Yuma Energy (YUMAQ) 10-K 12 Apr 17 2016 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2016	Apr. 12, 2017	Jun. 30, 2016
Document And Entity Information
Entity Registrant Name	Yuma Energy, Inc.
Entity Central Index Key	1,672,326
Document Type	10-K
Document Period End Date	Dec. 31, 2016
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Is Entity a Well-known Seasoned Issuer?	No
Is Entity a Voluntary Filer?	No
Is Entity's Reporting Status Current?	Yes
Entity Filer Category	Smaller Reporting Company
Entity Public Float			$ 13,100,000
Entity Common Stock, Shares Outstanding		12,211,256
Document Fiscal Period Focus	FY
Document Fiscal Year Focus	2,016

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($)	Dec. 31, 2016	Dec. 31, 2015
CURRENT ASSETS:
Cash and cash equivalents	$ 3,625,686	$ 4,064,094
Accounts receivable, net of allowance for doubtful accounts:
Trade	4,827,798	2,989,590
Officers and employees	68,014	1,121
Other	1,757,337	3,793,257
Commodity derivative instruments	0	1,711,072
Prepayments	1,063,418	328,218
Other deferred charges	284,305	0
Total current assets	11,626,558	12,887,352
OIL AND GAS PROPERTIES (full cost method):
Proved properties	488,723,905	425,767,477
Unproved properties - not subject to amortization	3,656,989	178,761
Subtotal	492,380,894	425,946,238
Less: accumulated depreciation, depletion and amortization	(410,440,433)	(381,987,616)
Net oil and gas properties	81,940,461	43,958,622
OTHER PROPERTY AND EQUIPMENT:
Land, buildings and improvements	1,600,000	179,054
Other property and equipment	7,136,530	8,855,503
Total	8,736,530	9,034,557
Less: accumulated depreciation and amortization	(5,349,145)	(7,357,964)
Net other property and equipment	3,387,385	1,676,593
OTHER ASSETS AND DEFERRED CHARGES:
Deferred taxes	0	1,425,964
Deposits	467,306	404,242
Other noncurrent assets	517,201	0
Total other assets and deferred charges	984,507	1,830,206
TOTAL ASSETS	97,938,911	60,352,773
CURRENT LIABILITIES:
Current maturities of debt	599,341	0
Accounts payable, principally trade	11,009,631	5,065,334
Commodity derivative instruments	1,340,451	0
Asset retirement obligations	376,735	184,881
Other accrued liabilities	2,572,680	733,070
Total current liabilities	15,898,838	5,983,285
LONG-TERM DEBT	39,500,000	0
OTHER NONCURRENT LIABILITIES:
Asset retirement obligations	9,819,648	5,147,169
Commodity derivative instruments	1,215,551	0
Other liabilities	0	95,000
Total other noncurrent liabilities	11,035,199	5,242,169
Commitments and contingencies (Note 18)
EQUITY:
Common stock ($.001 par value, 100 million shares authorized, 12,201,884 issued as of December 31, 2016 and 7,440,152 issued as of December 31, 2015)	12,202	7,440
Paid-in capital	43,877,563	209,512,985
Treasury stock	0	(41,350,488)
Accumulated earnings (deficit)	(12,386,668)	(119,376,290)
Total equity	31,504,874	49,127,319
TOTAL LIABILITIES AND EQUITY	97,938,911	60,352,773
Series D Convertible Preferred Stock [Member]
EQUITY:
Preferred stock	1,777	0
Series A Convertible Preferred Stock [Member]
EQUITY:
Preferred stock	$ 0	$ 333,672

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) - $ / shares	Dec. 31, 2016	Dec. 31, 2015
Common stock, par value	$ .001	$ .001
Common stock, authorized	100,000,000	100,000,000
Common stock, issued	12,201,884	7,440,152
Series D Convertible Preferred Stock [Member]
Preferred stock, par value	$ .001
Preferred stock, authorized	7,000,000
Preferred stock, issued	1,776,718
Series A Convertible Preferred Stock [Member]
Preferred stock, par value		$ .01
Preferred stock, authorized		50,000,000
Preferred stock, issued		33,367,187

CONSOLIDATED STATEMENTS OF OPER

CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
REVENUES:
Sales of natural gas and crude oil	$ 14,772,708	$ 18,628,000
EXPENSES:
Lease operating and production costs	5,563,630	7,643,037
General and administrative - stock-based compensation	1,731,969	933,017
General and administrative - other	12,727,328	6,865,763
Depreciation, depletion and amortization	8,239,802	17,139,137
Asset retirement obligation accretion expense	254,573	175,643
Impairment of oil and gas properties	20,654,848	40,479,906
Loss on write-off of other assets	833,157	0
Other	561,723	8,542
Total expenses	50,567,030	73,245,045
LOSS FROM OPERATIONS	(35,794,322)	(54,617,045)
OTHER INCOME (EXPENSE):
Net gains (losses) from commodity derivatives	(3,775,254)	3,319,004
Interest expense	(659,572)	(577,936)
Other, net	55,779	20,954
Total other income (expense)	(4,379,047)	2,762,022
LOSS BEFORE INCOME TAXES	(40,173,369)	(51,855,023)
Income tax expense - current	0	6,000
Income tax expense - deferred	1,425,964	10,454,802
NET LOSS	(41,599,333)	(62,315,825)
PREFERRED STOCK:
Dividends paid in kind	1,323,641	1,230,343
Loss on retirement of DPAC Series "A" Preferred Stock	(271,914)	0
NET LOSS ATTRIBUTABLE TO COMMON STOCKHOLDERS	$ (42,651,060)	$ (63,546,168)
LOSS PER COMMON SHARE:
Basic	$ (5.13)	$ (8.58)
Diluted	$ (5.13)	$ (8.58)
WEIGHTED AVERAGE NUMBER OF COMMON SHARES OUTSTANDING:
Basic	8,317,777	7,409,201
Diluted	8,317,777	7,409,201

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, 2014	$ 311,302	$ 7,354	$ 207,372,081	$ (41,140,147)	$ (55,830,122)	$ 110,720,468
Beginning Balance, Shares at Dec. 31, 2014	31,130,201	7,354,358
Net loss					(62,315,825)	(62,315,825)
Payment of DPAC Series "A" dividends in kind, Amount	$ 22,370		1,207,973		(1,230,343)	0
Payment of DPAC Series "A" dividends in kind, Shares	2,236,986
DPAC restricted stock grants, net of cancellations, Amount		$ 86	520			606
DPAC restricted stock grants, net of cancellations, Shares		85,794
DPAC treasury stock - employee tax payment				(210,341)		(210,341)
DPAC amortization of stock-based compensation			932,411			932,411
Ending Balance, Amount at Dec. 31, 2015	$ 333,672	$ 7,440	209,512,985	(41,350,488)	(119,376,290)	49,127,319
Ending Balance, Shares at Dec. 31, 2015	33,367,187	7,440,152
Net loss					(41,599,333)	(41,599,333)
Payment of DPAC Series "A" dividends in kind, Amount	$ 19,528		1,054,513		(1,074,041)	0
Payment of DPAC Series "A" dividends in kind, Shares	1,952,801
Retirement of DPAC Series "A" preferred stock, Amount	$ (353,200)		(18,800,880)		(271,914)	(19,425,994)
Retirement of DPAC Series "A" preferred stock, Shares	(35,319,988)
Issuance of Series "D" preferred stock, Amount	$ 1,754		19,424,240			19,425,994
Issuance of Series "D" preferred stock, Shares	1,754,179
Payment of Series "D" dividends in kind, Amount	$ 23		249,577		(249,600)	0
Payment of Series "D" dividends in kind, Shares	22,539
DPAC stock awards vested, Amount		$ 15	98,335			98,350
DPAC stock awards vested, Shares		14,651
Reclass DPAC equity at merger to paid-in capital			(150,184,510)			(150,184,510)
Common stock at merger, Amount		$ 4,746	20,930,798			20,935,544
Common stock at merger, Shares		4,746,180
Stock awards vested, Amount		$ 1	(1)			0
Stock awards vested, Shares		901
DPAC treasury stock - employee tax payment				(408,323)
Retire DPAC treasury stock			(41,758,811)	41,758,811		0
DPAC amortization of stock-based compensation			3,351,317			3,351,317
Ending Balance, Amount at Dec. 31, 2016	$ 1,777	$ 12,202	$ 43,877,563	$ 0	$ (12,386,668)	$ 31,504,874
Ending Balance, Shares at Dec. 31, 2016	1,776,718	12,201,884

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Reconciliation of net loss to net cash provided by (used in) operating activities
Net loss	$ (41,599,333)	$ (62,315,825)
Depreciation, depletion and amortization of property and equipment	8,239,802	17,139,137
Impairment of oil and gas properties	20,654,848	40,479,906
Amortization of debt issuance costs	148,970	210,067
Net deferred income tax expense	1,425,964	10,454,802
Stock-based compensation	1,731,969	933,017
Settlement of asset retirement obligations	(287,902)	(1,032,661)
Accretion of asset retirement obligation	254,573	175,643
Bad debt expense	556,406	0
Net gains (losses) from commodity derivatives	3,775,254	(3,319,004)
Losses on sales and write-offs of fixed assets	838,473	0
Changes in assets and liabilities:
Decrease in accounts receivable	3,698,004	1,133,493
Decrease in prepaids, deposits and other assets	353,889	10,924,780
Decrease in accounts payable and other current and non-current liabilities	(4,090,155)	(4,738,397)
NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES	(4,299,238)	10,044,958
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures on property and equipment	(10,066,999)	(23,301,875)
Proceeds from sale of oil and gas properties and other fixed assets	1,152,958	1,710,140
Merger with Yuma California	1,887,426	0
Derivative settlements	1,607,365	10,344,207
NET CASH USED IN INVESTING ACTIVITIES	(5,419,250)	(11,247,528)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings	247,013	0
Borrowings on senior credit facility	18,700,000	10,000,000
Repayments of borrowings	(9,049,625)	(15,000,000)
Debt issuance costs	(208,985)	0
Treasury stock repurchases	(408,323)	(210,341)
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES	9,280,080	(5,210,341)
NET DECREASE IN CASH AND CASH EQUIVALENTS	(438,408)	(6,412,911)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD	4,064,094	10,477,005
CASH AND CASH EQUIVALENTS AT END OF PERIOD	3,625,686	4,064,094
Supplemental disclosure of cash flow information:
Interest payments (net of interest capitalized)	590,160	362,860
Interest capitalized	26,121	0
Income tax payments	0	0
Supplemental disclosure of significant non-cash activity:
Change in capital expenditures financed by accounts payable	$ 323,910	$ 13,729,612

ORGANIZATION AND BASIS OF PRESE

ORGANIZATION AND BASIS OF PRESENTATION	12 Months Ended
	Dec. 31, 2016
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, primarily in the U.S. Gulf Coast and California. The Company has employed a 3-D seismic-based strategy to build an inventory of development and exploration prospects. The Company’s operations are currently focused on onshore properties located in central and southern Louisiana and Texas, where it is targeting the Eagle Ford, Woodbine, Tuscaloosa, Wilcox, Frio, Marg Tex, Austin Chalk and Hackberry formations. In addition, the Company has a non-operated position in the Bakken Shale in North Dakota and operated positions in Kern and Santa Barbara Counties in California. On October 26, 2016, Yuma Energy, Inc., a California corporation (“Yuma California”), merged (the “Reincorporation Merger”) with and into Yuma Energy, Inc., a Delaware corporation (“YEI”). Pursuant to the Reincorporation Merger, Yuma California was reincorporated in Delaware as YEI. Immediately thereafter, a wholly owned subsidiary of YEI merged (the “Davis Merger”) with and into privately-held Davis Petroleum Acquisition Corp., a Delaware corporation (“Davis”). As a result of the Davis Merger, Davis became a wholly owned subsidiary of YEI. Prior to the Reincorporation Merger, each share of Yuma California’s existing 9.25% Series A Cumulative Redeemable Preferred Stock, no par value per share (the “Yuma California Series A Preferred Stock”), was converted into 35 shares of common stock, no par value per share, of Yuma California (“Yuma California Common Stock”). As a result of the closing of the Reincorporation Merger, each share of Yuma California Common Stock was converted into one-twentieth of one (1) share (the “Reverse Stock Split”) of common stock, $0.001 par value per share of YEI (the “common stock”). As a result of the Reverse Stock Split, YEI issued an aggregate of approximately 4.75 million shares of its common stock. As a result of the Davis Merger, YEI issued approximately 7.45 million shares of its common stock to the former stockholders of Davis common stock. YEI also issued approximately 1.75 million shares of Series D Convertible Preferred Stock, $0.001 par value per share, of YEI (the “Series D Preferred Stock”), to existing Davis preferred stockholders. Upon completion of the Reincorporation Merger and the Davis Merger, there was an aggregate of approximately 12.2 million shares of common stock outstanding and 1.75 million shares of Series D Preferred Stock outstanding. At the closing of the Davis Merger, Davis appointed a majority of the board of directors of YEI. Four out of the five members of YEI’s board of directors prior to the closing of the Davis Merger continued to serve on the board of directors of YEI, with one of those four directors having been appointed by Davis. Three additional directors were appointed by Davis. The Davis Merger was accounted for as a “reverse acquisition” and a recapitalization since the former common stockholders of Davis have control over the combined company through their post-merger 61.1% ownership of the common stock and majority representation on YEI’s board of directors. The transaction qualified as a tax-deferred reorganization under Section 368(a) of the Internal Revenue Code of 1986, as amended (the “Code”). The Davis Merger was accounted for as a business combination in accordance with ASC 805 Business Combinations (“ASC 805”). ASC 805, among other things, requires assets acquired and liabilities assumed to be measured at their acquisition date fair value. Although YEI was the legal acquirer, Davis was the accounting acquirer. The historical financial statements are those of Davis. Hence, the financial statements included herein reflect (i) the historical results of Davis prior to the Davis Merger; (ii) the combined results of the Company following the Davis Merger; (iii) the acquired assets and liabilities of Davis at the their historical cost; and (iv) the fair value of Yuma California’s assets and liabilities at the close of the Davis Merger (see Note 4 – Acquisitions and Divestments, for further information). 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. 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 Pyramid Delaware Merger Subsidiary, Inc. “PDMS” Delaware 02/04/2014 YCI and PDMS 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 is a Delaware corporation formed for the purpose of acquiring equity interests of DPC and DPP. Petroleum became relatively inactive during 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. As of October 26, 2016 (the date of the Reincorporation Merger and the Davis Merger) and as of December 31, 2016, TSM was dormant due to the limited volumes of natural gas that it marketed, as well as the costs associated with accounting for the entity. POL is primarily engaged in holding assets located in the State of California. PDMS was inactive during 2016.

SUMMARY OF SIGNIFICANT ACCOUNTI

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	12 Months Ended
	Dec. 31, 2016
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 net revenues; 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; future cash flows associated with oil and gas properties; obligations related to employee benefits such as accrued vacation; and legal and environmental risks and exposures. Reclassifications When required for comparability, reclassifications are made to the prior period financial statements to conform to the current year presentation. Reclassifications include moving COPAS overhead recoveries from lease operating expenses to general and administrative expenses, moving certain other revenue to offset lease operating expense, moving commodity derivative gains (losses) from expenses to other income (expense), and moving regulatory interest from general and administrative to interest expense. 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 10 – 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 10 – 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. 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 $1,042,565 and $-0- at December 31, 2016 and 2015, 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 recognized. Depreciation, Depletion and Amortization (“DD&A”) Impairments Unproved oil and natural gas properties not subject to amortization consist of undeveloped leaseholds and exploratory and developmental wells in progress before the assignment of proved reserves and related capitalized interest. Management reviews the costs of these properties quarterly to determine whether and to what extent 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 the full cost pool. 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 for 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, with the exception of the Yuma California properties that were acquired in the Davis Merger, which were recorded at fair value as of the closing date of the Davis Merger in accordance with business combination accounting principles. 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 “Total Expenses” in the accompanying Consolidated Statements of Operations. In the event that facts and circumstances indicate that the carrying value of other plant, 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. 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 Revenue is recognized by the Company when crude oil, natural gas and condensate are delivered to the purchaser and title has transferred. Crude oil sales in Louisiana, representing a significant portion of the Company’s production, are typically indexed to Light Louisiana Sweet (“LLS”). Sales are based on index prices per MMBtu or the daily “spot” price as published in national publications with a mark-up or mark-down defined by contract with each customer. Sales prices for natural gas and crude oil are adjusted for transportation costs and other related deductions. The transportation costs and other deductions are based on contractual or historical data and do not require significant judgment. Subsequently, these deductions and transportation costs are adjusted to reflect actual charges based on third party documents. Historically, these adjustments have been insignificant. Since there is a ready market for natural gas and crude oil, the Company sells the majority of its products soon after production at various locations where title and risk of loss pass to the buyer. 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 17 – 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 (see Note 16 – Stockholders’ Equity). The Company adopted an Annual Incentive Plan for fiscal years 2016 and 2015 (see Note 13 – Stock-Based Compensation and Note 19 – Employee Benefit Plans). 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 13 – Stock-Based Compensation). Other Noncurrent Assets Noncurrent assets at December 31, 2016 are comprised of deferred debt issuance costs related to the establishment of the new Société Générale (“SocGen”) credit facility, and in 2015, are comprised of Davis’ Bank of America credit facility. Debt issuance costs related to the SocGen credit facility are being amortized to interest expense over the term of the new credit facility, which expires on October 26, 2019, and had a carrying amount of $801,506 at December 31, 2016, of which $284,305 is classified as current other deferred charges and $517,201 is classified as other noncurrent assets. Amortization expense during the year ended December 31, 2016 and 2015 was $148,970 and $210,067, respectively. Earnings per Share The Company’s basic earnings per share (“EPS”) is computed based on the 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 14 – Net 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. Changes in Accounting Principles Not Yet 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 does not expect the adoption of this ASU to have a material impact on its Consolidated Statements of Cash Flows. In February 2016, the FASB issued ASU 2016-02, “Leases,” a new lease standard requiring lessees to recognize lease assets and lease liabilities for most leases classified as operating leases under previous GAAP. The guidance is effective for fiscal years beginning after December 15, 2018 with early adoption permitted. The Company will be required to use a modified retrospective approach for leases that exist or are entered into after the beginning of the earliest comparative period in the financial statements. The Company is currently evaluating the impact of adopting this standard on its Consolidated Financial Statements, but does believe that it will materially impact the Company’s consolidated financial statements. In January 2016, the FASB issued ASU 2016-01, “Recognition and Measurement of Financial Assets and Financial Liabilities,” which changes certain guidance related to the recognition, measurement, presentation and disclosure of financial instruments. This update is effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years. Early adoption is not permitted for the majority of the update, but is permitted for two of its provisions. The Company is evaluating the new guidance, but does not believe that it will materially impact the Company’s consolidated financial statement presentation. In May 2014, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers (Topic 606).” In March, April, and May of 2016, the FASB issued rules clarifying several aspects of the new revenue recognition standard. The new guidance is effective for fiscal years and interim periods beginning after December 15, 2017. This guidance outlines a new, single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance, including industry-specific guidance. This new revenue recognition model provides a five-step analysis in determining when and how revenue is recognized. The new model will require revenue recognition to depict the transfer of promised goods or services to customers in an amount that reflects the consideration a company expects to receive in exchange for those goods and services. The new standard also requires more detailed disclosures related to the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. The Company will not early adopt the standard although early adoption is permitted. The Company is currently evaluating whether to apply the retrospective approach or modified retrospective approach with the cumulative effect recognized as of the date of initial application. The Company is currently evaluating the impact the standard is expected to have on its consolidated financial statements by evaluating current revenue streams and evaluating contracts under the revised standards. Recently adopted 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 provides a screen that when substantially all of the fair value of the gross assets acquired, or disposed of, are concentrated in a single identifiable asset, or a group of similar identifiable assets, the set will not be considered a business. If the screen is not met, a set must include an input and a substantive process that together significantly contribute to the ability to create an output to be considered 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 goodwill would not be allocated to divestitures or recorded for acquisitions that are not considered to be businesses. The FASB issued ASU 2016-09, “Compensation—Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting,” The FASB issued ASU 2015-03, “Interest – Imputation of Interest (Subtopic 835-30) – Simplifying the Presentation of Debt Issuance Costs,” which requires debt issuance costs to be presented in the balance sheet as a direct reduction from the associated debt liability. In August 2015, the FASB subsequently issued ASU 2015-15, “Interest – Imputation of Interest (Subtopic 835-30) – Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements,” a clarification as to the handling of debt issuance costs related to line-of-credit arrangements that allows the presentation of these costs as an asset. The standards update is effective for interim and annual periods beginning after December 15, 2015. The Company has debt costs associated with its line-of-credit only; therefore, this standard had no impact on its consolidated financial statements. These costs remain an asset on the Company’s Consolidated Balance Sheets. The FASB issued ASU 2014-15, “Presentation of Financial Instruments – Going Concern,” which requires management of an entity to evaluate whether there are conditions or events, considered in the aggregate, that raise substantial doubt about the entity’s ability to continue as a going concern within one year after the date that the financial statements are issued or available to be issued. This update is effective for annual periods ending after December 15, 2016. The adoption of this standard did not have a material impact on the Company’s consolidated financial statements.

PREPAYMENTS

PREPAYMENTS	12 Months Ended
	Dec. 31, 2016
Prepaid Expense and Other Assets [Abstract]
PREPAYMENTS	At December 31, prepayments consisted of the following: December 31, 2016 2015 Prepaid insurance $ 817,268 $ 152,709 Prepaid taxes 97,934 — Other prepayments 148,216 175,509 Total prepayments $ 1,063,418 $ 328,218

ACQUISITIONS AND DIVESTMENTS

ACQUISITIONS AND DIVESTMENTS	12 Months Ended
	Dec. 31, 2016
Business Combinations [Abstract]
ACQUISITIONS AND DIVESTMENTS	Acquisitions Effective August 1, 2015, the Company purchased an additional 3.5625% working interest in its Lac Blanc field for $1.4 million. Divestments During 2016, the Company made the following divestments: ● Clipper – the Company relinquished its right to a 5% reversionary interest for zero consideration ● Masters Creek – the Company assigned its interest in 27 gross wells in exchange for P&A liability ● Calif ornia – the Company sold surface rights to 77 acres for $1,140,427 During 2015, the Company sold its interests in the following fields: ● Cat Spring – net proceeds of $74,640 ● Carter Estate #1 – net proceeds of $867,500 ● Overriding Royalty Interests (various) – net proceeds of $768,000 Davis Merger On October 26, 2016, pursuant to the Reincorporation Merger, Yuma California was reincorporated in Delaware as YEI. Also on October 26, 2016, YEI and Davis closed the Davis Merger. In this transaction, YEI acquired all of the outstanding common stock and preferred stock of Davis, through a newly formed subsidiary, with Davis surviving as a wholly owned subsidiary of YEI, issuing approximately 7.45 million shares of common stock to holders of Davis common stock and approximately 1.75 million shares of Series D Preferred Stock to existing Davis preferred stockholders. The Davis Merger resulted in a change of control of YEI. The Davis Merger was recorded in accordance with FASB ASC An allocation of the purchase price was prepared using, among other things, the Company’s December 31, 2015 reserve report prepared by Netherland, Sewell & Associates, Inc., an independent petroleum engineering firm, and adjusted by the Company’s reserve engineering staff to the October 26, 2016 acquisition date. The estimated fair value of the consideration to be transferred, assets acquired, and liabilities assumed are described below (in thousands): Purchase Consideration Common stock (1) $ 20,883 Stock appreciation rights (2) 85 Stock options (3) 1 Restricted stock awards (4) 181 Restricted stock units (5) — Debt (6) 30,202 Net purchase considered to be allocated $ 51,352 Estimated fair value of assets acquired Proved natural gas and oil properties $ 54,974 Unproved natural gas and oil properties 505 Real property 2,755 Personal property 1,427 Commodity derivatives - asset 1,195 Deposits 414 Other assets 485 Other long-term assets 2 Total assets acquired 61,757 Estimated fair value of liabilities acquired Net working capital (4,453 ) Asset retirement obligation (5,874 ) Commodity derivatives - liabilities (78 ) Total liabilities acquired (10,405 ) Total assets and liabilities acquired $ 51,352 (1) 4,746,180 shares of Yuma California Common Stock were effectively transferred in connection with the Davis Merger. Those shares were valued at $4.40 per share, which was the last sales price of Yuma California Common Stock at October 26, 2016. The October 26, 2016 share price used is the same date as the October 26, 2016 NYMEX strip price applied in Yuma California’s most recent engineering reports. (2) Yuma California’s stock appreciation rights were valued using the binomial lattice model. (3) Yuma California’s 5,000 stock options were valued at approximately $0.259 per option using the Black-Scholes model. (4) 901 restricted stock awards vested in 2016 and the 78,336 restricted stock awards vesting in 2017 and 2018 were valued at $4.40 per share on October 26, 2016. (5) Yuma California had no restricted stock units outstanding at October 26, 2016. (6) Debt fair value approximates the related book value at October 26, 2016. The following unaudited pro forma combined results of operations are provided for the years ended December 31, 2016 and 2015 as though the Davis Merger had been completed as of the beginning of the earliest period presented, or January 1, 2015. These pro forma combined results of operations have been prepared by adjusting the historical results of the Company to include the historical results of Yuma California. These supplemental pro forma results of operations are provided for illustrative purposes only, and do not purport to be indicative of the actual results that would have been achieved by the combined company for the periods presented or that may be achieved by the combined company in the future. The pro forma results of operations do not include any cost savings or other synergies that resulted, or may result, from the Davis Merger or any estimated costs that will be incurred to integrate Davis and Yuma California. Future results may vary significantly from the results reflected in this pro forma financial information because of future events and transactions, as well as other factors. Years Ended December 31, 2016 2015 ($ in thousands) (Unaudited) (Unaudited) Revenues $ 24,536 $ 45,813 Net loss $ (41,829 ) $ (70,884 ) Net loss per share: Basic $ (3.43 ) $ (5.80 ) Diluted $ (3.43 ) $ (5.80 )

ASSET IMPAIRMENTS

ASSET IMPAIRMENTS	12 Months Ended
	Dec. 31, 2016
Asset Impairments
ASSET IMPAIRMENTS	Capitalized costs (net of accumulated DD&A and deferred income taxes) of proved oil and natural gas properties 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 less estimated future operating and development costs, abandonment costs (net of salvage value) and estimated related future income taxes. The oil and natural gas prices used to calculate the full cost ceiling were $42.75/Bbl for oil and $2.48/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. Amounts thus required to be written off are not reinstated for any subsequent increase in the cost center ceiling. During the years ended December 31, 2016 and 2015, the Company recorded full cost ceiling impairments after income taxes of $20.7 million and $40.5 million, respectively, due to the continued low commodity prices and the reduction of the Company’s proved undeveloped reserves.

PROPERTY, PLANT, AND EQUIPMENT,

PROPERTY, PLANT, AND EQUIPMENT, NET	12 Months Ended
	Dec. 31, 2016
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 production, exploration, and development activities at December 31: December 31, 2016 2015 Subject to amortization (proved properties) $ 488,723,905 $ 425,767,477 Less: Accumulated depreciation, depletion, amortization and impairment (410,440,433 ) (381,987,616 ) Proved properties, net $ 78,283,472 $ 43,779,861 Not subject to amortization (unproved properties) Leasehold acquisition costs 2,411,402 178,761 Exploration and development 1,219,466 — Capitalized Interest 26,121 — Total unproved properties 3,656,989 178,761 Oil and gas properties, net $ 81,940,461 $ 43,958,622 Unproved properties not subject to amortization Costs not being amortized are transferred to the Company’s full cost pool as its drilling program is executed or costs are evaluated and deemed impaired. The Company anticipates that these unevaluated costs will be included in the depletion computation in 2017 and 2018. A summary of the Company’s unevaluated properties by year incurred follows: Year Incurred 2016 2015 and prior Total Leasehold acquisition costs $ 2,232,641 $ 178,761 $ 2,411,402 Exploration and development 1,219,466 — 1,219,466 Capitalized interest 26,121 — 26,121 Total $ 3,478,228 $ 178,761 $ 3,656,989 Other Other property and equipment consists of the following: Estimated useful December 31, life in years 2016 2015 Plants and pipeline systems 10 $ 4,218,496 $ 4,599,177 Land n/a 1,314,000 — Software and IT equipment 3 - 5 964,581 2,006,133 Drilling and operating equipment 15 841,494 — Furniture and fixtures 7 - 10 820,584 666,816 Buildings 25 286,000 179,054 Automobiles 3 - 7 207,115 158,531 Office leasehold improvements 10 84,260 1,424,846 Total other property and equipment 8,736,530 9,034,557 Less: Accumulated depreciation and leasehold improvement amortization (5,349,145 (7,357,964 ) Net book value $ 3,387,385 $ 1,676,593 Depreciation and leasehold improvement amortization expense related to other property, plant and equipment outside of oil and natural gas properties totaled $483,695 and $591,350 for the years ended December 31, 2016 and 2015, 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, 2016
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 asset retirement costs. Revisions in estimated liabilities can also include, but are not limited to, revisions of estimated inflation rates, changes in property lives, and the expected timing of settlement. The changes in the asset retirement obligation for the years ended December 31, 2016 and 2015 were as follows: December 31, 2016 2015 Beginning of year balance $ 5,332,050 $ 7,226,164 Liabilities assumed in the merger 5,873,504 — Liabilities incurred during year 277,876 1,078,792 Liabilities settled during year (572,623 ) (1,164,927 ) Liabilities sold during year (1,334,215 ) (1,740,971 ) Accretion expense 254,573 175,643 Revisions in estimated cash flows 365,218 (242,651 ) End of year balance $ 10,196,383 $ 5,332,050 Liabilities sold during 2016 include the Company assigning its interest in 27 gross wells in Masters Creek in exchange for the assignee assuming the P&A liability, and the Company relinquishing its right to a 5% reversionary interest in the Clipper Field.

ACCOUNTS RECEIVABLE FROM CHIEF

ACCOUNTS RECEIVABLE FROM CHIEF EXECUTIVE OFFICER AND EMPLOYEES	12 Months Ended
	Dec. 31, 2016
Accounts Receivable From Chief Executive Officer And Employees
ACCOUNTS RECEIVABLE FROM CHIEF EXECUTIVE OFFICER AND EMPLOYEES	The following table provides information with respect to related party transactions with affiliates, the President and Chief Executive Officer (“CEO”) of the Company, and employees. The trade receivable from the CEO is primarily for invoiced costs on prospects and wells as part of his normal joint interest billings (see Note 9 – Related Party Transactions). December 31, 2016 2015 Receivables from affiliates, CEO and employees: Current: CEO $ 67,114 $ — Employees 900 1,121 Total $ 68,014 $ 1,121

RELATED PARTY TRANSACTIONS

RELATED PARTY TRANSACTIONS	12 Months Ended
	Dec. 31, 2016
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. Under the WIIP, Mr. Banks could purchase: ● Working interests in prospects from the Company or from unaffiliated third parties up to 2.5% of the Company’s working interest; and ● Working interests in production acquisitions that the Company undertakes in an amount up to 2.5% (previously 5%) of the aggregate cost of the interest to be acquired. 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 resulting from prior purchases under the WIIP.

FAIR VALUE MEASUREMENTS

FAIR VALUE MEASUREMENTS	12 Months Ended
	Dec. 31, 2016
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 2 – 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, 2016 Significant Quoted prices other Significant in active observable unobservable markets inputs inputs (Level 1) (Level 2) (Level 3) Total Liabilities: Commodity derivatives – oil $ — $ 956,997 $ — $ 956,997 Commodity derivatives – gas — 1,599,005 — $ 1,599,005 Total liabilities $ — $ 2,556,002 $ — $ 2,556,002 Fair value measurements at December 31, 2015 Significant Quoted prices other Significant in active observable unobservable markets inputs inputs (Level 1) (Level 2) (Level 3) Total Assets: Commodity derivatives – oil $ — $ 1,711,072 $ — $ 1,711,072 Commodity derivatives – gas — — — — Total assets $ — $ 1,711,072 $ — $ 1,711,072 Derivative instruments listed above include swaps, collars, and three-way collars (see Note 11 – Commodity Derivative Instruments). Debt Asset Retirement Obligations

COMMODITY DERIVATIVE INSTRUMENT

COMMODITY DERIVATIVE INSTRUMENTS	12 Months Ended
	Dec. 31, 2016
Derivative Instruments and Hedging Activities Disclosure [Abstract]
COMMODITY DERIVATIVE INSTRUMENTS	Objective and Strategies for Using Commodity Derivative Instruments 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, 2016 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”). 2017 2018 2019 Settlement Settlement Settlement NATURAL GAS (MMBtu): Swaps Volume 2,381,776 1,451,734 — Price $ 3.13 $ 3.00 — 3-way collars Volume 248,023 — — Ceiling sold price (call) $ 3.28 — — Floor purchased price (put) $ 2.95 — — Floor sold price (short put) $ 2.38 — — CRUDE OIL (Bbls): Swaps Volume 145,775 195,152 156,320 Price $ 52.24 $ 53.17 $ 53.77 3-way collars Volume 113,029 — — Ceiling sold price (call) $ 77.00 — — Floor purchased price (put) $ 60.00 — — Floor sold price (short put) $ 45.00 — — 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, 2016 2015 Asset commodity derivatives: Current assets $ 734,464 $ 1,711,072 Noncurrent assets 54,380 — 788,844 1,711,072 Liability commodity derivatives: Current liabilities (2,074,915 ) — Noncurrent liabilities (1,269,931 ) — (3,344,846 ) — Total commodity derivative instruments $ (2,556,002 ) $ 1,711,072 Net gains (losses) from commodity derivatives on the Consolidated Statements of Operations are comprised of the following: Years Ended December 31, 2016 2015 Derivative settlements $ 1,607,365 $ 10,344,207 Mark to market on commodity derivatives (5,382,619 ) (7,025,203 ) Net gains (losses) from commodity derivatives $ (3,775,254 ) $ 3,319,004

PREFERRED STOCK

PREFERRED STOCK	12 Months Ended
	Dec. 31, 2016
Preferred Stock Abstract
PREFERRED STOCK	On March 8, 2013, Davis issued 27,442,727 shares of Series A Convertible Preferred Stock (“Series A Preferred Stock”) providing for cumulative dividends of 7.0% per annum, payable in-kind, for approximately $15.1 million in proceeds. Proceeds from the issuance of the Series A Preferred Stock, along with $14.0 million in borrowings under its senior credit facility and available cash were used to purchase 65,672,512 shares of Davis’ common stock in March 2013. From January 1, 2016 through October 26, 2016, and during 2015, Davis issued 1,952,801 and 2,236,986 shares of Series A Preferred Stock, respectively, as paid in-kind dividends and as of October 26, 2016 immediately prior to the completion of the Davis Merger, there were 35,319,988 shares of Series A Preferred Stock outstanding. As part of the closing of the Davis Merger, each share of Series A Preferred Stock was converted into 0.04966536 shares of Series D Preferred Stock of the Company. The Company 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, which is convertible into shares of the Company’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 $11.0741176. 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 the closing of the Davis Merger, the Series D Preferred Stock had a liquidation preference of approximately $19.4 million and a conversion rate of $11.0741176 per share. The Series D Preferred Stock provides for cumulative dividends of 7.0% per annum, payable in-kind. The Company issued 22,539 shares of Series D Preferred Stock effective as of December 31, 2016 for the period from October 26, 2016 through December 31, 2016 inclusive.

STOCK-BASED COMPENSATION

STOCK-BASED COMPENSATION	12 Months Ended
	Dec. 31, 2016
Disclosure of Compensation Related Costs, Share-based Payments [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. 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, the Company assumed the Yuma California 2014 Long-Term Incentive Plan (the “2014 Plan”), which was approved by the shareholders of Yuma California. The shareholders of Yuma California originally approved the 2014 Plan at the special meeting of shareholders on September 10, 2014 and the subsequent amendment to the 2014 Plan at the special meeting of shareholders on October 26, 2016. Under the 2014 Plan, YEI may grant stock options, restricted stock awards, restricted stock units, stock appreciation rights, performance units, performance bonuses, stock awards and other incentive awards to employees of YEI and its subsidiaries and affiliates. YEI may also grant nonqualified stock options, restricted stock awards, restricted stock units, stock appreciation rights, performance units, stock awards and other incentive awards to any persons rendering consulting or advisory services and non-employee directors of YEI and its subsidiaries, subject to the conditions set forth in the 2014 Plan. Generally, all classes of YEI’s employees are eligible to participate in the 2014 Plan. The 2014 Plan provides that a maximum of 2,495,000 shares of common stock may be issued in conjunction with awards granted under the 2014 Plan. As of the closing of the Reincorporation Merger, there were awards for approximately 179,165 shares of common stock outstanding that were assumed by the Company. Awards that are forfeited under the 2014 Plan will again be eligible for issuance as though the forfeited awards had never been issued. Similarly, awards settled in cash will not be counted against the shares authorized for issuance upon exercise of awards under the 2014 Plan. The 2014 Plan provides that a maximum of 1,000,000 shares of common stock may be issued in conjunction with incentive stock options granted under the 2014 Plan. The 2014 Plan also limits the aggregate number of shares of common stock that may be issued in conjunction with stock options and/or SARs to any eligible employee in any calendar year to 1,500,000 shares. The 2014 Plan also limits the aggregate number of shares of common stock that may be issued in conjunction with the grant of RSAs, RSUs, performance unit awards, stock awards and other incentive awards to any eligible employee in any calendar year to 700,000 shares. At December 31, 2016, 2,151,811 shares of the 2,495,000 shares of common stock originally authorized under active share-based compensation plans remained available for future issuance. The Company generally issues new shares to satisfy awards under employee share-based payment plans. The number of shares available is reduced by awards granted. Davis Management Incentive Plan Davis had the Davis Petroleum Acquisition Corp. Management Incentive Plan (the “Davis Plan”) that was terminated as part of the closing of the Davis Merger and all outstanding stock options were cancelled or exchanged for Davis common stock prior to the closing of the Davis Merger and all outstanding restricted stock awards under the Davis Plan were vested or forfeited prior to the closing of the Davis Merger. Restricted Stock – A summary of the status of the RSAs for employees and non-employee directors and changes for the year to date ended December 31, 2016 is presented below. Number of Weighted average unvested grant-date RSA shares fair value Unvested shares as of January 1, 2016 235,646 $14.82 per share Granted on February 10, 2016 24,833 $3.96 per share Vested on February 10, 2016 (24,833 ) $3.96 per share Vested on April 1, 2016 (164,765 ) $14.07 per share Vested on May 1, 2016 (56,768 ) $16.57 per share Vested on October 5, 2016 (14,113 ) $18.22 per share Assumed on October 26, 2016 79,237 $4.40 per share Vested on November 1, 2016 (623 ) $4.40 per share Vested on December 31, 2016 (278 ) $4.40 per share Forfeited — Unvested shares as of December 31, 2016 78,336 $4.40 per share At December 31, 2016, total unrecognized RSA compensation cost of $111,187 is expected to be recognized over a weighted average remaining service period of approximately one year. Stock Appreciation Rights – Weighted Number of average unvested grant-date SARs fair value Unvested shares as of January 1, 2016 — Assumed on October 26, 2016 56,165 $2.35 per share Forfeited — Unvested shares as of December 31, 2016 56,165 $2.35 per share Assumptions used to estimate fair value of the SARs assumed were expected life of 5.8 years, 84.2% volatility, 1.42% risk-free rate, and zero annual dividends. At December 31, 2016, total unrecognized SAR compensation cost of $100,309 is expected to be recognized over a weighted average remaining service period of approximately one year. 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 Options – The Company assumed stock options issued by Yuma California as compensation to non-employee directors under the Yuma California 2006 Equity Incentive Plan (the “2006 Plan”). The options vested immediately, and are exercisable for a five-year period from the date of the grant. 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, 2015 337,452 $ 16.03 5.70 $ — Granted — — — — Exercised — — — — Forfeited (337,452 ) $ 16.03 4.84 — Assumed 5,000 $ 103.20 1.77 — Outstanding at December 31, 2016 5,000 $ 103.20 1.77 $ — Vested at December 31, 2016 5,000 $ 103.20 1.77 $ — Exercisable at December 31, 2016 5,000 $ 103.20 1.77 $ — 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 assumed were expected life of two years, 115.5% volatility, 0.85% risk-free rate, and zero annual dividends. As of December 31, 2016, there were no unvested stock options or unrecognized stock option expenses. Total share-based compensation expense recognized for the years ended December 31, 2016 and 2015 was $1,731,969 and $933,017, respectively, and is reflected in general and administrative expenses in the Consolidated Statements of Operations. These amounts are net of share-based compensation capitalized to the full cost pool for the years ended December 31, 2016 and 2015 of $1,717,698 and $-0-, respectively.

NET LOSS PER COMMON SHARE

NET LOSS PER COMMON SHARE	12 Months Ended
	Dec. 31, 2016
LOSS PER COMMON SHARE:
NET LOSS PER COMMON SHARE	Net 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. Equity, including the average number of shares of common stock and per share amounts, has been retroactively restated to reflect the Davis Merger. A reconciliation of loss per common share is as follows: Years Ended December 31, 2016 2015 Net loss attributable to common stockholders $ (42,651,060 ) $ (63,546,168 ) Net loss per common share: Basic $ (5.13 ) $ (8.58 ) Diluted $ (5.13 ) $ (8.58 ) Weighted average common shares outstanding Basic 8,317,777 7,409,201 Add potentially dilutive securities: Unvested restricted stock awards — — Stock appreciation rights — — Stock options — — Series A preferred stock — — Series D preferred stock — — Diluted weighted average common shares outstanding 8,317,777 7,409,201 For the year ended December 31, 2016, the Company excluded 78,336 shares of unvested restricted stock awards, 84,248 stock appreciation rights, 5,000 stock options, and 1,776,718 shares of Series D Preferred Stock in calculating diluted earnings per share, as the effect was anti-dilutive. For the year ended December 31, 2015, the Company excluded 235,646 shares of unvested restricted stock awards, 337,452 stock options, and 1,657,193 shares of Series A 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, 2016
Debt Disclosure [Abstract]
DEBT AND INTEREST EXPENSE	Long-term debt at December 31 consisted of the following: December 31, 2016 2015 Senior credit facility $ 39,500,000 $ — Installment loan due 7/15/17 originating from the financing of insurance premiums at 4.38% interest rate 599,341 — Total debt 40,099,341 — Less: current maturities (599,341 ) — Total long-term debt $ 39,500,000 $ — Senior Credit Facility In December 2008, Davis amended and restated its senior credit agreement (the “senior credit facility”) with a financial institution. The senior credit facility was subsequently amended in April 2011, January 2013, January 2016 and September 2016. The senior credit facility was paid off as part of the closing of the Davis Merger and the Company subsequently entered into the Credit Agreement (discussed below). In connection with the closing of the Davis Merger, on October 26, 2016, YEI 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 SocGen, as administrative agent, SG Americas Securities, LLC (“SG Americas”), as lead arranger and bookrunner, and the Lenders signatory thereto (collectively with SocGen, the “Lender”). The initial borrowing base of the credit facility was $44.0 million, which was reaffirmed as of January 1, 2017. The borrowing base is 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, 2016 was 4.52% and was based on LIBOR. 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. The Company is 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 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. 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, 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, a ratio of EBITDAX to interest expense for the four fiscal quarters ending on the last day of the fiscal quarter immediately preceding such date of determination to be less than 2.75 to 1.0, and cash and cash equivalent investments together with borrowing availability under the Credit Agreement of at least $3.0 million. EBITDAX is defined in the Credit Agreement as, for any period, the sum of consolidated net income for such period plus the following expenses or charges to the extent deducted from consolidated net income in such period: interest, income taxes, depreciation, depletion, amortization, non-cash losses as a result of changes in fair market value of derivatives, and oil and gas exploration and abandonment expenses, extraordinary or non-recurring losses, other non-cash charges reducing consolidated net income for such period, minus non-cash income included in consolidated net income and any extraordinary or non-recurring items increasing consolidated net income for such period. For fiscal quarters ending prior to and not including the fiscal quarter ending December 31, 2017, EBITDAX will be calculated using an annualized EBITDAX and interest expense will be calculated using an annualized interest expense. Annualized EBITDAX is defined in the Credit Agreement as, (a) EBITDAX for the four-fiscal quarter period ending on December 31, 2016 will be deemed to equal EBITDAX for such fiscal quarter multiplied by four (4); (b) EBITDAX for the four-fiscal quarter period ending March 31, 2017 will be deemed to equal EBITDAX for the two-fiscal quarter period comprising the fiscal quarter ending December 31, 2016 and the fiscal quarter ending March 31, 2017, multiplied by two (2); and (c) EBITDAX for the four-fiscal quarter period ending June 30, 2017 will be deemed to equal EBITDAX for the three-fiscal quarter period comprising the fiscal quarter ending December 31, 2016, the fiscal quarter ending March 31, 2017 and the fiscal quarter ending June 30, 2017, multiplied by four-thirds (4/3). Annualized interest expense is defined in the Credit Agreement as, (i) interest expense for the four-fiscal quarter period ending on December 31, 2016 will be deemed to equal interest expense for such fiscal quarter multiplied by four (4); (ii) interest expense for the four-fiscal quarter period ending March 31, 2017 will be deemed to equal interest expense for the two-fiscal quarter period comprising the fiscal quarter ending December 31, 2016 and the fiscal quarter ending March 31, 2017, multiplied by two (2); and (iii) interest expense for the four-fiscal quarter period ending June 30, 2017 will be deemed to equal interest expense for the three-fiscal quarter period comprising the fiscal quarter ending December 31, 2016, the fiscal quarter ending March 31, 2017 and the fiscal quarter ending June 30, 2017, multiplied by four-thirds (4/3). The Company is in compliance with its debt covenants at December 31, 2016. 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. The Company incurred commitment fees of $22,855 and $62,958 during 2016 and 2015, respectively.

STOCKHOLDERS' EQUITY

STOCKHOLDERS' EQUITY	12 Months Ended
	Dec. 31, 2016
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 13 – 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.

INCOME TAXES

INCOME TAXES	12 Months Ended
	Dec. 31, 2016
Income Tax Disclosure [Abstract]
INCOME TAXES	The provision for income taxes for the years ending December 31 follows: December 31, 2016 2015 Current expense (benefit) Federal $ — $ — State — 6,000 Deferred expense (benefit) Federal — 11,060,403 State 1,425,964 (605,601 ) Total income tax expense $ 1,425,964 $ 10,460,802 A reconciliation of the federal statutory income tax rate to the effective income tax rate for the years ended December 31 follows: December 31, 2016 2015 U. S. statutory rate 35.00 % 35.00 % State income taxes (net of federal benefit) (3.55 %) 1.16 % Nondeductible transaction costs (2.84 %) 0.00 % Stock compensation (4.07 %) 0.00 % Other (0.01 %) (0.01 %) Valuation allowance (28.08 %) (56.32 %) Effective tax rate (3.55 %) (20.17 %) Deferred income tax (liabilities) assets at December 31 follow: December 31, 2016 2015 Deferred income tax liabilities Property, plant and equipment $ — $ — Commodity derivative instruments — (594,910 ) — (594,910 ) Deferred income tax assets Net operating loss carryforward 52,258,483 21,522,598 Commodity derivative instruments 1,013,175 — Financial accruals and other 982,544 108,547 Asset retirement obligation 3,916,319 1,969,695 Property, plant and equipment 3,353,922 6,956,819 Stock-based compensation 26,051 1,801,701 Valuation allowance (61,550,494 ) (30,338,486 ) — 2,020,874 Deferred income taxes, net $ — $ 1,425,964 At December 31, 2016, the Company had federal and state net operating loss carryforwards of approximately $132.6 million which expire between 2022 and 2035. Of this amount, approximately $61.3 million is subject to limitation under Section 382 of the Code, which could result in some amounts expiring prior to being utilized. 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, 2016, the Company has recorded a full valuation allowance against its federal and state net deferred tax assets of $61.5 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, 2016, 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 2012 to 2016.

CONTINGENCIES

CONTINGENCIES	12 Months Ended
	Dec. 31, 2016
Commitments and Contingencies Disclosure [Abstract]
CONTINGENCIES	Certain Legal Proceedings From time to time, the Company is party to various legal proceedings arising in the ordinary course of business. While the outcome of lawsuits cannot be predicted with certainty, the Company is not currently a party to any proceeding that it believes, if determined in a manner adverse to the Company, could have a potential material adverse effect on its financial condition, results of operations, or cash flows. Ontiveros v. Pyramid Oil, LLC, Yuma Energy, Inc. et al In September 2015, a suit was filed against the Company and Pyramid Oil LLC styled Mark A. Ontiveros and Louise D. Ontiveros, Trustees of The Ontiveros Family Trust dated March 29, 2007 vs. Pyramid Oil, LLC, et al., Case Number 15CV02959 in the Superior Court of California, County of Santa Barbara, Cook Division. In the suit, the plaintiffs allege that the 1950 Community Oil and Gas Lease between them and Pyramid Oil LLC has expired by non-production. The Company claims that the lease is still in effect, as there is no cessation of production time frame set out in the lease; production had temporarily ceased, but was still profitable when measured over an appropriate time period; and the Company was conducting workover operations on a well on the lease in an effort to re-establish production when served with the quit claim deed demand from the plaintiff’s attorney. All present owners of the minerals covered by the 1950 Community Oil and Gas Lease, with the exception of the plaintiffs, have executed amendments signifying their concurrence that the 1950 Community Oil and Gas Lease is still in force and effect. On June 23, 2016, Pyramid Oil LLC filed a First Amended Cross Complaint against Texican Energy Corporation and Everett Lawley alleging interference with contractual relations and prospective economic relations, and violation of the California Uniform Trade Secrets Act. The parties are presently in the process of discovery. 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 are currently engaged in the arbitrator selection process. Management intends to pursue the Company’s claims and to defend the counterclaim vigorously. Environmental Remediation Contingencies As of December 31, 2016, there were no known environmental or other regulatory matters related to the Company’s operations that were reasonably expected to result in a material liability to the Company. The Company’s operations are subject to numerous laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. Vintage Assets, Inc. v. Tennessee Gas Pipeline, L.L.C. et al. On October 24, 2016, Texas Southeastern Gas Gathering Company (“TGG”), a subsidiary of the Company, was named as a defendant in an action by Vintage Assets, Inc. in the United States District Court for the Eastern District of Louisiana. Vintage claims that its property, located in Plaquemines Parish, has been damaged by the widening of canals used by the defendants. Between 1953 and 1970, the defendants’ predecessors received multiple right-of-way servitudes on Vintage’s property, which authorized the construction and operation of pipelines and dredge canals. The defendants dredged canals and laid pipelines pursuant to the rights of way agreements. Vintage alleges that its property has suffered damage because of defendants’ failure to maintain the pipeline canals and banks. Further, Vintage alleges that this failure has caused ecological damages and loss of acreage due to erosion. The action is currently scheduled for trial in September 2017. Management intends to defend the plaintiffs’ claims vigorously and has notified its insurance carrier of the claim. TGG sold all of its assets to High Point Gas Gathering in 2010. 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 books. Counsel for plaintiffs has been informed that TGG was dissolved and terminated as of 2011, and has been furnished with confirming documentation. Counsel for plaintiffs is considering dismissal of the claims against TGG. The Parish of St. Bernard v. Atlantic Richfield Co., et al On October 13, 2016, two subsidiaries of the Company, 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. 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 books. The case has been removed to federal district court for the Eastern District of Louisiana. A motion to remand has been filed, but has not yet been ruled upon. Davis - Cameron Parish vs. BEPCO LP, et al Davis - 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, 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. Motions to remand have been filed but have not yet been ruled upon. Audits 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. 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. Exploration is currently waiting on the Department of Revenue’s final audit results. The exposure related to this audit is not currently determinable.

EMPLOYEE BENEFIT PLANS

EMPLOYEE BENEFIT PLANS	12 Months Ended
	Dec. 31, 2016
Compensation and Retirement Disclosure [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 currently provides a match for employees at a rate of 100 percent of each employee’s contribution up to six percent during periods prior to the closing of the Davis Merger, and up to four percent of the employee’s base salary after the closing of the Davis Merger. The Company contributed $102,358 and $169,067 under the 401(k) Plan for the years ended December 31, 2016 and 2015, 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 95 percent for the employee portion of the premium, and 85 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 $185,503 and $-0- for the years ended December 31, 2016 and 2015, respectively. The Company maintains employment contracts with members of its exploration staff and with certain key employees of the Company. As of December 31, 2016, future employment contract salary commitments were $709,325, excluding automatic renewals, evergreen and month-to-month provisions, and potential Annual Incentive Plan awards.

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, 2016
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, 2016
Risks and Uncertainties [Abstract]
SALES TO MAJOR CUSTOMERS	In 2016 and 2015, approximately 39% and 38%, respectively, of the Company’s natural gas, oil, and NGL 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, 2016, and 2015, sales to five customers accounted for approximately 78% and sales to four customers accounted to approximately 84%, 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. Substantially all of the Company’s accounts receivable at December 31, 2016 and 2015 were from sales of natural gas and crude oil as well as joint interest billings to third party companies also in the oil and gas industry. At December 31, 2016, there were five customers that represented approximately 78% of the Company’s accounts receivable balance. At December 31, 2015, there were four customers that represented approximately 75% of the Company’s accounts receivable balance. This concentration of customers and joint interest owners may impact the Company’s overall credit risk, either positively or negatively, in that these entities may be similarly affected by changes in economic or other conditions.

LEASE OBLIGATIONS AND OTHER COM

LEASE OBLIGATIONS AND OTHER COMMITMENTS	12 Months Ended
	Dec. 31, 2016
Leases [Abstract]
LEASE OBLIGATIONS AND OTHER COMMITMENTS	The Company leases its primary office space of 15,180 square feet for $24,035 per month, plus $50 per month for each employee or contractor parking space. The lease term expires on December 31, 2017. The Company 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, 2017. Aggregate rental expense for fiscal years 2016 and 2015 was $546,272 and $501,641, respectively. As of December 31, 2016, future minimum rentals under all noncancellable operating leases are as follows: 2017 $ 551,325 2018 2,264 2019 — 2020 — 2021 —

SUBSEQUENT EVENTS

SUBSEQUENT EVENTS	12 Months Ended
	Dec. 31, 2016
Subsequent Events [Abstract]
SUBSEQUENT EVENTS	Joint Development Agreement On March 27, 2017, the Company entered into a Joint Development Agreement with Firethorn Petroleum, LLC and Carnes Natural Gas, Ltd., both unaffiliated entities, covering an area of approximately 52 square miles (33,280 acres) in Yoakum County, Texas. In connection with the agreement, the Company has acquired an 87.5% interest in approximately 2,269 existing gross (1,985 net) leasehold acres. As the operator of the property covered by this agreement, the Company is committed to spend an additional $2.1 million towards the development of this acreage position and intends to acquire additional leasehold acreage and begin drilling its first joint venture well in 2017.

SUPPLEMENTARY INFORMATION ON OI

SUPPLEMENTARY INFORMATION ON OIL AND NATURAL GAS EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES (UNAUDITED)	12 Months Ended
	Dec. 31, 2016
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 Davis in the year ended December 31, 2015. Information at and for the year ended December 31, 2016 combines Davis’ reserve and other information with that of Yuma California resulting from the Davis Merger. Reserves Proved natural gas and oil reserves are those quantities of natural gas and oil, 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 natural gas or oil 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 natural gas and oil 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 natural gas and oil 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. Internal Controls Over Reserve and Future Net Revenue Estimation The Company’s principal engineer is the Executive Vice President and Chief Operating Officer and is the person primarily responsible for overseeing the preparation of the Company’s internal reserve estimates and for overseeing the independent petroleum engineering firm during the preparation of the Company’s reserve report. His experience includes, among other things, detailed evaluation of reserves and future net revenues for acquisitions, divestments, bank financing, long range planning, portfolio optimization, strategy and end of year financial reports. He has a B.S. in Petroleum Engineering from Louisiana Tech University and is a member of the Society of Petroleum Engineers (the “SPE”). His professional qualifications meet or exceed the qualifications of reserve estimators and auditors set forth in the “Standards Pertaining to Estimation and Auditing of Oil and Gas Reserves Information” promulgated by the SPE. The Executive Vice President and Chief Operating Officer reports directly to the Company’s Chief Executive Officer. At December 31, 2016 and 2015, Netherland, Sewell & Associates, Inc. (“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. Third Party Procedures and Methods Review In preparation of the reserve report, NSAI’s review consisted of 34 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, 2016 and 2015. The Chief Operating Officer 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 gas producing activities, and based on natural gas and crude oil reserve and production volumes estimated by the Company’s engineering staff. 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 2016 and 2015. 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, 2016 2015 Costs incurred for the year: Exploration (including geological and geophysical costs) $ 23,000 $ — Development 8,268,653 3,847,000 Acquisition of properties, net (1) 55,479,000 1,401,000 Capitalized overhead 3,688,642 1,502,000 Lease acquisition costs, net of recoveries 670,514 899,000 Total costs incurred $ 68,129,809 $ 7,649,000 (1) Acquisition costs incurred during 2016 consisted entirely of assets acquired in the Davis Merger described in Note 4 - Acquisitions and Divestments. During the years ended December 31, 2016 and 2015, total costs incurred included estimated cost of future abandonment of $6.5 million and $0.8 million, respectively. Capitalized costs for oil and natural gas properties are as follows: December 31, 2016 2015 Oil and natural gas properties Capitalized Unproved properties $ 3,656,989 $ 178,761 Proved properties 488,723,905 425,767,477 Total oil and gas properties 492,380,894 425,946,238 Less accumulated DD&A (410,440,433 ) (381,987,616 ) Net oil and natural gas properties capitalized $ 81,940,461 $ 43,958,622 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 natural gas and crude oil 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, 2014 1,995,900 717,400 12,650,500 4,821,700 Revisions of previous estimates (871,400 ) 14,100 3,711,100 (238,800 ) Extension, discoveries and other additions 261,200 403,600 2,132,100 1,020,200 Purchases of minerals in place 12,800 25,100 516,600 124,000 Sales of minerals in place (21,300 ) (2,300 ) (945,100 ) (181,100 ) Production (209,500 ) (129,700 ) (2,547,300 ) (763,800 ) Proved reserves at December 31, 2015 1,167,700 1,028,200 15,517,900 4,782,200 Revisions of previous estimates (3,913,400 ) (1,253,000 ) (12,481,500 ) (7,246,700 ) Extension, discoveries and other additions 286,900 — 30,400 292,000 Purchases of minerals in place 5,682,100 1,685,700 23,322,800 11,255,000 Sales of minerals in place (75,400 ) (7,900 ) (84,300 ) (97,400 ) Production (172,000 ) (104,700 ) (2,326,400 ) (664,400 ) Proved reserves at December 31, 2016 2,975,900 1,348,300 23,978,900 8,320,700 Proved developed reserves December 31, 2014 1,084,900 579,400 11,901,600 3,647,900 December 31, 2015 703,300 604,300 10,464,300 3,051,600 December 31, 2016 2,203,000 1,061,000 21,918,700 6,917,100 Proved undeveloped reserves December 31, 2014 911,000 138,000 748,900 1,173,800 December 31, 2015 464,400 423,900 5,053,600 1,730,600 December 31, 2016 772,900 287,300 2,060,200 1,403,600 In 2016, downward revisions of previous estimates are primarily due to removing undeveloped reserves in Masters Creek Field. The Company elected not to extend its Masters Creek acreage associated with these reserves due to the depressed price environment and The Company’s inability to attract a joint venture partner. 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, 2016 and 2015 were $2.48/MMbtu and $42.75/Bbl (West Texas Intermediate) and $2.59/MMbtu and $50.28/Bbl (West Texas Intermediate), respectively, 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 year-end 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, 2016 2015 Future cash inflows $ 200,115,200 $ 112,448,800 Future oil and natural gas operating expenses (67,735,300 ) (38,403,800 ) Future development costs (32,071,500 ) (21,947,100 ) Future income tax expenses — — Future net cash flows 100,308,400 52,097,900 10% annual discount for estimated timing of cash flows (26,708,300 ) (11,117,800 ) Standardized measure of discounted future net cash flows $ 73,600,100 $ 40,980,100 A summary of the changes in the standardized measure of discounted future net cash flows applicable to proved natural gas and crude oil reserves follows: Year Ended December 31, 2016 2015 January 1 $ 40,980,100 $ 101,671,500 Changes due to current year operation: Sales of oil and natural gas, net of oil and natural gas operating expenses (5,433,825 ) (10,769,400 ) Extensions and discoveries 2,739,700 3,534,100 Purchases of oil and natural gas properties 45,762,176 1,062,200 Development costs incurred during the period that reduced future development costs 7,077,036 2,094,500 Changes due to revisions in standardized variables: Prices and operating expenses (12,181,580 ) (66,321,100 ) Income taxes — — Estimated future development costs 1,915,239 15,321,900 Quantity estimates (7,876,109 ) (12,951,100 ) Sale of reserves in place (2,243,256 ) (2,784,500 ) Accretion of discount 4,098,010 10,167,200 Production rates, timing and other (1,237,391 ) (45,200 ) Net change 32,620,000 (60,691,400 ) December 31 $ 73,600,100 $ 40,980,100

SUMMARY OF SIGNIFICANT ACCOUN31

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)	12 Months Ended
	Dec. 31, 2016
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 net revenues; 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; future cash flows associated with oil and gas properties; obligations related to employee benefits such as accrued vacation; and legal and environmental risks and exposures.
Reclassifications	When required for comparability, reclassifications are made to the prior period financial statements to conform to the current year presentation. Reclassifications include moving COPAS overhead recoveries from lease operating expenses to general and administrative expenses, moving certain other revenue to offset lease operating expense, moving commodity derivative gains (losses) from expenses to other income (expense), and moving regulatory interest from general and administrative to interest expense.
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 10 – 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 10 – 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.
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 $1,042,565 and $-0- at December 31, 2016 and 2015, 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 recognized. Depreciation, Depletion and Amortization (“DD&A”) Impairments Unproved oil and natural gas properties not subject to amortization consist of undeveloped leaseholds and exploratory and developmental wells in progress before the assignment of proved reserves and related capitalized interest. Management reviews the costs of these properties quarterly to determine whether and to what extent 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 the full cost pool. 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 for 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, with the exception of the Yuma California properties that were acquired in the Davis Merger, which were recorded at fair value as of the closing date of the Davis Merger in accordance with business combination accounting principles. 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 “Total Expenses” in the accompanying Consolidated Statements of Operations. In the event that facts and circumstances indicate that the carrying value of other plant, 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.
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	Revenue is recognized by the Company when crude oil, natural gas and condensate are delivered to the purchaser and title has transferred. Crude oil sales in Louisiana, representing a significant portion of the Company’s production, are typically indexed to Light Louisiana Sweet (“LLS”). Sales are based on index prices per MMBtu or the daily “spot” price as published in national publications with a mark-up or mark-down defined by contract with each customer. Sales prices for natural gas and crude oil are adjusted for transportation costs and other related deductions. The transportation costs and other deductions are based on contractual or historical data and do not require significant judgment. Subsequently, these deductions and transportation costs are adjusted to reflect actual charges based on third party documents. Historically, these adjustments have been insignificant. Since there is a ready market for natural gas and crude oil, the Company sells the majority of its products soon after production at various locations where title and risk of loss pass to the buyer.
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 17 – 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 (see Note 16 – Stockholders’ Equity). The Company adopted an Annual Incentive Plan for fiscal years 2016 and 2015 (see Note 13 – Stock-Based Compensation and Note 19 – Employee Benefit Plans). 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 13 – Stock-Based Compensation).
Other Noncurrent Assets	Noncurrent assets at December 31, 2016 are comprised of deferred debt issuance costs related to the establishment of the new Société Générale (“SocGen”) credit facility, and in 2015, are comprised of Davis’ Bank of America credit facility. Debt issuance costs related to the SocGen credit facility are being amortized to interest expense over the term of the new credit facility, which expires on October 26, 2019, and had a carrying amount of $801,506 at December 31, 2016, of which $284,305 is classified as current other deferred charges and $517,201 is classified as other noncurrent assets. Amortization expense during the year ended December 31, 2016 and 2015 was $148,970 and $210,067, respectively.
Earnings per Share	The Company’s basic earnings per share (“EPS”) is computed based on the 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 14 – Net 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.
Changes in Accounting Principles	Not Yet 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 does not expect the adoption of this ASU to have a material impact on its Consolidated Statements of Cash Flows. In February 2016, the FASB issued ASU 2016-02, “Leases,” a new lease standard requiring lessees to recognize lease assets and lease liabilities for most leases classified as operating leases under previous GAAP. The guidance is effective for fiscal years beginning after December 15, 2018 with early adoption permitted. The Company will be required to use a modified retrospective approach for leases that exist or are entered into after the beginning of the earliest comparative period in the financial statements. The Company is currently evaluating the impact of adopting this standard on its Consolidated Financial Statements, but does believe that it will materially impact the Company’s consolidated financial statements. In January 2016, the FASB issued ASU 2016-01, “Recognition and Measurement of Financial Assets and Financial Liabilities,” which changes certain guidance related to the recognition, measurement, presentation and disclosure of financial instruments. This update is effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years. Early adoption is not permitted for the majority of the update, but is permitted for two of its provisions. The Company is evaluating the new guidance, but does not believe that it will materially impact the Company’s consolidated financial statement presentation. In May 2014, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers (Topic 606).” In March, April, and May of 2016, the FASB issued rules clarifying several aspects of the new revenue recognition standard. The new guidance is effective for fiscal years and interim periods beginning after December 15, 2017. This guidance outlines a new, single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance, including industry-specific guidance. This new revenue recognition model provides a five-step analysis in determining when and how revenue is recognized. The new model will require revenue recognition to depict the transfer of promised goods or services to customers in an amount that reflects the consideration a company expects to receive in exchange for those goods and services. The new standard also requires more detailed disclosures related to the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. The Company will not early adopt the standard although early adoption is permitted. The Company is currently evaluating whether to apply the retrospective approach or modified retrospective approach with the cumulative effect recognized as of the date of initial application. The Company is currently evaluating the impact the standard is expected to have on its consolidated financial statements by evaluating current revenue streams and evaluating contracts under the revised standards. Recently adopted 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 provides a screen that when substantially all of the fair value of the gross assets acquired, or disposed of, are concentrated in a single identifiable asset, or a group of similar identifiable assets, the set will not be considered a business. If the screen is not met, a set must include an input and a substantive process that together significantly contribute to the ability to create an output to be considered 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 goodwill would not be allocated to divestitures or recorded for acquisitions that are not considered to be businesses. The FASB issued ASU 2016-09, “Compensation—Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting,” The FASB issued ASU 2015-03, “Interest – Imputation of Interest (Subtopic 835-30) – Simplifying the Presentation of Debt Issuance Costs,” which requires debt issuance costs to be presented in the balance sheet as a direct reduction from the associated debt liability. In August 2015, the FASB subsequently issued ASU 2015-15, “Interest – Imputation of Interest (Subtopic 835-30) – Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements,” a clarification as to the handling of debt issuance costs related to line-of-credit arrangements that allows the presentation of these costs as an asset. The standards update is effective for interim and annual periods beginning after December 15, 2015. The Company has debt costs associated with its line-of-credit only; therefore, this standard had no impact on its consolidated financial statements. These costs remain an asset on the Company’s Consolidated Balance Sheets. The FASB issued ASU 2014-15, “Presentation of Financial Instruments – Going Concern,” which requires management of an entity to evaluate whether there are conditions or events, considered in the aggregate, that raise substantial doubt about the entity’s ability to continue as a going concern within one year after the date that the financial statements are issued or available to be issued. This update is effective for annual periods ending after December 15, 2016. The adoption of this standard did not have a material impact on the Company’s consolidated financial statements.

ORGANIZATION AND BASIS OF PRE32

ORGANIZATION AND BASIS OF PRESENTATION (Tables)	12 Months Ended
	Dec. 31, 2016
Organization And Basis Of Presentation Tables
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 Pyramid Delaware Merger Subsidiary, Inc. “PDMS” Delaware 02/04/2014

PREPAYMENTS (Tables)

PREPAYMENTS (Tables)	12 Months Ended
	Dec. 31, 2016
Prepayments Tables
Prepayments	December 31, 2016 2015 Prepaid insurance $ 817,268 $ 152,709 Prepaid taxes 97,934 — Other prepayments 148,216 175,509 Total prepayments $ 1,063,418 $ 328,218

ACQUISITIONS AND DIVESTMENTS (T

ACQUISITIONS AND DIVESTMENTS (Tables)	12 Months Ended
	Dec. 31, 2016
Acquisitions And Divestments Tables
Consideration transferred	Purchase Consideration Common stock (1) $ 20,883 Stock appreciation rights (2) 85 Stock options (3) 1 Restricted stock awards (4) 181 Restricted stock units (5) — Debt (6) 30,202 Net purchase considered to be allocated $ 51,352 Estimated fair value of assets acquired Proved natural gas and oil properties $ 54,974 Unproved natural gas and oil properties 505 Real property 2,755 Personal property 1,427 Commodity derivatives - asset 1,195 Deposits 414 Other assets 485 Other long-term assets 2 Total assets acquired 61,757 Estimated fair value of liabilities acquired Net working capital (4,453 ) Asset retirement obligation (5,874 ) Commodity derivatives - liabilities (78 ) Total liabilities acquired (10,405 ) Total assets and liabilities acquired $ 51,352 (1) 4,746,180 shares of Yuma California Common Stock were effectively transferred in connection with the Davis Merger. Those shares were valued at $4.40 per share, which was the last sales price of Yuma California Common Stock at October 26, 2016. The October 26, 2016 share price used is the same date as the October 26, 2016 NYMEX strip price applied in Yuma California’s most recent engineering reports. (2) Yuma California’s stock appreciation rights were valued using the binomial lattice model. (3) Yuma California’s 5,000 stock options were valued at approximately $0.259 per option using the Black-Scholes model. (4) 901 restricted stock awards vested in 2016 and the 78,336 restricted stock awards vesting in 2017 and 2018 were valued at $4.40 per share on October 26, 2016. (5) Yuma California had no restricted stock units outstanding at October 26, 2016. (6) Debt fair value approximates the related book value at October 26, 2016.
Pro forma results	Years Ended December 31, 2016 2015 ($ in thousands) (Unaudited) (Unaudited) Revenues $ 24,536 $ 45,813 Net loss $ (41,829 ) $ (70,884 ) Net loss per share: Basic $ (3.43 ) $ (5.80 ) Diluted $ (3.43 ) $ (5.80 )

PROPERTY, PLANT, AND EQUIPMEN35

PROPERTY, PLANT, AND EQUIPMENT, NET (Tables)	12 Months Ended
	Dec. 31, 2016
Property Plant And Equipment Net Tables
Property, plant and equipment	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 production, exploration, and development activities at December 31: December 31, 2016 2015 Subject to amortization (proved properties) $ 488,723,905 $ 425,767,477 Less: Accumulated depreciation, depletion, amortization and impairment (410,440,433 ) (381,987,616 ) Proved properties, net $ 78,283,472 $ 43,779,861 Not subject to amortization (unproved properties) Leasehold acquisition costs 2,411,402 178,761 Exploration and development 1,219,466 — Capitalized Interest 26,121 — Total unproved properties 3,656,989 178,761 Oil and gas properties, net $ 81,940,461 $ 43,958,622 A summary of the Company’s unevaluated properties by year incurred follows: Year Incurred 2016 2015 and prior Total Leasehold acquisition costs $ 2,232,641 $ 178,761 $ 2,411,402 Exploration and development 1,219,466 — 1,219,466 Capitalized interest 26,121 — 26,121 Total $ 3,478,228 $ 178,761 $ 3,656,989 Other property and equipment consists of the following: Estimated useful December 31, life in years 2016 2015 Plants and pipeline systems 10 $ 4,218,496 $ 4,599,177 Land n/a 1,314,000 — Software and IT equipment 3 - 5 964,581 2,006,133 Drilling and operating equipment 15 841,494 — Furniture and fixtures 7 - 10 820,584 666,816 Buildings 25 286,000 179,054 Automobiles 3 - 7 207,115 158,531 Office leasehold improvements 10 84,260 1,424,846 Total other property and equipment 8,736,530 9,034,557 Less: Accumulated depreciation and leasehold improvement amortization (5,349,145 (7,357,964 ) Net book value $ 3,387,385 $ 1,676,593

ASSET RETIREMENT OBLIGATIONS (T

ASSET RETIREMENT OBLIGATIONS (Tables)	12 Months Ended
	Dec. 31, 2016
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligations	December 31, 2016 2015 Beginning of year balance $ 5,332,050 $ 7,226,164 Liabilities assumed in the merger 5,873,504 — Liabilities incurred during year 277,876 1,078,792 Liabilities settled during year (572,623 ) (1,164,927 ) Liabilities sold during year (1,334,215 ) (1,740,971 ) Accretion expense 254,573 175,643 Revisions in estimated cash flows 365,218 (242,651 ) End of year balance $ 10,196,383 $ 5,332,050

ACCOUNTS RECEIVABLE FROM CHIE37

ACCOUNTS RECEIVABLE FROM CHIEF EXECUTIVE OFFICER AND EMPLOYEES (Tables)	12 Months Ended
	Dec. 31, 2016
Accounts Receivable From Chief Executive Officer And Employees Tables
Information with respect to related party transactions with affiliates	December 31, 2016 2015 Receivables from affiliates, CEO and employees: Current: CEO $ 67,114 $ — Employees 900 1,121 Total $ 68,014 $ 1,121

FAIR VALUE MEASUREMENTS (Tables

FAIR VALUE MEASUREMENTS (Tables)	12 Months Ended
	Dec. 31, 2016
Fair Value Disclosures [Abstract]
Fair value measurements by hierarchy	Fair value measurements at December 31, 2016 Significant Quoted prices other Significant in active observable unobservable markets inputs inputs (Level 1) (Level 2) (Level 3) Total Liabilities: Commodity derivatives – oil $ — $ 956,997 $ — $ 956,997 Commodity derivatives – gas — 1,599,005 — $ 1,599,005 Total liabilities $ — $ 2,556,002 $ — $ 2,556,002 Fair value measurements at December 31, 2015 Significant Quoted prices other Significant in active observable unobservable markets inputs inputs (Level 1) (Level 2) (Level 3) Total Assets: Commodity derivatives – oil $ — $ 1,711,072 $ — $ 1,711,072 Commodity derivatives – gas — — — — Total assets $ — $ 1,711,072 $ — $ 1,711,072

COMMODITY DERIVATIVE INSTRUME39

COMMODITY DERIVATIVE INSTRUMENTS (Tables)	12 Months Ended
	Dec. 31, 2016
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Commodity derivative instruments	2017 2018 2019 Settlement Settlement Settlement NATURAL GAS (MMBtu): Swaps Volume 2,381,776 1,451,734 — Price $ 3.13 $ 3.00 — 3-way collars Volume 248,023 — — Ceiling sold price (call) $ 3.28 — — Floor purchased price (put) $ 2.95 — — Floor sold price (short put) $ 2.38 — — CRUDE OIL (Bbls): Swaps Volume 145,775 195,152 156,320 Price $ 52.24 $ 53.17 $ 53.77 3-way collars Volume 113,029 — — Ceiling sold price (call) $ 77.00 — — Floor purchased price (put) $ 60.00 — — Floor sold price (short put) $ 45.00 — —
Schedule of derivative assets and liablities	Fair value as of December 31, 2016 2015 Asset commodity derivatives: Current assets $ 734,464 $ 1,711,072 Noncurrent assets 54,380 — 788,844 1,711,072 Liability commodity derivatives: Current liabilities (2,074,915 ) — Noncurrent liabilities (1,269,931 ) — (3,344,846 ) — Total commodity derivative instruments $ (2,556,002 ) $ 1,711,072
Gains (losses) from commodity derivatives	Years Ended December 31, 2016 2015 Derivative settlements $ 1,607,365 $ 10,344,207 Mark to market on commodity derivatives (5,382,619 ) (7,025,203 ) Net gains (losses) from commodity derivatives $ (3,775,254 ) $ 3,319,004

STOCK-BASED COMPENSATION (Table

STOCK-BASED COMPENSATION (Tables)	12 Months Ended
	Dec. 31, 2016
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, 2015 337,452 $ 16.03 5.70 $ — Granted — — — — Exercised — — — — Forfeited (337,452 ) $ 16.03 4.84 — Assumed 5,000 $ 103.20 1.77 — Outstanding at December 31, 2016 5,000 $ 103.20 1.77 $ — Vested at December 31, 2016 5,000 $ 103.20 1.77 $ — Exercisable at December 31, 2016 5,000 $ 103.20 1.77 $ —
Restricted Stock Awards (RSAs) [Member]
Summary of the Company's stock option activity	Number of Weighted average unvested grant-date RSA shares fair value Unvested shares as of January 1, 2016 235,646 $14.82 per share Granted on February 10, 2016 24,833 $3.96 per share Vested on February 10, 2016 (24,833 ) $3.96 per share Vested on April 1, 2016 (164,765 ) $14.07 per share Vested on May 1, 2016 (56,768 ) $16.57 per share Vested on October 5, 2016 (14,113 ) $18.22 per share Assumed on October 26, 2016 79,237 $4.40 per share Vested on November 1, 2016 (623 ) $4.40 per share Vested on December 31, 2016 (278 ) $4.40 per share Forfeited — Unvested shares as of December 31, 2016 78,336 $4.40 per share
Stock Appreciation Rights (SARs) [Member]
Summary of the Company's stock option activity	Weighted Number of average unvested grant-date SARs fair value Unvested shares as of January 1, 2016 — Assumed on October 26, 2016 56,165 $2.35 per share Forfeited — Unvested shares as of December 31, 2016 56,165 $2.35 per share

NET LOSS PER COMMON SHARE (Tabl

NET LOSS PER COMMON SHARE (Tables)	12 Months Ended
	Dec. 31, 2016
LOSS PER COMMON SHARE:
Potentially dilutive securities for the computation of diluted weighted average number of shares	Years Ended December 31, 2016 2015 Net loss attributable to common stockholders $ (42,651,060 ) $ (63,546,168 ) Net loss per common share: Basic $ (5.13 ) $ (8.58 ) Diluted $ (5.13 ) $ (8.58 ) Weighted average common shares outstanding Basic 8,317,777 7,409,201 Add potentially dilutive securities: Unvested restricted stock awards — — Stock appreciation rights — — Stock options — — Series A preferred stock — — Series D preferred stock — — Diluted weighted average common shares outstanding 8,317,777 7,409,201

DEBT AND INTEREST EXPENS (Table

DEBT AND INTEREST EXPENS (Tables)	12 Months Ended
	Dec. 31, 2016
Debt And Interest Expens Tables
Long term Debt	December 31, 2016 2015 Senior credit facility $ 39,500,000 $ — Installment loan due 7/15/17 originating from the financing of insurance premiums at 4.38% interest rate 599,341 — Total debt 40,099,341 — Less: current maturities (599,341 ) — Total long-term debt $ 39,500,000 $ —

INCOME TAXES (Tables)

INCOME TAXES (Tables)	12 Months Ended
	Dec. 31, 2016
Income Tax Disclosure [Abstract]
Provisions for income taxes	December 31, 2016 2015 Current expense (benefit) Federal $ — $ — State — 6,000 Deferred expense (benefit) Federal — 11,060,403 State 1,425,964 (605,601 ) Total income tax expense $ 1,425,964 $ 10,460,802
Reconciliation of the federal statutory income tax rate	December 31, 2016 2015 U. S. statutory rate 35.00 % 35.00 % State income taxes (net of federal benefit) (3.55 %) 1.16 % Nondeductible transaction costs (2.84 %) 0.00 % Stock compensation (4.07 %) 0.00 % Other (0.01 %) (0.01 %) Valuation allowance (28.08 %) (56.32 %) Effective tax rate (3.55 %) (20.17 %)
Deferred tax liabilities (assets)	December 31, 2016 2015 Deferred income tax liabilities Property, plant and equipment $ — $ — Commodity derivative instruments — (594,910 ) — (594,910 ) Deferred income tax assets Net operating loss carryforward 52,258,483 21,522,598 Commodity derivative instruments 1,013,175 — Financial accruals and other 982,544 108,547 Asset retirement obligation 3,916,319 1,969,695 Property, plant and equipment 3,353,922 6,956,819 Stock-based compensation 26,051 1,801,701 Valuation allowance (61,550,494 ) (30,338,486 ) — 2,020,874 Deferred income taxes, net $ — $ 1,425,964

LEASE OBLIGATIONS AND OTHER C44

LEASE OBLIGATIONS AND OTHER COMMITMENTS (Tables)	12 Months Ended
	Dec. 31, 2016
Leases [Abstract]
Future minimum rentals under all noncancellable leases	2017 $ 551,325 2018 2,264 2019 — 2020 — 2021 —

SUPPLEMENTARY INFORMATION ON 45

SUPPLEMENTARY INFORMATION ON OIL AND NATURAL GAS EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES (UNAUDITED) (Tables)	12 Months Ended
	Dec. 31, 2016
Supplementary Information On Oil And Natural Gas Exploration Development And Production Activities Tables
Costs Incurred	Years Ended December 31, 2016 2015 Costs incurred for the year: Exploration (including geological and geophysical costs) $ 23,000 $ — Development 8,268,653 3,847,000 Acquisition of properties, net (1) 55,479,000 1,401,000 Capitalized overhead 3,688,642 1,502,000 Lease acquisition costs, net of recoveries 670,514 899,000 Total costs incurred $ 68,129,809 $ 7,649,000 (1) Acquisition costs incurred during 2016 consisted entirely of assets acquired in the Davis Merger described in Note 4 - Acquisitions and Divestments.
Capitalized Costs Relating to Oil and Gas Producing Activities	December 31, 2016 2015 Oil and natural gas properties Capitalized Unproved properties $ 3,656,989 $ 178,761 Proved properties 488,723,905 425,767,477 Total oil and gas properties 492,380,894 425,946,238 Less accumulated DD&A (410,440,433 ) (381,987,616 ) Net oil and natural gas properties capitalized $ 81,940,461 $ 43,958,622
Reserve	Oil (bbls) NGL (bbls) Gas (mcf) Boe Proved reserves at December 31, 2014 1,995,900 717,400 12,650,500 4,821,700 Revisions of previous estimates (871,400 ) 14,100 3,711,100 (238,800 ) Extension, discoveries and other additions 261,200 403,600 2,132,100 1,020,200 Purchases of minerals in place 12,800 25,100 516,600 124,000 Sales of minerals in place (21,300 ) (2,300 ) (945,100 ) (181,100 ) Production (209,500 ) (129,700 ) (2,547,300 ) (763,800 ) Proved reserves at December 31, 2015 1,167,700 1,028,200 15,517,900 4,782,200 Revisions of previous estimates (3,913,400 ) (1,253,000 ) (12,481,500 ) (7,246,700 ) Extension, discoveries and other additions 286,900 — 30,400 292,000 Purchases of minerals in place 5,682,100 1,685,700 23,322,800 11,255,000 Sales of minerals in place (75,400 ) (7,900 ) (84,300 ) (97,400 ) Production (172,000 ) (104,700 ) (2,326,400 ) (664,400 ) Proved reserves at December 31, 2016 2,975,900 1,348,300 23,978,900 8,320,700 Proved developed reserves December 31, 2014 1,084,900 579,400 11,901,600 3,647,900 December 31, 2015 703,300 604,300 10,464,300 3,051,600 December 31, 2016 2,203,000 1,061,000 21,918,700 6,917,100 Proved undeveloped reserves December 31, 2014 911,000 138,000 748,900 1,173,800 December 31, 2015 464,400 423,900 5,053,600 1,730,600 December 31, 2016 772,900 287,300 2,060,200 1,403,600
Discounted future net cash flows	Year Ended December 31, 2016 2015 Future cash inflows $ 200,115,200 $ 112,448,800 Future oil and natural gas operating expenses (67,735,300 ) (38,403,800 ) Future development costs (32,071,500 ) (21,947,100 ) Future income tax expenses — — Future net cash flows 100,308,400 52,097,900 10% annual discount for estimated timing of cash flows (26,708,300 ) (11,117,800 ) Standardized measure of discounted future net cash flows $ 73,600,100 $ 40,980,100
Change in Standardized Measure	Year Ended December 31, 2016 2015 January 1 $ 40,980,100 $ 101,671,500 Changes due to current year operation: Sales of oil and natural gas, net of oil and natural gas operating expenses (5,433,825 ) (10,769,400 ) Extensions and discoveries 2,739,700 3,534,100 Purchases of oil and natural gas properties 45,762,176 1,062,200 Development costs incurred during the period that reduced future development costs 7,077,036 2,094,500 Changes due to revisions in standardized variables: Prices and operating expenses (12,181,580 ) (66,321,100 ) Income taxes — — Estimated future development costs 1,915,239 15,321,900 Quantity estimates (7,876,109 ) (12,951,100 ) Sale of reserves in place (2,243,256 ) (2,784,500 ) Accretion of discount 4,098,010 10,167,200 Production rates, timing and other (1,237,391 ) (45,200 ) Net change 32,620,000 (60,691,400 ) December 31 $ 73,600,100 $ 40,980,100

ORGANIZATION AND BASIS OF PRE46

ORGANIZATION AND BASIS OF PRESENTATION (Details)	12 Months Ended
	Dec. 31, 2016
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
Pyramid Delaware Merger Subsidiary, Inc. [Member]
Reference	“PDMS”
State of incorporation	Delaware
Date of incorporation	Feb. 4, 2014

SUMMARY OF SIGNIFICANT ACCOUN47

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details Narrative)	12 Months Ended
	Dec. 31, 2016USD ($)$ / Unit	Dec. 31, 2015USD ($)$ / Unit
Summary Of Significant Accounting Policies Details Narrative
Allowance for doubtful accounts	$ 1,042,565	$ 0
Depreciation, depletion and amortization rate per boe | $ / Unit	11.67	21.67
Depreciation, depletion and amortization expense for oil and natural gas properties	$ 7,756,107	$ 16,547,787
Capitalized interest associated with line of credit	26,121	0
Capitalized internal costs	3,447,779	1,500,181
Debt issuance costs	801,506
Amortization expense	$ 148,970	$ 210,067

PREPAYMENTS (Details)

PREPAYMENTS (Details) - USD ($)	Dec. 31, 2016	Dec. 31, 2015
Prepayments Details
Prepaid insurance	$ 817,268	$ 152,709
Prepaid taxes	97,934	0
Other prepayments	148,216	175,509
Total prepayments	$ 1,063,418	$ 328,218

ACQUISITIONS AND DIVESTMENTS (D

ACQUISITIONS AND DIVESTMENTS (Details) $ in Thousands	10 Months Ended
	Oct. 26, 2016USD ($)
Purchase Consideration
Common stock	$ 20,883	[1]
Stock appreciation rights	85	[2]
Stock options	1	[3]
Restricted stock awards	181	[4]
Restricted stock units	0	[5]
Debt	30,202	[6]
Net purchase considered to be allocated	51,352
Estimated fair value of assets acquired
Proved natural gas and oil properties	54,974
Unproved natural gas and oil properties	505
Real property	2,755
Personal property	1,427
Commodity derivatives - asset	1,195
Deposits	414
Other assets	485
Other long-term assets	2
Total assets acquired	61,757
Estimated fair value of liabilities acquired
Net working capital	(4,453)
Asset retirement obligation	(5,874)
Commodity derivatives - liabilities	(78)
Total liabilities acquired	(10,405)
Total assets and liabilities acquired	$ 51,352
[1]	4,746,180 shares of Yuma California Common Stock were effectively transferred in connection with the Davis Merger. Those shares were valued at $4.40 per share, which was the last sales price of Yuma California Common Stock at October 26, 2016. The October 26, 2016 share price used is the same date as the October 26, 2016 NYMEX strip price applied in Yuma California's most recent engineering reports.
[2]	Yuma California's stock appreciation rights were valued using the binomial lattice model.
[3]	Yuma California's 5,000 stock options were valued at approximately $0.259 per option using the Black-Scholes model.
[4]	901 restricted stock awards vested in 2016 and the 78,336 restricted stock awards vesting in 2017 and 2018 were valued at $4.40 per share on October 26, 2016.
[5]	Yuma California had no restricted stock units outstanding at October 26, 2016.
[6]	Debt fair value approximates the related book value at October 26, 2016.

ACQUISITIONS AND DIVESTMENTS 50

ACQUISITIONS AND DIVESTMENTS (Details 1) - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Business Combinations [Abstract]
Revenues	$ 24,536	$ 45,813
Net loss	$ (41,829)	$ (70,884)
Net loss per share:
Basic	$ (3.43)	$ (5.80)
Diluted	$ (3.43)	$ (5.80)

ASSET IMPAIRMENTS (Details Narr

ASSET IMPAIRMENTS (Details Narrative) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Asset Impairments Details Narrative
Oil and gas impairment	$ 20,654,848	$ 40,479,906

PROPERTY, PLANT, AND EQUIPMEN52

PROPERTY, PLANT, AND EQUIPMENT, NET (Details) - USD ($)	Dec. 31, 2016	Dec. 31, 2015
Property Plant And Equipment Net Details
Subject to amortization (proved properties)	$ 488,723,905	$ 425,767,477
Less: Accumulated depreciation, depletion, amortization and impairment	410,440,433	381,987,616
Proved properties, net	78,283,472	43,779,861
Not subject to amortization (unproved properties)
Leasehold acquisition costs	2,411,402	178,761
Exploration and development	1,219,466	0
Capitalized Interest	26,121	0
Total unproved properties	3,656,989	178,761
Oil and gas properties, net	$ 81,940,461	$ 43,958,622

PROPERTY, PLANT, AND EQUIPMEN53

PROPERTY, PLANT, AND EQUIPMENT, NET (Details 1)	12 Months Ended
	Dec. 31, 2016USD ($)
Leasehold acquisition cost	$ 2,411,402
Exploration and development cost	1,219,466
Capitalized interest	26,121
Total	3,656,989
2016 [Member]
Leasehold acquisition cost	2,232,641
Exploration and development cost	1,219,466
Capitalized interest	26,121
Total	3,478,228
2015 and prior [Member]
Leasehold acquisition cost	178,761
Exploration and development cost	0
Capitalized interest	0
Total	$ 178,761

PROPERTY, PLANT, AND EQUIPMEN54

PROPERTY, PLANT, AND EQUIPMENT, NET (Details 2) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Plants and pipeline systems	$ 4,218,496	$ 4,599,177
Land	1,314,000	0
Drilling and operating equipment	841,494	0
Software and IT equipment	964,581	2,006,133
Furniture and fixtures	820,584	666,816
Buildings	286,000	179,054
Automotive	207,115	158,531
Office leasehold improvements	84,260	1,424,846
Total other property and equipment	8,736,530	9,034,557
Less: Accumulated depreciation and leasehold improvement amortization	(5,349,145)	(7,357,964)
Net book value	$ 3,387,385	$ 1,676,593
Plants and pipeline systems [Member]
Estimated useful life in years	10 years
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 EQUIPMEN55

PROPERTY, PLANT, AND EQUIPMENT, NET (Details Narrative) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Property Plant And Equipment Net Details Narrative
Depreciation and leasehold improvement amortization expense	$ 483,695	$ 591,350

ASSET RETIREMENT OBLIGATIONS (D

ASSET RETIREMENT OBLIGATIONS (Details) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Asset Retirement Obligation Disclosure [Abstract]
Beginning of year balance	$ 5,332,050	$ 7,226,164
Liabilities assumed in merger	5,873,504	0
Liabilities incurred during year	277,876	1,078,792
Liabilities settled during year	(572,623)	(1,164,927)
Liabilities sold during year	(1,334,215)	(1,740,971)
Accretion expense	254,573	175,643
Revisions in estimated cash flows	365,218	(242,651)
End of year balance	$ 10,196,383	$ 5,332,050

ACCOUNTS RECEIVABLE FROM CHIE57

ACCOUNTS RECEIVABLE FROM CHIEF EXECUTIVE OFFICER AND EMPLOYEES (Details) - USD ($)	Dec. 31, 2016	Dec. 31, 2015
Current	$ 68,014	$ 1,121
Yuma CEO [Member]
Current	67,114	0
Employee [Member]
Current	$ 900	$ 1,121

FAIR VALUE MEASUREMENTS (Detail

FAIR VALUE MEASUREMENTS (Details) - USD ($)	Dec. 31, 2016	Dec. 31, 2015
Total assets		$ 1,711,072
Total liabilities	$ 2,556,002
Commodity derivatives oil
Total assets		1,711,072
Total liabilities	956,997
Commodity derivatives gas
Total assets		0
Total liabilities	1,599,005
Level 1
Total assets		0
Total liabilities	0
Level 1 | Commodity derivatives oil
Total assets		0
Total liabilities	0
Level 1 | Commodity derivatives gas
Total assets		0
Total liabilities	0
Level 2
Total assets		1,711,072
Total liabilities	2,556,002
Level 2 | Commodity derivatives oil
Total assets		1,711,072
Total liabilities	956,997
Level 2 | Commodity derivatives gas
Total assets		0
Total liabilities	1,599,005
Level 3
Total assets		0
Total liabilities	0
Level 3 | Commodity derivatives oil
Total assets		0
Total liabilities	0
Level 3 | Commodity derivatives gas
Total assets		$ 0
Total liabilities	$ 0

COMMODITY DERIVATIVE INSTRUME59

COMMODITY DERIVATIVE INSTRUMENTS (Details)	Dec. 31, 2019bbl$ / bbl	Dec. 31, 2018bblMMBbls$ / MMBTU$ / bbl	Dec. 31, 2017bblMMBbls$ / MMBTU$ / bbl
Swaps
Natural Gas (MMBtu):
Volume | MMBbls		1,451,734	2,381,776
Price | $ / MMBTU		3	3.13
Crude Oil:
Volume | bbl	156,320	195,152	145,775
Price | $ / bbl	53.77	53.17	52.24
3-Way Collars
Natural Gas (MMBtu):
Volume | MMBbls			248,023
Ceiling sold price (call) | $ / MMBTU			3.28
Floor purchased price (put) | $ / MMBTU			2.95
Floor sold price (short put) | $ / MMBTU			2.38
Crude Oil:
Volume | bbl			113,029
Ceiling sold price (call) | $ / bbl			77
Floor purchased price (put) | $ / bbl			60
Floor sold price (short put) | $ / bbl			45

COMMODITY DERIVATIVE INSTRUME60

COMMODITY DERIVATIVE INSTRUMENTS (Details 1) - USD ($)	Dec. 31, 2016	Dec. 31, 2015
Asset commodity derivatives:
Current assets	$ 734,464	$ 1,711,072
Noncurrent assets	54,380	0
Total	788,844	1,711,072
Liability commodity derivatives:
Current liabilities	(2,074,915)	0
Noncurrent liabilities	(1,269,931)	0
Total	(3,344,846)	0
Total commodity derivative instruments	$ (2,556,002)	$ 1,711,072

COMMODITY DERIVATIVE INSTRUME61

COMMODITY DERIVATIVE INSTRUMENTS (Details 2) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
C. Commodity Derivative Instruments Details 1
Derivative settlements	$ 1,607,365	$ 10,344,207
Mark to market on commodity derivatives	(5,382,619)	(7,025,203)
Net gains (losses) from commodity derivatives	$ (3,775,254)	$ 3,319,004

STOCK-BASED COMPENSATION (Detai

STOCK-BASED COMPENSATION (Details) - RSA	12 Months Ended
	Dec. 31, 2016$ / sharesshares
Number of unvested RSA shares
Unvested shares as of January 1, 2016 | shares	235,646
Granted on February 10, 2016 | shares	24,833
Vested on February 10, 2016 | shares	(24,833)
Vested on April 1, 2016 | shares	(164,765)
Vested on May 1, 2016 | shares	(56,768)
Vested on October 5, 2016 | shares	(14,113)
Assumed on October 26, 2016 | shares	79,237
Vested on November 1, 2016 | shares	(623)
Vested on December 31, 2016 | shares	(278)
Forfeited | shares	0
Unvested shares as of December 31, 2016 | shares	78,336
Weighted Average Grant-Date Fair Value
Unvested per shares as of January 1, 2016 | $ / shares	$ 14.82
Granted on February 10, 2016 | $ / shares	3.96
Vested on February 10, 2016 | $ / shares	3.96
Vested on April 1, 2016 | $ / shares	14.07
Vested on May 1, 2016 | $ / shares	16.57
Vested on October 5, 2016 | $ / shares	18.22
Assumed on October 26, 2016 | $ / shares	4.40
Vested on November 1, 2016 | $ / shares	4.40
Vested on December 31, 2016 | $ / shares	4.40
Forfeited | $ / shares	0
Unvested per shares as of December 31, 2016 | $ / shares	$ 4.40

STOCK-BASED COMPENSATION (Det63

STOCK-BASED COMPENSATION (Details 1) - Stock Appreciation Rights (SARs) [Member]	12 Months Ended
	Dec. 31, 2016$ / sharesshares
Number of unvested SAR shares
Unvested shares as of January 1, 2016 | shares	0
Assumed on October 26, 2016 | shares	56,165
Forfeited | shares	0
Unvested shares as of December 31, 2016 | shares	56,165
Weighted Average Grant-Date Fair Value
Unvested per shares as of January 1, 2016 | $ / shares	$ 0
Assumed on October 26, 2016 | $ / shares	2.35
Forfeited | $ / shares	0
Unvested per shares as of December 31, 2016 | $ / shares	$ 2.35

STOCK-BASED COMPENSATION (Det64

STOCK-BASED COMPENSATION (Details 2)	12 Months Ended
	Dec. 31, 2016USD ($)$ / sharesshares
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Number of Options Outstanding, Beginning | shares	337,452
Number of Options Granted | shares	0
Number of Options Exercised | shares	0
Number of Options Forfeited | shares	(337,452)
Number of Options Assumed | shares	5,000
Number of Options Outstanding, Ending | shares	5,000
Vested and expected to vest December 31, 2016 | shares	5,000
Number of shares Options Exercisable | shares	5,000
Weighted Average Exercise Price Outstanding	$ 16.03
Weighted Average Exercise Price Granted	0
Weighted Average Exercise Price Exercised	0
Weighted Average Exercise Price Forfeited	16.03
Weighted Average Exercise Price Assumed	103.20
Weighted Average Exercise Price Outstanding	103.20
Weighted Average Exercise Price Vested and expected to vest at December 31, 2016	103.20
Weighted Average Exercise Price Exercisable	$ 103.20
Weighted Average Remaining Contractual Life (in years) Outstanding	5 years 8 months 12 days
Weighted Average Remaining Contractual Life (in years) Forfeited	4 years 10 months 2 days
Weighted Average Remaining Contractual Life (in years) Assumed	1 year 9 months 7 days
Weighted Average Remaining Contractual Life (in years) Vested and expected to vest at December 31, 2016	1 year 9 months 7 days
Weighted Average Remaining Contractual Life (in years) Exercisable	1 year 9 months 7 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 Assumed	$ 0
Aggregate Intrinsic Value Outstanding, Ending | $	$ 0
Aggregate Intrinsic Value Vested and expected to vest at December 31, 2016 | $	0
Aggregate Intrinsic Value Exercisable at December 31, 2016 | $	$ 0

STOCK-BASED COMPENSATION (Det65

STOCK-BASED COMPENSATION (Details Narrative) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Weighted average remaining service period	5 years 8 months 12 days
Share-based compensation expense	$ 1,731,969	$ 933,017
Restricted Stock Awards (RSAs) [Member]
Unrecognized compensation cost	$ 111,187
Weighted average remaining service period	1 year
Stock Appreciation Rights (SARs) [Member]
Unrecognized compensation cost	$ 100,309
Weighted average remaining service period	1 year
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%

EARNINGS PER COMMON SHARE (Deta

EARNINGS PER COMMON SHARE (Details) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
LOSS PER COMMON SHARE:
Net loss attributable to common stockholders	$ (42,651,060)	$ (63,546,168)
Net loss per common share:
Basic	$ (5.13)	$ (8.58)
Diluted	$ (5.13)	$ (8.58)
Weighted average common shares outstanding
Basic	8,317,777	7,409,201
Add potentially dilutive securities
Unvested restricted stock awards	0	0
Stock appreciation rights	0	0
Stock options	0	0
Series A preferred stock	0	0
Series D preferred stock	0	0
Diluted weighted average common shares outstanding	8,317,777	7,409,201

DEBT AND INTEREST EXPENSE (Deta

DEBT AND INTEREST EXPENSE (Details) - USD ($)	Dec. 31, 2016	Dec. 31, 2015
Total Debt	$ 40,099,341	$ 0
Less: current portion	(599,341)	0
Total long-term debt	39,500,000	0
Senior credit facility [Member]
Total Debt	39,500,000	0
Installment loan due 7/15/17 [Member]
Total Debt	$ 599,341	$ 0

DEBT AND INTEREST EXPENSE (De68

DEBT AND INTEREST EXPENSE (Details Narrative) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Debt And Interest Expense Details Narrative
Commitment fees	$ 22,855	$ 62,958

INCOME TAXES (Details)

INCOME TAXES (Details) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Current income taxes (benefit):
Federal	$ 0	$ 0
State	0	6,000
Deferred income taxes (benefit):
Federal	0	11,060,403
State	1,425,964	(605,601)
Total income tax expense	$ 1,425,964	$ 10,460,802

INCOME TAXES (Details 1)

INCOME TAXES (Details 1)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Income Taxes Details 1
U. S. statutory rate	35.00%	35.00%
State income taxes (net of federal benefit)	(3.55%)	1.16%
Nondeductible transaction costs	(2.84%)	0.00%
Stock compensation	(4.07%)	0.00%
Other	(0.01%)	(0.01%)
Valuation allowance	(28.08%)	(56.32%)
Effective tax rate	(3.55%)	(20.17%)

INCOME TAXES (Details 2)

INCOME TAXES (Details 2) - USD ($)	Dec. 31, 2016	Dec. 31, 2015
Deferred income tax liabilities
Property, plant and equipment	$ 0	$ 0
Commodity derivative instruments	0	(594,910)
Deferred tax liability	0	(594,910)
Deferred income tax assets
Net operating loss carryforward	52,258,483	21,522,598
Commodity derivative instruments	1,013,175	0
Financial accruals and other	982,544	108,547
Asset retirement obligation	3,916,319	1,969,695
Property, plant and equipment	3,353,922	6,956,819
Stock based compensation	26,051	1,801,701
Valuation allowance	(61,550,494)	(30,338,486)
Deferred tax asset	0	2,020,874
Net deferred tax asset (liability)	$ 0	$ 1,425,964

INCOME TAXES (Details Narrative

INCOME TAXES (Details Narrative)	Dec. 31, 2016USD ($)
Income Taxes Details Narrative
Net operating loss carryforwards	$ 132,600,000
Net operating loss carryforwards valuation allowance	$ 61,500,000

EMPLOYEE BENEFIT PLANS (Details

EMPLOYEE BENEFIT PLANS (Details Narrative) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Compensation and Retirement Disclosure [Abstract]
Defined Contribution Plan, Employer Matching Contribution, Percent	100.00%
Defined Contribution Plan, Employer Contribution	$ 102,358	$ 169,067
Accrued liability for compensated absences	185,503	$ 0
Future employment contract salary commitments	$ 709,325

SALES TO MAJOR CUSTOMERS (Detai

SALES TO MAJOR CUSTOMERS (Details Narrative)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Sales To Major Customers Details Narrative
Number of major customer	5	4
Oil and natural gas sales to major customers (percent)	78.00%	84.00%

LEASE OBLIGATIONS AND OTHER C75

LEASE OBLIGATIONS AND OTHER COMMITMENTS (Details)	Dec. 31, 2016USD ($)
Future minimum rentals under all noncancellable operating leases
2,017	$ 551,325
2,018	2,264
2,019	0
2,020	0
2,021	$ 0

LEASE OBLIGATIONS AND OTHER C76

LEASE OBLIGATIONS AND OTHER COMMITMENTS (Details Narrative) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Lease Obligations And Other Commitments Details Narrative
Aggregate rental expense	$ 546,272	$ 501,641

SUPPLEMENTARY INFORMATION ON 77

SUPPLEMENTARY INFORMATION ON OIL AND NATURAL GAS EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES (UNAUDITED) (Details) - USD ($)		12 Months Ended
		Dec. 31, 2016	Dec. 31, 2015
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Exploration (including geological and geophysical costs)		$ 23,000	$ 0
Development		8,268,653	3,847,000
Acquisition of properties, net	[1]	55,479,000	1,401,000
Capitalized overhead		3,688,642	1,502,000
Lease acquisition costs, net of recoveries		670,514	899,000
Total costs incurred		$ 68,129,809	$ 7,649,000
[1]	Acquisition costs incurred during 2016 consisted entirely of assets acquired in the Davis Merger described in Note 4 - Acquisitions and Divestments.

SUPPLEMENTARY INFORMATION ON 78

SUPPLEMENTARY INFORMATION ON OIL AND NATURAL GAS EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES (UNAUDITED) (Details 1) - USD ($)	Dec. 31, 2016	Dec. 31, 2015
Oil and natural gas properties, Capitalized
Unproved properties	$ 3,656,989	$ 178,761
Proved properties	488,723,905	425,767,477
Total oil and gas properties	492,380,894	425,946,238
Less accumulated DD&A	(410,440,433)	(381,987,616)
Net oil and natural gas properties capitalized	$ 81,940,461	$ 43,958,622

SUPPLEMENTARY INFORMATION ON 79

SUPPLEMENTARY INFORMATION ON OIL AND NATURAL GAS EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES (UNAUDITED) (Details 2)	12 Months Ended
	Dec. 31, 2016bblMMcf	Dec. 31, 2015bblMMcf
Oil in (Bbls) [Member]
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves, Beginning of year	1,167,700	1,995,900
Revisions of Previous Estimates	(3,913,400)	(871,400)
Extension, discoveries and other additions	286,900	261,200
Purchases of minerals in place	5,682,100	12,800
Sales of minerals in place	(75,400)	(21,300)
Production	(172,000)	(209,500)
Proved developed and undeveloped reserves, End of year	2,975,900	1,167,700
Proved developed reserves, Beginning of the year	703,300	1,084,900
Proved developed reserves, End of year	2,203,000	703,300
Proved undeveloped reserves, Beginning of year	464,400	911,000
Proved undeveloped reserves, End of year	772,900	464,400
NGL in (Bbls) [Member]
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves, Beginning of year	1,028,200	717,400
Revisions of Previous Estimates	(1,253,000)	14,100
Extension, discoveries and other additions	0	403,600
Purchases of minerals in place	1,685,700	25,100
Sales of minerals in place	(7,900)	(2,300)
Production	(104,700)	(129,700)
Proved developed and undeveloped reserves, End of year	1,348,300	1,028,200
Proved developed reserves, Beginning of the year	604,300	579,400
Proved developed reserves, End of year	1,061,000	604,300
Proved undeveloped reserves, Beginning of year	423,900	138,000
Proved undeveloped reserves, End of year	287,300	423,900
Natural Gas (in Mcf) [Member]
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves, Beginning of year | MMcf	15,517,900	12,650,500
Revisions of Previous Estimates | MMcf	(12,481,500)	3,711,100
Extension, discoveries and other additions | MMcf	30,400	2,132,100
Purchases of minerals in place | MMcf	23,322,800	516,600
Sales of minerals in place | MMcf	(84,300)	(945,100)
Production | MMcf	(2,326,400)	(2,547,300)
Proved developed and undeveloped reserves, End of year | MMcf	23,978,900	15,517,900
Proved developed reserves, Beginning of the year | MMcf	10,464,300	11,901,600
Proved developed reserves, End of year | MMcf	21,918,700	10,464,300
Proved undeveloped reserves, Beginning of year | MMcf	5,053,600	748,900
Proved undeveloped reserves, End of year | MMcf	2,060,200	5,053,600
BOE [Member]
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves, Beginning of year	4,782,200	4,821,700
Revisions of Previous Estimates	(7,246,700)	(238,800)
Extension, discoveries and other additions	292,000	1,020,200
Purchases of minerals in place	11,255,000	124,000
Sales of minerals in place	(97,400)	(181,100)
Production	(664,400)	(763,800)
Proved developed and undeveloped reserves, End of year	8,320,700	4,782,200
Proved developed reserves, Beginning of the year	3,051,600	3,647,900
Proved developed reserves, End of year	6,917,100	3,051,600
Proved undeveloped reserves, Beginning of year	1,730,600	1,173,800
Proved undeveloped reserves, End of year	1,403,600	1,730,600

SUPPLEMENTARY INFORMATION ON 80

SUPPLEMENTARY INFORMATION ON OIL AND NATURAL GAS EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES (UNAUDITED) (Details 3) - USD ($)	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Future cash inflows	$ 200,115,200	$ 112,448,800
Future oil and natural gas operating expenses	(67,735,300)	(38,403,800)
Future development costs	(32,071,500)	(21,947,100)
Future income tax expenses	0	0
Future net cash flows	100,308,400	52,097,900
10% annual discount for estimating timing of cash flows	(26,708,300)	(11,117,800)
Standardized measure of discounted future net cash flows	$ 73,600,100	$ 40,980,100	$ 101,671,500

SUPPLEMENTARY INFORMATION ON 81

SUPPLEMENTARY INFORMATION ON OIL AND NATURAL GAS EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES (UNAUDITED) (Details 4) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Beginning of year	$ 40,980,100	$ 101,671,500
Changes due to current year operation:
Sales of oil and natural gas, net of oil and natural gas operating expenses	(5,433,825)	(10,769,400)
Extensions and discoveries	2,739,700	3,534,100
Purchases of oil and gas properties	45,762,176	1,062,200
Development costs incurred during the period that reduced future development costs	7,077,036	2,094,500
Changes due to revisions in standardized variables:
Prices and operating expenses	(12,181,580)	(66,321,100)
Income taxes	0	0
Estimated future development costs	1,915,239	15,321,900
Quantity estimates	(7,876,109)	(12,951,100)
Sale of reserves in place	(2,243,256)	(2,784,500)
Accretion of discount	4,098,010	10,167,200
Production rates, timing and other	(1,237,391)	(45,200)
End of year	$ 73,600,100	$ 40,980,100

SUPPLEMENTARY INFORMATION ON 82

SUPPLEMENTARY INFORMATION ON OIL AND NATURAL GAS EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES (Details Narrative)	12 Months Ended
	Dec. 31, 2016$ / MMBTU$ / bbl	Dec. 31, 2015$ / MMBTU$ / bbl
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Crude oil prices used in computing future cash flow | $ / bbl	42.75	50.28
Natural gas prices used in computing future cash flow | $ / MMBTU	2.48	2.59