prepayment, lease incentives received and the lessee’s initial direct costs. The new guidance is effective for fiscal years beginning after December 15, 2018. The Company plans to adopt this guidance in the first quarter of 2019 using the optional transition method. Consequently, the Company's reporting for the comparative periods presented in the financial statements will continue to be in accordance with ASC Topic 840, Leases. The adoption of this guidance will result in the addition of right-of-use assets and corresponding lease obligations to the consolidated balance sheet and will not have a material impact on the Company’s results of operations or cash flows. The Company has substantially completed its evaluation of the impact on the Company’s lease portfolio. ASU 2016-02 provides for certain practical expedients when adopting the guidance. The Company plans to elect the package of practical expedients allowing the Company to not reassess whether any expired or existing contracts are, or contain, leases, the lease classification for any expired or existing leases or initial direct costs for any expired or existing leases. The Company also plans to apply the hindsight practical expedient allowing the Company to use hindsight when determining the lease term (i.e., evaluating the Company’s option to renew or terminate the lease or to purchase the underlying asset) and assessing impairment of expired or existing leases. The Company additionally plans to apply the land easements practical expedient allowing the Company to not assess whether any expired or existing land easements are, or contain, leases if they were not previously accounted for as leases under the existing leasing guidance. Instead, it will continue to apply its existing accounting policies to historical land easements. The Company also elects to apply the short-term lease exception, therefore it will not record a right-of-use asset or corresponding lease liability for leases with a term of twelve months or less and instead recognize a single lease cost allocated over the lease term, generally on a straight-line basis. The Company plans to elect the practical expedient to not separate lease components from non-lease components and instead account for both as a single lease component for all asset classes. As part of the Company’s assessment, it formed an implementation work team, conducted training for the relevant staff regarding the potential impacts of Topic 842 and has concluded its contract analyses and policy review. The Company engaged external resources to assist in its efforts to complete the analysis of potential changes to current accounting practices and is in the process of implementing a new lease accounting system in connection with the adoption of the updated guidance. The Company also evaluated the impact of Topic 842 on its internal control over financial reporting and other changes in business practices and processes. The Company is in the process of finalizing its catalog of existing lease contracts and implementing changes to its systems. Upon adoption, the Company expects to record operating lease right-of-use assets of approximately $4.1 million representing the present value of future lease payments under operating leases with terms of greater than twelve months. The Company is continuing to evaluate the impact the pronouncement will have on the related disclosures. Accounting Pronouncements Recently Adopted In August 2016, the FASB issued ASU 2016-15, “Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments,” which provides clarification on how certain cash receipts and cash payments are presented and classified on the statement of cash flows. This ASU is effective for annual and interim periods beginning after December 15, 2017 and is required to be adopted using a retrospective approach if practicable, with early adoption permitted. The Company adopted this update, as required, beginning in the first quarter of 2018, and the adoption did not have a material impact on its consolidated financial statements. In January 2017, the FASB issued ASU 2017-01, “Business Combinations (Topic 805): Clarifying the Definition of a Business,” which assists in determining whether a transaction should be accounted for as an acquisition or disposal of assets or as a business. This ASU is effective for annual and interim periods beginning in 2018 and is required to be adopted using a prospective approach, with early adoption permitted for transactions not previously reported in issued financial statements. The Company adopted this ASU on January 1, 2017, and expects that the adoption of this ASU could have a material impact on future consolidated financial statements, as future oil and gas asset acquisitions may not be considered businesses. In March 2016, the FASB issued ASU 2016-09, “Compensation—Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting,” In May 2014, the FASB issued ASU 2014 09 “Revenue from Contracts with Customers” (Topic 606) (ASC 606, as subsequently amended). ASC 606 supersedes the revenue recognition requirements in topic 605, Revenue Recognition, and requires entities to recognize revenue when control of the promised goods or services is transferred to customers at an amount that reflects the consideration to which an entity expects to be entitled to in exchange for those goods or services. The Company adopted ASC 606 with an effective date of January 2018 using the full retrospective approach. For public entities, ASC 606 became effective for fiscal years beginning after December 15, 2017. The adoption of this standard did not have a material effect on the Company’s consolidated results of operations, financial position or cash flows.

ORGANIZATION AND BASIS OF PRE_2

ORGANIZATION AND BASIS OF PRESENTATION (Tables)	12 Months Ended
	Dec. 31, 2018
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Incorporated date	State of Date of Company Name Reference Incorporation Incorporation The Yuma Companies, Inc. “YCI” Delaware 10/30/1996 Yuma Exploration and Production Company, Inc. “Exploration” Delaware 01/16/1992 Davis Petroleum Acquisition Corp. “DPAC” Delaware 01/18/2006 Davis Petroleum Pipeline LLC “DPP” Delaware 11/15/1999 Davis GOM Holdings, LLC “Davis GOM” Delaware 07/25/2014 Davis Petroleum Corp. “DPC” Delaware 07/08/1986 Yuma Petroleum Company “Petroleum” Delaware 12/19/1991 Texas Southeastern Gas Marketing Company “TSM” Texas 09/12/1996 Pyramid Oil LLC “POL” California 08/08/2014

SUMMARY OF SIGNIFICANT ACCOUN_3

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Tables)	12 Months Ended
	Dec. 31, 2018
Accounting Policies [Abstract]
Disaggregation of revenue	Years Ended December 31, 2018 2017 Sales of natural gas and crude oil: Crude oil and condensate $ 11,565,706 $ 12,596,983 Natural gas 6,678,666 9,425,676 Natural gas liquids 3,226,721 3,420,942 Total revenues $ 21,471,093 $ 25,443,601

PREPAYMENTS (Tables)

PREPAYMENTS (Tables)	12 Months Ended
	Dec. 31, 2018
Prepaid Expense and Other Assets [Abstract]
Prepayments	December 31, 2018 2017 Prepaid insurance $ 1,009,216 $ 828,648 Prepaid taxes 1,394 28,158 Other prepayments 141,516 119,656 Total prepayments $ 1,152,126 $ 976,462

PROPERTY, PLANT, AND EQUIPMEN_2

PROPERTY, PLANT, AND EQUIPMENT, NET (Tables)	12 Months Ended
	Dec. 31, 2018
Property, Plant and Equipment, Net [Abstract]
Property, plant and equipment	December 31, 2018 2017 Subject to amortization (proved properties) $ 504,139,740 $ 494,216,531 Less: Accumulated depreciation, depletion, and amortization (436,642,215 ) (421,165,400 ) Proved properties, net $ 67,497,525 $ 73,051,131 Not subject to amortization (unproved properties) Leasehold acquisition costs - 3,133,162 Exploration and development - 3,368,339 Capitalized Interest - 292,871 Total unproved properties - 6,794,372 Oil and gas properties, net $ 67,497,525 $ 79,845,503 Year Incurred 2018 2017 and prior Leasehold acquisition costs $ - $ 3,133,162 Exploration and development - 3,368,339 Capitalized interest - 292,871 Total $ - $ 6,794,372 Estimated useful December 31, life in years 2018 2017 Land n/a $ - $ 1,314,000 Software and IT equipment 3 - 5 979,389 979,389 Drilling and operating equipment 15 - 837,013 Furniture and fixtures 7 - 10 704,758 712,692 Buildings 25 - 286,000 Automobiles 3 - 7 24,990 232,105 Office leasehold improvements 10 84,260 84,260 Total other property and equipment 1,793,397 4,445,459 Less: Accumulated depreciation and leasehold improvement amortization (1,355,639 ) (1,409,535 Net book value $ 437,758 $ 3,035,924

ASSET RETIREMENT OBLIGATIONS (T

ASSET RETIREMENT OBLIGATIONS (Tables)	12 Months Ended
	Dec. 31, 2018
Asset Retirement Obligation Disclosure [Abstract]
Asset retirement obligations	December 31, 2018 2017 Beginning of year balance $ 10,466,413 $ 10,196,383 Liabilities incurred during year 69,021 6,663 Liabilities settled during year (295,146 ) (389,765 ) Liabilities sold during year (15,203 ) (418,527 ) Accretion expense 560,922 557,683 Revisions in estimated cash flows 485,852 513,976 End of year balance $ 11,271,859 $ 10,466,413

ACCOUNTS RECEIVABLE FROM CHIE_2

ACCOUNTS RECEIVABLE FROM CHIEF EXECUTIVE OFFICER AND EMPLOYEES (Tables)	12 Months Ended
	Dec. 31, 2018
Accounts Receivable, after Allowance for Credit Loss [Abstract]
Information with respect to related party transactions with affiliates	December 31, 2018 2017 Receivables from CEO and employees: Current: CEO $ 12,748 $ 53,979 Employees - - Total $ 12,748 $ 53,979

FAIR VALUE MEASUREMENTS (Tables

FAIR VALUE MEASUREMENTS (Tables)	12 Months Ended
	Dec. 31, 2018
Fair Value Disclosures [Abstract]
Fair value measurements by hierarchy	Fair value measurements at December 31, 2018 Significant Quoted prices other Significant in active observable unobservable markets inputs inputs (Level 1) (Level 2) (Level 3) Total Assets: Commodity derivatives – oil $ - $ 922,562 $ - $ 922,562 Commodity derivatives – gas - (158,376 ) - $ (158,376 ) Total liabilities $ - $ 764,186 $ - $ 764,186 Fair value measurements at December 31, 2017 Significant Quoted prices other Significant in active observable unobservable markets inputs inputs (Level 1) (Level 2) (Level 3) Total Liabilities: Commodity derivatives – oil $ - $ 1,517,410 $ - $ 1,517,410 Commodity derivatives – gas - (278,001 ) - $ (278,001 ) Total liabilities $ - $ 1,239,409 $ - $ 1,239,409

COMMODITY DERIVATIVE INSTRUME_2

COMMODITY DERIVATIVE INSTRUMENTS (Tables)	12 Months Ended
	Dec. 31, 2018
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Commodity derivative instruments	2019 2020 Settlement Settlement NATURAL GAS (MMBtu): Swaps Volume 1,660,297 1,095,430 Price $ 2.75 $ 2.68 CRUDE OIL (Bbls): Swaps Volume 139,823 Price $ 53.95
Schedule of derivative assets and liablities	Fair value as of December 31, 2018 2017 Asset commodity derivatives: Current assets $ 1,031,614 $ 295,304 Noncurrent assets 98,530 118 1,130,144 295,422 Liability commodity derivatives: Current liabilities (280,456 ) (1,198,307 ) Noncurrent liabilities (85,502 ) (336,524 ) (365,958 ) (1,534,831 ) Total commodity derivative instruments $ 764,186 $ (1,239,409 )
Gains (losses) from commodity derivatives	Years Ended December 31, 2018 2017 Derivative settlements $ (2,419,303 ) $ 1,238,341 Mark to market on commodity derivatives 2,003,595 1,316,593 Net gains (losses) from commodity derivatives $ (415,708 ) $ 2,554,934

STOCK-BASED COMPENSATION (Table

STOCK-BASED COMPENSATION (Tables)	12 Months Ended
	Dec. 31, 2018
Summary of the Company's share based compensation activity	Weighted- Weighted- average average remaining Aggregate exercise contractual intrinsic Options price life (years) value Outstanding at December 31, 2017 898,617 $ 3.12 9.25 $ - Granted - - - - Exercised - - - - Forfeited - - - - Expired (5,000 ) $ 103.20 - - Outstanding at December 31, 2018 893,617 $ 2.56 8.30 $ - Vested at December 31, 2018 297,874 $ 2.56 8.30 $ - Exercisable at December 31, 2018 297,874 $ 2.56 8.30 $ -
Restricted Stock Awards (RSAs) [Member]
Summary of the Company's share based compensation activity	Number of Weighted average unvested grant-date RSA shares fair value Unvested shares as of January 1, 2018 274,450 $2.78 per share Granted on February 6, 2018 930,916 $1.15 per share Vested on February 6, 2018 (930,916 ) $1.15 per share Vested on February 6, 2018 (80,687 ) $1.15 per share Vested on May 31, 2018 (31,147 ) $0.40 per share Vested on July 20, 2018 (1,250 ) $0.46 per share Forfeited (17,056 ) $2.56 per share Unvested shares as of December 31, 2018 144,310 $2.56 per share
Stock Appreciation Rights (SARs) [Member]
Summary of the Company's share based compensation activity	Weighted Number of average unvested grant-date SARs fair value Unvested shares as of January 1, 2018 28,081 $2.35 per share Vested on May 31, 2018 (28,081 ) $2.35 per share Forfeited - Unvested shares as of December 31, 2018 - Number of unvested Weighted average SARs fair value Unvested shares as of January 1, 2018 1,623,371 $0.06 per share Vested February 6, 2018 (159,092 ) $0.06 per share Forfeited - Unvested shares as of December 31, 2018 1,464,279 $0.06 per share

NET INCOME (LOSS) PER COMMON _2

NET INCOME (LOSS) PER COMMON SHARE (Tables)	12 Months Ended
	Dec. 31, 2018
LOSS PER COMMON SHARE:
Reconciliation of loss per common share	Years Ended December 31, 2018 2017 Net loss attributable to common stockholders $ (17,070,271 ) $ (6,806,633 ) Net loss per common share: Basic $ (0.74 ) $ (0.46 ) Diluted $ (0.74 ) $ (0.46 ) Weighted average common shares outstanding Basic 23,023,066 14,815,991 Add potentially dilutive securities: Unvested restricted stock awards - - Stock appreciation rights - - Stock options - - Series D preferred stock - - Diluted weighted average common shares outstanding 23,023,066 14,815,991

DEBT AND INTEREST EXPENS (Table

DEBT AND INTEREST EXPENS (Tables)	12 Months Ended
	Dec. 31, 2018
Debt Disclosure [Abstract]
Long term debt	December 31, 2018 2017 Senior credit facility $ 34,000,000 $ 27,700,000 Installment loan due 7/22/19 originating from the financing of insurance premiums at 6.14% interest rate 742,953 - Installment loan due 7/22/18 originating from the financing of insurance premiums at 5.14% interest rate - 651,124 Total debt 34,742,953 28,351,124 Less: current maturities (34,742,953 ) (651,124 ) Total long-term debt $ - $ 27,700,000

INCOME TAXES (Tables)

INCOME TAXES (Tables)	12 Months Ended
	Dec. 31, 2018
Income Tax Disclosure [Abstract]
Provisions for income taxes	December 31, 2018 2017 Current expense (benefit) Federal $ - $ - State - - Deferred expense (benefit) Federal - - State - - Total income tax expense $ - $ -
Reconciliation of the federal statutory income tax rate	December 31, 2018 2017 U.S. statutory rate 21.00 % 35.00 % State income taxes (net of federal benefit) 6.96 % (9.21 %) Nondeductible transaction costs 0.00 % (1.61 %) Stock compensation 0.00 % (0.03 %) Prior year differences 0.00 % 7.38 % Change in tax rates 0.00 % (429.43 %) Valuation allowance (27.91 %) 397.96 % Other (0.05 %) (0.06 %) Effective tax rate (0.00 %) 0.00 %
Deferred tax (liabilities) assets	December 31, 2018 2017 Deferred income tax liabilities Property and equipment $ (4,884,966 ) $ (4,599,347 ) Commodity derivative instruments (130,856 ) - (5,015,822 ) (4,599,347 ) Deferred income tax assets Net operating loss carryforward 46,370,912 41,368,982 Commodity derivative instruments - 326,893 Financial accruals and other 145,031 246,001 Asset retirement obligation 2,789,434 2,476,370 Stock-based compensation 141,759 270,366 Valuation allowance (44,431,314 ) (40,089,265 ) 5,015,822 4,599,347 Deferred income taxes, net $ - $ -

COMMITMENTS AND CONTINGENCIES (

COMMITMENTS AND CONTINGENCIES (Tables)	12 Months Ended
	Dec. 31, 2018
Commitments and Contingencies Disclosure [Abstract]
Future minimum rentals under all noncancellable leases	2019 $ 532,147 2020 $ 520,297 2021 $ 524,044 2022 $ 530,990 2023 $ 351,392

SUPPLEMENTARY INFORMATION ON _2

SUPPLEMENTARY INFORMATION ON OIL AND NATURAL GAS EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES (UNAUDITED) (Tables)	12 Months Ended
	Dec. 31, 2018
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Costs incurred	Years Ended December 31, 2018 2017 Costs incurred for the year: Exploration (including geological and geophysical costs) $ 1,973,043 $ 5,216,304 Development 1,323,819 2,883,801 Acquisition of properties (1) - - Capitalized overhead 733,199 1,606,910 Lease acquisition costs, net of recoveries 589,351 2,462,233 Total costs incurred $ 4,619,412 $ 12,169,248
Capitalized costs relating to oil and gas producing activities	December 31, 2018 2017 Oil and natural gas properties Capitalized Unproved properties $ - $ 6,794,372 Proved properties 504,139,740 494,216,531 Total oil and gas properties 504,139,740 501,010,903 Less accumulated DD&A (436,642,215 ) (421,165,400 ) Net oil and natural gas properties capitalized $ 67,497,525 $ 79,845,503
Reserves	Oil (Bbls) NGL (Bbls) Gas (Mcf) Boe Proved reserves at December 31, 2016 2,975,900 1,348,300 23,978,900 8,320,700 Revisions of previous estimates 44,100 (57,800 ) 112,100 5,000 Extension, discoveries and other additions 235,900 157,200 2,677,700 839,400 Purchases of minerals in place - - - - Sales of minerals in place (643,500 ) (22,300 ) (87,600 ) (680,400 ) Production (250,300 ) (131,200 ) (3,085,600 ) (895,800 ) Proved reserves at December 31, 2017 2,362,100 1,294,200 23,595,500 7,588,900 Revisions of previous estimates (632,100 ) (379,300 ) (4,607,200 ) (1,779,200 ) Extension, discoveries and other additions - - - - Purchases of minerals in place - - - - Sales of minerals in place (27,200 ) (4,300 ) (17,900 ) (34,500 ) Production (171,600 ) (100,200 ) (2,095,000 ) (621,000 ) Proved reserves at December 31, 2018 1,531,200 810,400 16,875,400 5,154,200 Proved developed reserves December 31, 2016 2,203,000 1,061,000 21,918,700 6,917,100 December 31, 2017 1,763,200 1,009,200 21,130,900 6,294,300 December 31, 2018 1,531,200 810,400 16,875,400 5,154,200 Proved undeveloped reserves December 31, 2016 772,900 287,300 2,060,200 1,403,600 December 31, 2017 598,900 284,900 2,464,600 1,294,600 December 31, 2018 - - - -
Discounted future net cash flows	Year Ended December 31, 2018 2017 Future cash inflows $ 186,108,775 $ 222,266,300 Future oil and natural gas operating expenses (62,571,446 ) (78,791,900 ) Future development costs (16,914,730 ) (28,980,100 ) Future income tax expenses - - Future net cash flows 106,622,599 114,494,300 10% annual discount for estimated timing of cash flows (40,566,536 ) (41,591,600 ) Standardized measure of discounted future net cash flows $ 66,056,063 $ 72,902,700
Change in standardized easure	Year Ended December 31, 2018 2017 January 1 $ 72,902,700 $ 73,600,100 Changes due to current year operation: Sales of oil and natural gas, net of oil and natural gas operating expenses (10,909,630 ) (14,406,288 ) Extensions and discoveries - 11,776,109 Purchases of oil and natural gas properties - - Development costs incurred during the period that reduced future development costs 1,323,819 3,364,636 Changes due to revisions in standardized variables: Prices and operating expenses 21,240,259 18,601,781 Income taxes - - Estimated future development costs 5,227,340 (2,252,078 ) Quantity estimates (27,220,938 ) (1,199,960 ) Sale of reserves in place (588,217 ) (5,945,688 ) Accretion of discount 7,290,270 7,360,010 Production rates, timing and other (3,209,540 ) (17,995,922 ) Net change (6,846,637 ) (697,400 ) December 31 $ 66,056,063 $ 72,902,700

ORGANIZATION AND BASIS OF PRE_3

ORGANIZATION AND BASIS OF PRESENTATION (Details)	12 Months Ended
	Dec. 31, 2018
The Yuma Companies, Inc. [Member]
Reference	“YCI”
State of incorporation	Delaware
Date of incorporation	Oct. 30, 1996
Yuma Exploration and Production Company, Inc. [Member]
Reference	“Exploration”
State of incorporation	Delaware
Date of incorporation	Jan. 16, 1992
Davis Petroleum Acquisition Corp. [Member]
Reference	“DPAC”
State of incorporation	Delaware
Date of incorporation	Jan. 18, 2006
Davis Petroleum Pipeline LLC [Member]
Reference	“DPP”
State of incorporation	Delaware
Date of incorporation	Nov. 15, 1999
Davis GOM Holdings, LLC [Member]
Reference	“Davis GOM”
State of incorporation	Delaware
Date of incorporation	Jul. 25, 2014
Davis Petroleum Corp. [Member]
Reference	“DPC”
State of incorporation	Delaware
Date of incorporation	Jul. 8, 1986
Yuma Petroleum Company [Member]
Reference	“Petroleum”
State of incorporation	Delaware
Date of incorporation	Dec. 19, 1991
Texas Southeastern Gas Marketing Company [Member]
Reference	“TSM”
State of incorporation	Texas
Date of incorporation	Sep. 12, 1996
Pyramid Oil LLC [Member]
Reference	“POL”
State of incorporation	California
Date of incorporation	Aug. 8, 2014

SUMMARY OF SIGNIFICANT ACCOUN_4

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details) - USD ($)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Sales of natural gas and crude oil	$ 21,471,093	$ 25,443,601
Crude oil and condensate
Sales of natural gas and crude oil	11,565,706	12,596,983
Natural gas
Sales of natural gas and crude oil	6,678,666	9,425,676
Natural gas liquids
Sales of natural gas and crude oil	$ 3,226,721	$ 3,420,942

SUMMARY OF SIGNIFICANT ACCOUN_5

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details Narrative) - USD ($)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Accounting Policies [Abstract]
Allowance for doubtful accounts	$ 621,006	$ 934,338
Depreciation, depletion and amortization rate per boe	$13.57 per Boe	$11.97 per Boe
Depreciation, depletion and amortization expense for oil and natural gas properties	$ 8,427,599	$ 10,724,967
Capitalized interest associated with line of credit	133,772	317,691
Capitalized internal costs	733,199	1,606,910
Impairment of other property and equipment	$ 794,623	$ 0

PREPAYMENTS (Details)

PREPAYMENTS (Details) - USD ($)	Dec. 31, 2018	Dec. 31, 2017
Prepaid Expense and Other Assets [Abstract]
Prepaid insurance	$ 1,009,216	$ 828,648
Prepaid taxes	1,394	28,158
Other prepayments	141,516	119,656
Total prepayments	$ 1,152,126	$ 976,462

ASSET IMPAIRMENTS (Details Narr

ASSET IMPAIRMENTS (Details Narrative) - USD ($)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Asset Impairments
Oil and gas impairment	$ 7,049,216	$ 0

PROPERTY, PLANT, AND EQUIPMEN_3

PROPERTY, PLANT, AND EQUIPMENT, NET (Details) - USD ($)	Dec. 31, 2018	Dec. 31, 2017
Property, Plant and Equipment, Net [Abstract]
Subject to amortization (proved properties)	$ 504,139,740	$ 494,216,531
Less: Accumulated depreciation, depletion, amortization and impairment	436,642,215	421,165,400
Proved properties, net	67,497,525	73,051,131
Not subject to amortization (unproved properties)
Leasehold acquisition costs	0	3,133,162
Exploration and development	0	3,368,339
Capitalized Interest	0	292,871
Total unproved properties	0	6,794,372
Oil and gas properties, net	$ 67,497,525	$ 79,845,503

PROPERTY, PLANT, AND EQUIPMEN_4

PROPERTY, PLANT, AND EQUIPMENT, NET (Details 1) - USD ($)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Property, Plant and Equipment, Net [Abstract]
Leasehold acquisition cost	$ 0	$ 3,133,162
Exploration and development cost	0	3,368,339
Capitalized interest	0	292,871
Total	$ 0	$ 6,794,372

PROPERTY, PLANT, AND EQUIPMEN_5

PROPERTY, PLANT, AND EQUIPMENT, NET (Details 2) - USD ($)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Land	$ 0	$ 1,314,000
Software and IT equipment	979,389	979,389
Drilling and operating equipment	0	837,013
Furniture and fixtures	704,758	712,692
Buildings	0	286,000
Automotive	24,990	232,105
Office leasehold improvements	84,260	84,260
Total other property and equipment	1,793,397	4,445,459
Less: Accumulated depreciation and leasehold improvement amortization	(1,355,639)	(1,409,535)
Net book value	$ 437,758	$ 3,035,924
Software and IT equipment [Member] | Minimum [Member]
Estimated useful life in years	3 years
Software and IT equipment [Member] | Maximum [Member]
Estimated useful life in years	5 years
Drilling and operating equipment [Member]
Estimated useful life in years	15 years
Furniture and fixtures [Member] | Minimum [Member]
Estimated useful life in years	7 years
Furniture and fixtures [Member] | Maximum [Member]
Estimated useful life in years	10 years
Buildings [Member]
Estimated useful life in years	25 years
Automotive [Member] | Minimum [Member]
Estimated useful life in years	3 years
Automotive [Member] | Maximum [Member]
Estimated useful life in years	7 years
Office leasehold improvements [Member]
Estimated useful life in years	10 years

PROPERTY, PLANT, AND EQUIPMEN_6

PROPERTY, PLANT, AND EQUIPMENT, NET (Details Narrative) - USD ($)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Property, Plant and Equipment, Net [Abstract]
Depreciation and leasehold improvement amortization expense	$ 111,955	$ 230,236

ASSET RETIREMENT OBLIGATIONS (D

ASSET RETIREMENT OBLIGATIONS (Details) - USD ($)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Asset Retirement Obligation Disclosure [Abstract]
Beginning of year balance	$ 10,466,413	$ 10,196,383
Liabilities incurred during year	69,021	6,663
Liabilities settled during year	(295,146)	(389,765)
Liabilities sold during year	(15,203)	(418,527)
Accretion expense	560,922	557,683
Revisions in estimated cash flows	485,852	513,976
End of year balance	$ 11,271,859	$ 10,466,413

ACCOUNTS RECEIVABLE FROM CHIE_3

ACCOUNTS RECEIVABLE FROM CHIEF EXECUTIVE OFFICER AND EMPLOYEES (Details) - USD ($)	Dec. 31, 2018	Dec. 31, 2017
Current	$ 12,748	$ 53,979
Yuma CEO [Member]
Current	12,748	53,979
Employee [Member]
Current	$ 0	$ 0

FAIR VALUE MEASUREMENTS (Detail

FAIR VALUE MEASUREMENTS (Details) - USD ($)	Dec. 31, 2018	Dec. 31, 2017
Total liabilities	$ 764,186	$ 1,239,409
Commodity derivatives oil
Total liabilities	922,562	1,517,410
Commodity derivatives gas
Total liabilities	(158,376)	(278,001)
Level 1
Total liabilities	0	0
Level 1 | Commodity derivatives oil
Total liabilities	0	0
Level 1 | Commodity derivatives gas
Total liabilities	0	0
Level 2
Total liabilities	764,186	1,239,409
Level 2 | Commodity derivatives oil
Total liabilities	922,562	1,517,410
Level 2 | Commodity derivatives gas
Total liabilities	(158,376)	(278,001)
Level 3
Total liabilities	0	0
Level 3 | Commodity derivatives oil
Total liabilities	0	0
Level 3 | Commodity derivatives gas
Total liabilities	$ 0	$ 0

COMMODITY DERIVATIVE INSTRUME_3

COMMODITY DERIVATIVE INSTRUMENTS (Details) - Swaps	12 Months Ended
	Dec. 31, 2020MMBbls	Dec. 31, 2019bblMMBbls
Natural Gas (MMBtu):
Volume | MMBbls	1,095,430	1,660,297
Price	$2.68 per MMBtu	$2.75 per MMBtu
Crude Oil:
Volume | bbl		139,823
Price		$53.95 per barrel

COMMODITY DERIVATIVE INSTRUME_4

COMMODITY DERIVATIVE INSTRUMENTS (Details 1) - USD ($)	Dec. 31, 2018	Dec. 31, 2017
Asset commodity derivatives:
Current assets	$ 1,031,614	$ 295,304
Noncurrent assets	98,530	118
Total	1,130,144	295,422
Liability commodity derivatives:
Current liabilities	(280,456)	(1,198,307)
Noncurrent liabilities	(85,502)	(336,524)
Total	(365,958)	(1,534,831)
Total commodity derivative instruments	$ 764,186	$ (1,239,409)

COMMODITY DERIVATIVE INSTRUME_5

COMMODITY DERIVATIVE INSTRUMENTS (Details 2) - USD ($)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative settlements	$ (2,419,303)	$ 1,238,341
Mark to market on commodity derivatives	2,003,595	1,316,593
Net gains (losses) from commodity derivatives	$ (415,708)	$ 2,554,934

STOCK-BASED COMPENSATION (Detai

STOCK-BASED COMPENSATION (Details) - RSA	12 Months Ended
	Dec. 31, 2018$ / sharesshares
Number of unvested RSA shares
Unvested shares as of January 1, 2018 | shares	274,450
Granted on February 6, 2018 | shares	930,916
Vested on February 6, 2018 | shares	(930,916)
Vested on February 6, 2018 | shares	(80,687)
Vested on May 31, 2018 | shares	(31,147)
Vested on July 20, 2018 | shares	(1,250)
Forfeited | shares	(17,056)
Unvested shares as of December 31, 2018 | shares	144,310
Weighted Average Grant-Date Fair Value
Unvested per shares as of January 1, 2018 | $ / shares	$ 2.78
Granted on February 6, 2018 | $ / shares	1.15
Vested on February 6, 2018 | $ / shares	1.15
Vested on February 6, 2018 | $ / shares	1.15
Vested on May 31, 2018 | $ / shares	0.40
Vested on July 20, 2018 | $ / shares	0.46
Forfeited | $ / shares	2.56
Unvested per shares as of December 31, 2018 | $ / shares	$ 2.56

STOCK-BASED COMPENSATION (Det_2

STOCK-BASED COMPENSATION (Details 1) - Stock Appreciation Rights (SARs) [Member]	12 Months Ended
	Dec. 31, 2018$ / sharesshares
Stock Settled [Member]
Number of unvested SAR shares
Unvested shares as of January 1, 2018 | shares	28,081
Vested | shares	(28,081)
Forfeited | shares	0
Unvested shares as of December 31, 2018 | shares	0
Weighted Average Grant-Date Fair Value
Unvested per shares as of January 1, 2018 | $ / shares	$ 2.35
Vested | $ / shares	2.35
Forfeited | $ / shares	.00
Unvested per shares as of December 31, 2018 | $ / shares	$ .00
Cash Settled [Member]
Number of unvested SAR shares
Unvested shares as of January 1, 2018 | shares	1,623,371
Vested | shares	(159,092)
Forfeited | shares	0
Unvested shares as of December 31, 2018 | shares	1,464,279
Weighted Average Grant-Date Fair Value
Unvested per shares as of January 1, 2018 | $ / shares	$ .06
Vested | $ / shares	.06
Forfeited | $ / shares	.00
Unvested per shares as of December 31, 2018 | $ / shares	$ .06

STOCK-BASED COMPENSATION (Det_3

STOCK-BASED COMPENSATION (Details 2)	12 Months Ended
	Dec. 31, 2018USD ($)$ / sharesshares
Share-based Payment Arrangement [Abstract]
Number of Options Outstanding, Beginning | shares	898,617
Number of Options Granted | shares	0
Number of Options Exercised | shares	0
Number of Options Forfeited | shares	0
Number of Options Expired | shares	(5,000)
Number of Options Outstanding, Ending | shares	893,617
Vested and expected to vest December 31, 2018 | shares	297,874
Number of shares Options Exercisable | shares	297,874
Weighted Average Exercise Price Outstanding	$ 3.12
Weighted Average Exercise Price Granted	0
Weighted Average Exercise Price Exercised	.00
Weighted Average Exercise Price Forfeited	0
Weighted Average Exercise Price Expired	103.20
Weighted Average Exercise Price Outstanding	2.56
Weighted Average Exercise Price Vested and expected to vest at December 31, 2018	2.56
Weighted Average Exercise Price Exercisable	$ 2.56
Weighted Average Remaining Contractual Life (in years) Outstanding	9 years 3 months
Weighted Average Remaining Contractual Life (in years) Granted	0 years
Weighted Average Remaining Contractual Life (in years) Forfeited	0 years
Weighted Average Remaining Contractual Life (in years) Expired	0 years
Weighted Average Remaining Contractual Life (in years) Outstanding	8 years 3 months 18 days
Weighted Average Remaining Contractual Life (in years) Vested and expected to vest at December 31, 2018	8 years 3 months 18 days
Weighted Average Remaining Contractual Life (in years) Exercisable	8 years 3 months 18 days
Aggregate Intrinsic Value Outstanding, Beginning | $	$ 0
Aggregate Intrinsic Value Granted	$ 0
Aggregate Intrinsic Value Exercised | $	$ 0
Aggregate Intrinsic Value Forfeited	$ 0
Aggregate Intrinsic Value Expired	$ 0
Aggregate Intrinsic Value Outstanding, Ending | $	$ 0
Aggregate Intrinsic Value Vested and expected to vest at December 31, 2018 | $	$ 0

STOCK-BASED COMPENSATION (Det_4

STOCK-BASED COMPENSATION (Details Narrative) - USD ($)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Weighted average remaining service period	9 years 3 months
SAR, Weighted average assumptions used to estimate fair value expected life	5 years 10 months 24 days
SAR, Weighted average assumptions used to estimate fair value volatility	84.20%
SAR, Weighted average assumptions used to estimate fair value risk-free rate	1.90%
Share-based compensation expense	$ 582,344	$ 2,381,365
Restricted Stock Awards (RSAs) [Member]
Unrecognized compensation cost	$ 203,144
Weighted average remaining service period	1 year
Stock Appreciation Rights (SARs) [Member] | Stock Settled [Member]
SAR, Weighted average assumptions used to estimate fair value expected life	5 years 9 months 18 days
SAR, Weighted average assumptions used to estimate fair value volatility	84.20%
SAR, Weighted average assumptions used to estimate fair value risk-free rate	1.42%
Stock Appreciation Rights (SARs) [Member] | Cash Settled [Member]
SAR, Weighted average assumptions used to estimate fair value expected life	3 years 3 months 18 days
SAR, Weighted average assumptions used to estimate fair value volatility	143.60%
SAR, Weighted average assumptions used to estimate fair value risk-free rate	2.45%

NET INCOME (LOSS) PER COMMON _3

NET INCOME (LOSS) PER COMMON SHARE (Details) - USD ($)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
LOSS PER COMMON SHARE:
Net loss attributable to common stockholders	$ (17,070,272)	$ (6,806,633)
Net loss per common share:
Basic	$ (0.74)	$ (0.46)
Diluted	$ (0.74)	$ (0.46)
Weighted average common shares outstanding
Basic	23,023,066	14,815,991
Add potentially dilutive securities
Unvested restricted stock awards	0	0
Stock appreciation rights	0	0
Stock options	0	0
Series D preferred stock	0	0
Diluted weighted average common shares outstanding	23,023,066	14,815,991

DEBT AND INTEREST EXPENSE (Deta

DEBT AND INTEREST EXPENSE (Details) - USD ($)	Dec. 31, 2018	Dec. 31, 2017
Total Debt	$ 34,742,953	$ 28,351,124
Less: current portion	(34,742,953)	(651,124)
Total long-term debt	0	27,700,000
Senior credit facility [Member]
Total Debt	34,000,000	27,700,000
Installment loan due 7/22/19 [Member]
Total Debt	742,953	0
Installment loan due 7/22/18 [Member]
Total Debt	$ 0	$ 651,124

DEBT AND INTEREST EXPENSE (De_2

DEBT AND INTEREST EXPENSE (Details Narrative) - USD ($)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Debt Disclosure [Abstract]
Commitment fees	$ 19,170	$ 41,404

INCOME TAXES (Details)

INCOME TAXES (Details) - USD ($)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Current income taxes (benefit):
Federal	$ 0	$ 0
State	0	0
Deferred income taxes (benefit):
Federal	0	0
State	0	0
Total income tax expense	$ 0	$ 0

INCOME TAXES (Details 1)

INCOME TAXES (Details 1)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Income Tax Disclosure [Abstract]
U. S. statutory rate	21.00%	35.00%
State income taxes (net of federal benefit)	6.96%	(9.21%)
Nondeductible transaction costs	0.00%	(1.61%)
Stock compensation	0.00%	(0.03%)
Prior year differences	0.00%	7.38%
Change in tax rates	0.00%	(429.43%)
Valuation allowance	(27.91%)	397.96%
Other	(0.05%)	(0.06%)
Effective tax rate	0.00%	0.00%

INCOME TAXES (Details 2)

INCOME TAXES (Details 2) - USD ($)	Dec. 31, 2018	Dec. 31, 2017
Deferred income tax liabilities
Other property, plant and equipment	$ (4,884,996)	$ (4,599,347)
Commodity derivative instruments	(130,856)	0
Deferred tax liability	(5,015,822)	(4,599,347)
Deferred income tax assets
Net operating loss carryforward	46,370,912	41,368,982
Commodity derivative instruments	0	326,893
Financial accruals and other	145,031	246,001
Asset retirement obligation	2,789,434	2,476,370
Stock based compensation	141,759	270,366
Valuation allowance	(44,431,314)	(40,089,265)
Deferred tax asset	5,015,822	4,599,347
Deferred income taxes, net	$ 0	$ 0

INCOME TAXES (Details Narrative

INCOME TAXES (Details Narrative)	Dec. 31, 2018USD ($)
Income Tax Disclosure [Abstract]
Net operating loss carryforwards	$ 187,800,000
Net operating loss carryforwards valuation allowance	$ 44,400,000

COMMITMENTS AND CONTINGENCIES_2

COMMITMENTS AND CONTINGENCIES (Details)	Dec. 31, 2018USD ($)
Future minimum rentals under all noncancellable operating leases
2019	$ 532,147
2020	520,297
2021	524,044
2022	530,990
2023	$ 351,392

COMMITMENTS AND CONTINGENCIES_3

COMMITMENTS AND CONTINGENCIES (Details Narrative) - USD ($)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Commitments and Contingencies Disclosure [Abstract]
Aggregate rental expense	$ 504,046	$ 507,331

EMPLOYEE BENEFIT PLANS (Details

EMPLOYEE BENEFIT PLANS (Details Narrative) - USD ($)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Retirement Benefits [Abstract]
Defined Contribution Plan, Employer Matching Contribution, Percent	4.00%	4.00%
Defined Contribution Plan, Employer Contribution	$ 73,529	$ 100,597
Accrued liability for compensated absences	$ 231,520	$ 252,649

SALES TO MAJOR CUSTOMERS (Detai

SALES TO MAJOR CUSTOMERS (Details Narrative)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Risks and Uncertainties [Abstract]
Number of major customer	5	5
Oil and natural gas sales to major customers (percent)	80.00%	79.00%

SUPPLEMENTARY INFORMATION ON _3

SUPPLEMENTARY INFORMATION ON OIL AND NATURAL GAS EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES (UNAUDITED) (Details) - USD ($)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Exploration (including geological and geophysical costs)	$ 1,973,043	$ 5,216,304
Development	1,323,819	2,883,801
Acquisition of properties	0	0
Capitalized overhead	733,199	1,606,910
Lease acquisition costs, net of recoveries	589,351	2,462,233
Total costs incurred	$ 4,619,412	$ 12,169,248

SUPPLEMENTARY INFORMATION ON _4

SUPPLEMENTARY INFORMATION ON OIL AND NATURAL GAS EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES (UNAUDITED) (Details 1) - USD ($)	Dec. 31, 2018	Dec. 31, 2017
Oil and natural gas properties, capitalized
Unproved properties	$ 0	$ 6,794,372
Proved properties	504,139,740	494,216,531
Total oil and gas properties	504,139,740	501,010,903
Less accumulated DD&A	(436,642,215)	(421,165,400)
Net oil and natural gas properties capitalized	$ 67,497,525	$ 79,845,503

SUPPLEMENTARY INFORMATION ON _5

SUPPLEMENTARY INFORMATION ON OIL AND NATURAL GAS EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES (UNAUDITED) (Details 2)	12 Months Ended
	Dec. 31, 2018bblMMcf	Dec. 31, 2017bblMMcf
Oil in (Bbls) [Member]
Proved developed and undeveloped reserves, beginning	2,362,100	2,975,900
Revisions of previous estimates	(632,100)	44,100
Extension, discoveries and other additions	0	235,900
Purchases of minerals in place	0	0
Sales of minerals in place	(27,200)	(643,500)
Production	(171,600)	(250,300)
Proved developed and undeveloped reserves, ending	1,531,200	2,362,100
Proved developed reserves, beginning	1,763,200	2,203,000
Proved developed reserves, ending	1,531,200	1,763,200
Proved undeveloped reserves, beginning	598,900	772,900
Proved undeveloped reserves, ending	0	598,900
NGL in (Bbls) [Member]
Proved developed and undeveloped reserves, beginning	1,294,200	1,348,300
Revisions of previous estimates	(379,300)	(57,800)
Extension, discoveries and other additions	0	157,200
Purchases of minerals in place	0	0
Sales of minerals in place	(4,300)	(22,300)
Production	(100,200)	(131,200)
Proved developed and undeveloped reserves, ending	810,400	1,294,200
Proved developed reserves, beginning	1,009,200	1,061,000
Proved developed reserves, ending	810,400	1,009,200
Proved undeveloped reserves, beginning	284,900	287,300
Proved undeveloped reserves, ending	0	284,900
Natural Gas (in Mcf) [Member]
Proved developed and undeveloped reserves, beginning | MMcf	(23,595,500)	23,978,900
Revisions of previous estimates | MMcf	(4,607,200)	112,100
Extension, discoveries and other additions | MMcf	0	2,677,700
Purchases of minerals in place | MMcf	0	0
Sales of minerals in place | MMcf	(17,900)	(87,600)
Production | MMcf	(2,095,000)	(3,085,600)
Proved developed and undeveloped reserves, ending | MMcf	16,875,400	(23,595,500)
Proved developed reserves, beginning | MMcf	21,130,900	21,918,700
Proved developed reserves, ending | MMcf	16,875,400	21,130,900
Proved undeveloped reserves, beginning | MMcf	2,464,600	2,060,200
Proved undeveloped reserves, ending | MMcf	0	2,464,600
BOE [Member]
Proved developed and undeveloped reserves, beginning	7,588,900	8,320,700
Revisions of previous estimates	(1,779,200)	5,000
Extension, discoveries and other additions	0	839,400
Purchases of minerals in place	0	0
Sales of minerals in place	(34,500)	(680,400)
Production	(621,000)	(895,800)
Proved developed and undeveloped reserves, ending	5,154,200	7,588,900
Proved developed reserves, beginning	6,294,300	6,917,100
Proved developed reserves, ending	5,154,200	6,294,300
Proved undeveloped reserves, beginning	1,294,600	1,403,600
Proved undeveloped reserves, ending	0	1,294,600

SUPPLEMENTARY INFORMATION ON _6

SUPPLEMENTARY INFORMATION ON OIL AND NATURAL GAS EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES (UNAUDITED) (Details 3) - USD ($)	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Future cash inflows	$ 186,108,775	$ 222,266,300
Future oil and natural gas operating expenses	(62,571,446)	(78,791,900)
Future development costs	(16,914,730)	(28,980,100)
Future income tax expenses	0	0
Future net cash flows	106,622,599	114,494,300
10% annual discount for estimating timing of cash flows	(40,566,536)	(41,591,600)
Standardized measure of discounted future net cash flows	$ 66,056,063	$ 72,902,700	$ 73,600,100

SUPPLEMENTARY INFORMATION ON _7

SUPPLEMENTARY INFORMATION ON OIL AND NATURAL GAS EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES (UNAUDITED) (Details 4) - USD ($)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Beginning of year	$ 72,902,700	$ 73,600,100
Changes due to current year operation:
Sales of oil and natural gas, net of oil and natural gas operating expenses	(10,909,630)	(14,406,288)
Extensions and discoveries	0	11,776,109
Purchases of oil and gas properties	0	0
Development costs incurred during the period that reduced future development costs	1,323,819	3,364,636
Changes due to revisions in standardized variables:
Prices and operating expenses	21,240,259	18,601,781
Income taxes	0	0
Estimated future development costs	5,227,340	(2,252,078)
Quantity estimates	(27,220,938)	(1,199,960)
Sale of reserves in place	(588,217)	(5,945,688)
Accretion of discount	7,290,270	7,360,010
Production rates, timing and other	(3,209,540)	(17,995,922)
Net change	(6,846,637)	(697,400)
End of year	$ 66,056,063	$ 72,902,700

SUPPLEMENTARY INFORMATION ON _8

SUPPLEMENTARY INFORMATION ON OIL AND NATURAL GAS EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES (Details Narrative)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Crude oil prices used in computing future cash flow	$65.56 per Bbl	$51.34 per Bbl
Natural gas prices used in computing future cash flow	$3.10 per MMBtu	$2.98 per MMBtu