Yuma Energy 10-K 30 Mar 16 2015 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2015	Mar. 29, 2016	Jun. 30, 2015
Document And Entity Information
Entity Registrant Name	Yuma Energy, Inc.
Entity Central Index Key	81,318
Document Type	10-K
Document Period End Date	Dec. 31, 2015
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			$ 14,956,252
Entity Common Stock, Shares Outstanding		71,911,361
Document Fiscal Period Focus	FY
Document Fiscal Year Focus	2,015

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($)	Dec. 31, 2015	Dec. 31, 2014
CURRENT ASSETS:
Cash and cash equivalents	$ 5,355,191	$ 11,558,322
Short-term investments		1,170,868
Accounts receivable, net of allowance for doubtful accounts:
Trade	$ 2,829,266	9,739,737
Officers and employees	75,404	316,077
Other	633,573	856,562
Commodity derivative instruments	2,658,047	3,338,537
Prepayments	704,523	782,234
Other deferred charges	415,740	342,798
Total current assets	12,671,744	28,105,135
OIL AND GAS PROPERTIES (full cost method):
Not subject to amortization	14,288,716	25,707,052
Subject to amortization	204,512,038	186,530,863
Subtotal	218,800,754	212,237,915
Less: accumulated depreciation, depletion and amortization	(117,304,945)	(103,929,493)
Net oil and gas properties	101,495,809	108,308,422
OTHER PROPERTY AND EQUIPMENT:
Land, buildings and improvements	2,795,000	2,795,000
Other property and equipment	3,460,507	3,439,688
Total	6,255,507	6,234,688
Less: accumulated depreciation and amortization	(2,174,316)	(1,909,352)
Net other property and equipment	4,081,191	4,325,336
OTHER ASSETS AND DEFERRED CHARGES:
Commodity derivative instruments	1,070,541	1,403,109
Deposits	$ 264,064	264,064
Goodwill		5,349,988
Other noncurrent assets	$ 38,104	262,200
Total other assets and deferred charges	1,372,709	7,279,361
Total assets	119,621,453	148,018,254
CURRENT LIABILITIES:
Current maturities of debt	30,063,635	282,843
Accounts payable, principally trade	7,933,664	$ 25,004,364
Asset retirement obligations	70,000
Other accrued liabilities	1,781,484	$ 1,419,565
TOTAL CURRENT LIABILITIES	$ 39,848,783	26,706,772
LONG-TERM DEBT:
Bank debt		22,900,000
OTHER NONCURRENT LIABILITIES:
Asset retirement obligations	$ 8,720,498	12,487,770
Deferred taxes	$ 6,797,166	14,773,306
Restricted stock units		71,569
Other liabilities	$ 30,090	22,451
Total other noncurrent liabilities	15,547,754	27,355,096
EQUITY:
Preferred stock	10,828,603	9,958,217
Common stock, no par value (300 million shares authorized, 71,834,617 and 69,139,869 issued)	$ 141,858,946	137,469,772
Accumulated other comprehensive income		38,801
Accumulated earnings (deficit)	$ (88,462,633)	(76,410,404)
Total equity	64,224,916	71,056,386
Total liabilities and equity	$ 119,621,453	$ 148,018,254

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) - $ / shares	Dec. 31, 2015	Dec. 31, 2014
Balance Sheet Parentherical [Abstract]
Common stock, shares par value	$ 0	$ 0
Common stock, shares authorized	300,000,000	300,000,000
Common Stock, shares, Issued	71,834,617	69,139,869

CONSOLIDATED STATEMENTS OF OPER

CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
REVENUES:
Sales of natural gas and crude oil	$ 18,680,584	$ 38,659,392	$ 28,235,413
Net gains (losses) from commodity derivatives	5,038,826	3,398,518	(159,810)
Total revenues	23,719,410	42,057,910	28,075,603
EXPENSES:
Marketing cost of sales	532,985	1,045,177	1,234,308
Lease operating	11,401,309	12,816,725	9,316,364
Re-engineering and workovers	555,539	3,084,972	2,521,707
General and administrative - stock-based compensation	2,289,311	3,388,321	452,058
General and administrative - other	7,434,304	8,156,077	4,536,506
Depreciation, depletion and amortization	13,651,207	19,664,991	12,077,368
Asset retirement obligation accretion expense	604,538	$ 604,511	$ 668,497
Goodwill impairment	5,349,988
Other	468,221	$ 98,476	$ 171,774
Total expenses	42,287,402	48,859,250	30,978,582
INCOME (LOSS) FROM OPERATIONS	$ (18,567,992)	(6,801,340)	(2,902,979)
OTHER INCOME (EXPENSE):
Change in fair value of preferred stock derivative liability - Series A and Series B		(15,676,842)	(26,258,559)
Interest expense	$ (456,423)	(326,200)	(567,676)
Other, net	36,338	25,378	(240,617)
Total other income (expense)	(420,085)	(15,977,664)	(27,066,852)
NET INCOME (LOSS) BEFORE INCOME TAXES	(18,988,077)	(22,779,004)	(29,969,831)
Income tax expense (benefit)	(7,983,039)	(2,553,854)	3,080,272
NET INCOME (LOSS)	(11,005,038)	(20,225,150)	$ (33,050,103)
PREFERRED STOCK:
Dividends paid in cash, perpetual preferred Series A	1,047,191	$ 224,098
Dividends in arrears, perpetual preferred Series A	$ 213,751
Accretion, Series A and Series B		$ 786,536	$ 1,101,972
Dividends paid in cash, Series A and Series B		445,152	145,900
Dividends paid in kind, Series A and Series B		4,133,380	5,412,281
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCKHOLDERS	$ (12,265,980)	$ (25,814,316)	$ (39,710,256)
EARNINGS (LOSS) PER COMMON SHARE:
Basic	$ (0.17)	$ (0.52)	$ (0.97)
Diluted	$ (0.17)	$ (0.52)	$ (0.97)
WEIGHTED AVERAGE NUMBER OF COMMON SHARES OUTSTANDING:
Basic	71,013,717	49,678,444	41,074,953
Diluted	71,013,717	49,678,444	41,074,953

CONSOLIDATED STATEMENTS OF COMP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Consolidated Statements Of Comprehensive Income
NET INCOME (LOSS)	$ (11,005,038)	$ (20,225,150)	$ (33,050,103)
OTHER COMPREHENSIVE INCOME (LOSS):
Commodity derivatives sold	(119,917)
Less income taxes	(46,168)
Commodity derivatives sold, net of income taxes	(73,749)
Reclassification of (gain) loss on settled commodity derivatives	56,826	$ 50	$ (374,099)
Less income taxes	21,878	19	(144,028)
Reclassification of (gain) loss on settled commodity derivatives, net of income taxes	34,948	31	(230,071)
OTHER COMPREHENSIVE INCOME (LOSS)	(38,801)	31	(230,071)
COMPREHENSIVE LOSS	$ (11,043,839)	$ (20,225,119)	$ (33,280,174)

CONSOLIDATED STATEMENTS OF CHAN

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY - USD ($)	PERPETUAL PREFERRED STOCK	COMMON STOCK	ACCUMULATED OTHER COMPREHENSIVE INCOME	ACCUMULATED EARNINGS (DEFICIT)	Total
Beginning Balance, Amount at Dec. 31, 2012	$ 0	$ 2,182,833	$ 268,841	$ (10,885,832)
Beginning Balance, Shares at Dec. 31, 2012	0	40,896,221
Sales of shares of common stock, Amount	$ 0	$ 0
Sales of shares of common stock, Shares	0
Employee restricted stock awards, Amount		$ 486,632
Employee restricted stock awards, Shares		178,729
Buy back of shares from vested stock awards, Amount		$ 0
Stock appreciation rights issued, not vested, Amount		0
Restricted stock unit awards, Amount		0
Convert preferred stock to shares of common stock, Amount		0
Pyramid Oil Company shares outstanding last day of trading, Amount		0
Fair value of Pyramid Oil Company stock options		0
Comprehensive income (loss) from commodity derivative instruments, net of income taxes			(230,071)
Net loss attributable to Yuma Energy, Inc.				(33,050,103)	$ (33,050,103)
Series A perpetual preferred stock cash dividends				0
Preferred stock accretion (Series A and B)				(1,101,972)
Preferred stock cash dividends (Series A and B)				(145,900)
Preferred stock dividends paid in kind (Series A and B)				(5,412,281)
Ending Balance, Amount at Dec. 31, 2013	$ 0	$ 2,669,465	38,770	(50,596,088)	(47,887,853)
Ending Balance, Shares at Dec. 31, 2013	0	41,074,950
Sales of shares of preferred stock, Amount	$ 9,958,217
Sales of shares of preferred stock, Shares	507,739
Restricted stock awards, Amount		$ 3,272,638
Restricted stock awards, Shares		19,440
Restricted stock unit awards, Amount		$ 869,231
Restricted stock unit awards, Shares		273,907
Convert preferred stock to shares of common stock, Amount		$ 107,552,938
Convert preferred stock to shares of common stock, Shares		22,883,487
Pyramid Oil Company shares outstanding last day of trading, Amount		$ 22,504,000
Pyramid Oil Company shares outstanding last day of trading, Shares		4,788,085
Fair value of Pyramid Oil Company stock options		$ 100,500
Stock awards to employees, directors and consultants of Pyramid Oil Company vested upon the change in control and issued, Amount		$ 501,000
Stock awards to employees, directors and consultants of Pyramid Oil Company vested upon the change in control and issued, Shares		100,000
Comprehensive income (loss) from commodity derivative instruments, net of income taxes			31
Net loss attributable to Yuma Energy, Inc.				(20,225,150)	(20,225,150)
Series A perpetual preferred stock cash dividends				(224,098)
Preferred stock accretion (Series A and B)				(786,536)
Preferred stock cash dividends (Series A and B)				(445,152)
Preferred stock dividends paid in kind (Series A and B)				(4,133,380)
Ending Balance, Amount at Dec. 31, 2014	$ 9,958,217	$ 137,469,772	38,801	(76,410,404)	71,056,386
Ending Balance, Shares at Dec. 31, 2014	507,739	69,139,869
Sales of shares of preferred stock, Amount	$ 870,386
Sales of shares of preferred stock, Shares	46,857
Sales of shares of common stock, Amount		$ 1,363,160
Sales of shares of common stock, Shares		1,347,458
Restricted stock awards, Amount		$ 3,171,477
Restricted stock awards, Shares		1,676,113
Buy back of shares from vested stock awards, Amount		$ (300,732)
Buy back of shares from vested stock awards, Shares		(328,823)
Stock appreciation rights issued, not vested, Amount		$ 155,269
Comprehensive income (loss) from commodity derivative instruments, net of income taxes			(38,801)
Net loss attributable to Yuma Energy, Inc.				(11,005,038)	(11,005,038)
Series A perpetual preferred stock cash dividends				(1,047,191)
Preferred stock accretion (Series A and B)				0
Preferred stock cash dividends (Series A and B)				0
Preferred stock dividends paid in kind (Series A and B)				0
Ending Balance, Amount at Dec. 31, 2015	$ 10,828,603	$ 141,858,946	$ 0	$ (88,462,633)	$ 64,224,916
Ending Balance, Shares at Dec. 31, 2015	554,596	71,834,617

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Reconciliation of net loss to net cash provided by (used in) operating activities
Net loss	$ (11,005,038)	$ (20,225,150)	$ (33,050,103)
Goodwill write-off	$ 5,349,988
Increase in fair value of preferred stock derivative liability		$ 15,676,842	$ 26,258,559
Depreciation, depletion and amortization of property and equipment	$ 13,651,207	19,664,991	12,077,368
Accretion of asset retirement obligation	604,538	604,511	668,497
Stock-based compensation net of capitalized cost	2,289,311	3,388,321	452,058
Amortization of other assets and liabilities	286,010	188,669	166,608
Deferred tax expense (benefit)	(7,951,850)	(2,553,854)	3,080,272
Bad debt expense	$ 839,171	97,068	$ 193,601
Write off deferred offering costs		$ 1,257,160
Write off credit financing costs			$ 313,652
Amortization of benefit from commodity derivatives (sold) and purchased, net		$ (93,750)	(72,600)
Unrealized (gains) losses on commodity derivatives	$ 949,967	(4,724,985)	231,886
Other	(342,835)	5,448	(21,328)
Changes in current operating assets and liabilities:
Accounts receivable	6,877,906	976,093	(5,589,741)
Other current assets	77,711	(267,386)	869,550
Accounts payable	(13,688,145)	10,690,790	9,115,792
Other current liabilities	$ 691,915	$ (218,468)	148,834
Other non-current liability			69,998
NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES	$ (1,370,144)	$ 24,466,300	14,912,903
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures on property and equipment	(13,540,582)	(25,526,887)	(28,152,714)
Proceeds from sale of property	$ 58,557	667,267	$ 902,166
Cash received from merger		4,550,082
Decrease in short-term investments	$ 1,170,868	2,125,541
Decrease (increase) in noncurrent receivable from affiliate		95,634	$ (2,493)
NET CASH USED IN INVESTING ACTIVITIES	$ (12,311,157)	(18,088,363)	(27,253,041)
CASH FLOWS FROM FINANCING ACTIVITIES:
Change in borrowing on line of credit	6,900,000	(8,315,000)	13,340,000
Proceeds from insurance note	813,562	901,257	872,754
Payments on insurance note	(832,770)	(796,441)	(878,328)
Line of credit financing costs	(250,141)	$ (92,909)	$ (681,739)
Net proceeds from sale of common stock	1,363,160
Net proceeds from sales of perpetual preferred stock	870,386	$ 9,958,217
Deferred offering costs	(38,104)		$ (1,257,160)
Cash dividends to preferred stockholders	(1,047,191)	$ (669,250)	$ (145,900)
Common stock purchased from employees	(300,732)
NET CASH PROVIDED BY FINANCING ACTIVITIES	7,478,170	$ 985,874	$ 11,249,627
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	(6,203,131)	7,363,811	(1,090,511)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD	11,558,322	4,194,511	5,285,022
CASH AND CASH EQUIVALENTS AT END OF PERIOD	5,355,191	11,558,322	4,194,511
Supplemental disclosure of cash flow information:
Interest payments (net of interest capitalized)	131,521	175,009	22,210
Interest capitalized	$ 983,472	1,059,350	1,031,816
Supplemental disclosure of significant non-cash activity:
Preferred dividends paid in kind (Series A and Series B)		4,133,380	5,412,281
Change in capital expenditures financed by accounts payable	$ 3,382,555	$ 1,310,037	$ 1,904,581

SUMMARY OF SIGNIFICANT ACCOUNTI

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	12 Months Ended
	Dec. 31, 2015
Accounting Policies [Abstract]
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	Yuma Energy, Inc., a California corporation (“YEI” and collectively with its subsidiaries, the “Company”) (formerly Pyramid Oil Company (“Pyramid”)), is an independent Houston-based exploration and production company focused on the acquisition, development and exploration for conventional and unconventional oil and natural gas resources, primarily in the U.S. Gulf Coast and California. YEI has employed a 3-D seismic-based strategy to build a multi-year inventory of development and exploration prospects. YEI’s current operations are focused on onshore assets located in central and southern Louisiana, where the Company targets the Austin Chalk, Tuscaloosa, Wilcox, Frio, Marg Tex 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. Basis of Presentation The accompanying financial statements include the accounts of YEI on a consolidated basis. All significant intercompany accounts and transactions between YEI, YCI, Exploration, Petroleum, TSM and POL have been eliminated in the consolidation. All events described or referred to as prior to September 10, 2014 relate to Yuma Co. as the accounting acquirer. All references to “Pyramid” refer to the Company prior to the closing of the merger on September 10, 2014. 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 financial statements were prepared on a going concern basis. The Company has been operating in a weak commodity price environment and was not in compliance with the trailing four quarter funded debt to EBITDA financial ratio covenant under its credit facility at September 30, 2015 and December 31, 2015 as well as the EBITDA to interest expense ratio at December 31, 2015. On December 30, 2015, the Company entered into a waiver with the lenders under its credit facility. On February 10, 2016, the Company entered into an Agreement and Plan of Merger and Reorganization with Davis Petroleum Acquisition Corp. (“Davis”) for an all-stock transaction. See Note 24 – Subsequent Events. 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 assets; obligations related to employee benefits; 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. 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 8 – Fair Value Measurements). The carrying amount of cash and cash equivalents, accounts receivable and accounts payable reported on the balance sheet approximates fair value. The fair value of debt is the estimated amount the Company would have to pay to repurchase its debt. Nonfinancial assets and liabilities initially measured at fair value include certain assets acquired in a business combination, goodwill, asset retirement obligations and exit or disposal costs. Level 3 Valuation Techniques 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. Short-term Investments Short-term investments consisted of commercial bank certificates of deposit which matured in May 2015 and were valued at cost. Trade Receivables Accounts receivable are stated net of allowance for doubtful accounts of $532,719 and $138,960 at December 31, 2015 and 2014, respectively. Management evaluates accounts receivable quarterly on an individual account basis, making individual assessments of collectability, and reserves those amounts it deems potentially uncollectible. Inventories Inventories, consisting principally of oilfield equipment, are carried at the lower of cost or market. The Company will often have tangible materials purchased for a well carried for the joint account (oil and gas property full cost pool on the balance sheet) pending sale or disposition. Derivative Instruments All derivative instruments (including certain derivative instruments embedded in other contracts) are recorded in the Company’s Consolidated Balance Sheets as either an asset or liability and measured at fair value. Changes in the derivative instrument’s fair value are recognized in earnings. Under cash flow hedge accounting, unrealized gains and losses were reflected in stockholders’ equity as accumulated other comprehensive income (“AOCI”) to the extent they were effective until the forecasted transaction occurred. Absent cash-flow accounting, all hedges are treated as non-qualifying derivative instruments and mark-to-market adjustments are in the Consolidated Statements of Operations. The Company discontinued cash flow hedge accounting effective January 1, 2013. The result of this change in policy was that the amount carried in AOCI at December 31, 2012 was amortized to oil and gas revenues during the month the hedges settled. Subsequent to December 31, 2012, all hedges are treated as non-qualifying derivative instruments and all new mark-to-market adjustments are in “Sales of natural gas and crude oil” in the Consolidated Statements of Operations. The final contracts that were included within AOCI expired at the end of 2015; therefore, the AOCI balance was zero at December 31, 2015. Oil and Natural Gas Properties Investments in oil and natural gas properties are accounted for using the full cost method of accounting. Under this method, all costs directly related to the acquisition, exploration, exploitation and development of oil and natural gas properties 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 Impairments 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. Management reviews the costs of these properties periodically for impairment, with the impairment provision included in the cost of oil and natural gas properties subject to amortization. Factors considered by management in impairment assessments include drilling results by the Company and other operators, the terms of oil and gas leases not held for production, and available funds for exploration and development. The table below shows the cost of unproved properties, along with well and development costs in progress not subject to amortization at December 31, 2015, and the year in which those costs were incurred. Year of acquisition 2015 2014 2013 Prior Total Leasehold acquisition cost $ (9,039,268 ) $ 154,194 $ 1,704,190 $ 19,247,036 $ 12,066,152 Exploration and development cost (1,739,341 ) 891,610 1,059,262 172,159 383,690 Capitalized interest (639,726 ) 609,970 829,456 1,027,969 1,827,669 Total $ (11,418,335 ) $ 1,655,774 $ 3,592,908 $ 20,447,164 $ 14,277,511 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. In doing this, the Company typically earns a profit over its actual costs in seismic, land, brokerage, brochuring and marketing. It typically markets interests in the project on a “third for a quarter” basis, whereby the participant pays a percentage of the cost to casing point or through prospect payout and then has its participation interest reduced by twenty-five percent (25%) with the Company earning the difference. This difference is referred to as the “carried interest.” The Company assembles 3-D seismic survey projects and markets participating interests in the projects. The Company typically recovers all of its costs plus allocated overhead, and receives a quarterly general and administrative (“G&A”) expense reimbursement paid by the various participants in the project during the 3-D seismic acquisition phase and the 3-D seismic interpretation phase. The proceeds from the sale of the 3-D seismic survey along with the quarterly G&A reimbursements are included in the full cost pool caption “Not subject to amortization.” In addition, the participants in the 3-D seismic survey typically carry the Company for a percentage of the costs associated with the 3-D survey acquisition, ranging from 25 to 35 percent. The Company received G&A expense reimbursements of $-0-, $-0- and $42,329 in fiscal years 2015, 2014 and 2013, respectively. Other Property and Equipment Other property and equipment is generally recorded at cost, with the exception of the Pyramid property that was acquired in the merger, which was marked to fair value as of the closing date of the merger. 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. 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. Office business machines and furniture and fixtures are depreciated using the modified accelerated cost recovery system (“MACRS”) for financial reporting purposes. MACRS depreciation methods approximate depreciation expense computed under GAAP using the double declining balance method. Depreciation of drilling and operating equipment, automotive, and buildings is computed using the straight-line method over the shorter of the estimated useful lives or the applicable lease terms. Leasehold improvements for the corporate office space in Houston, Texas are depreciated by the straight line method over the term of the lease. Estimated useful December 31, life in years 2015 2014 Land n/a $ 2,469,000 $ 2,469,000 Office business machines 3 - 5 1,381,968 1,361,149 Drilling and operating equipment 14 982,010 982,010 Furniture and fixtures 7 412,215 412,215 Automotive 5 351,707 351,707 Office leasehold improvements 5 332,607 332,607 Buildings and improvements 3 - 25 326,000 326,000 Total other property and equipment 6,255,507 6,234,688 Less: Accumulated depreciation and leasehold improvement amortization (2,174,316 ) (1,909,352 ) Net book value $ 4,081,191 $ 4,325,336 Depreciation and leasehold improvement amortization expense totaled $275,756, $174,338 and $149,496 for the years ended December 31, 2015, 2014 and 2013, respectively. Goodwill Goodwill represents the excess of the purchase price over the estimated fair value of the assets acquired net of the fair value of liabilities assumed in an acquisition. The provisions of Accounting Standards Codification (“ASC”) 350, Intangibles – Goodwill and Other (“ASC 350”) require that intangible assets with indefinite lives, including goodwill, be evaluated on an annual basis for impairment, or more frequently if events occur or circumstances change that could potentially result in impairment. The goodwill impairment test requires the allocation of goodwill and all other assets and liabilities to reporting units. However, the Company has only one reporting unit. To assess impairment, the Company has the option to qualitatively assess if it is more likely than not that the fair value of the reporting unit is less than the book value. Absent a qualitative assessment, or, through the qualitative assessment, if the Company determines it is more likely than not that the fair value of the reporting unit is less than the book value, a quantitative assessment is prepared to calculate the fair market value of the reporting unit. If it is determined that the fair value of the reporting unit is less than the book value, the recorded goodwill is impaired to its implied fair value with a charge to operating expense. The Company’s goodwill as of December 31, 2014 related to its acquisition of Pyramid. The drop in crude oil prices and the resulting decline in the Company’s common share price caused the Company to test goodwill for impairment at June 30, 2015. Goodwill was determined to be fully impaired and as a result, the balance of $5,349,988 was written off. Refer to Note 14 – Merger with Pyramid Oil Company and Goodwill for more details. Accounts Payable Accounts payable consist principally of trade payables and costs associated with oil and natural gas exploration. 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 deliveries of 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”). TSM recognizes revenue from sales of natural gas primarily to other marketing companies and industrials in the period in which the natural gas is delivered and billed to the customer. 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. 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 (see Note 16 – Income Taxes). Other Taxes Taxes incurred, other than income taxes, are as follows: December 31, 2015 2014 2013 Production and severance tax $ 1,678,825 $ 2,693,396 $ 2,403,263 Ad valorem tax 1,103,913 1,046,134 732,302 Sales tax 18,534 62,864 180,498 State franchise taxes 68,248 40,740 41,072 Total $ 2,869,520 $ 3,843,134 $ 3,357,135 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. Sales taxes are collected from customers on sales of natural gas by TSM, and remitted to the appropriate state agency. Exploration accrues sales tax on applicable purchases of materials, and remits funds directly to the taxing jurisdictions. Financial Instruments The Company’s financial instruments consist of cash, receivables, payables, long-term debt, oil and natural gas derivatives, and (prior to the merger as described in Note 14 – Merger with Pyramid Oil Company and Goodwill) Series A and Series B Preferred Stock. The carrying amount of cash, receivables and payables approximates fair value because of the short-term nature of these items. Accumulated Other Comprehensive Income AOCI includes changes in equity that are excluded from the Consolidated Statements of Operations and recorded directly into a separate section of equity on the Consolidated Balance Sheets. The Company’s AOCI shown on the Consolidated Balance Sheets and the Consolidated Statements of Changes in Equity consists of unrealized income and losses on cash flow hedges; however, the Company discontinued hedge accounting effective January 1, 2013. The final contracts that were included within AOCI expired at the end of 2015; therefore, the AOCI balance was zero at December 31, 2015. 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 2011 Stock Option Plan on June 21, 2011, and the 2014 Long-Term Incentive Plan effective September 10, 2014 (see Note 15 – Stockholders’ Equity). The Company adopted an Annual Incentive Plan for fiscal years 2015, 2014 and 2013 (see Note 18 – Employee Benefit Plans). The Company accounts for stock-based compensation at fair value. The Company grants equity-classified awards including stock options and 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 market price of common stock. 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 11 – Stock-Based Compensation. General and Administrative Expenses - Other G&A expenses are reported net of amounts capitalized pursuant to the full cost method of accounting. Re-engineering and Workovers One of the Company’s core business strategies is to perform a comprehensive field re-engineering and design to increase and maintain production, lower per-unit operating expenses, and improve field economics. Re-engineering projects are undertaken with the intent of lowering per-unit operating expenses and/or reducing field down-time. In addition, the Company seeks to implement more efficient production practices in order to increase production and/or arrest natural field production declines. These practices are often deployed in fields in connection with or in anticipation of further field development activities such as installation of secondary recovery operations or additional drilling. Workovers included within this category relate to significant non-recurring operations. Other Noncurrent Assets Noncurrent assets at December 31, 2015 are comprised of deferred costs related to future potential equity raises. If these potential equity raises come to fruition, then costs are netted from the new equity issuance; if not, then those costs are charged to G&A. In 2014, noncurrent assets were comprised of debt financing costs, which were moved to current in 2015. 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 15 – Stockholders’ Equity. Changes in Accounting Principles Not Yet Adopted In May 2014 and August 2015, the Financial Accounting Standards Board (“FASB”) issued an update that supersedes the existing revenue recognition requirements. This standard includes a five-step revenue recognition model to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for those goods or services. Among other things, the standard requires enhanced disclosures about revenue, provides guidance for transactions that were not previously addressed comprehensively and improves guidance for multiple-element arrangements. This standard is effective for the Company in the first quarter of 2018 and should be applied retrospectively to each prior reporting period presented or with the cumulative effect of initially applying the update recognized at the date of initial application. Early adoption is permitted. The Company is evaluating the provisions of this accounting standards update and assessing the impact, if any, it may have on its consolidated results of operations, financial position or cash flows. In July 2015, the FASB issued an update that requires an entity to measure inventory at the lower of cost and net realizable value. This excludes inventory measured using LIFO or the retail inventory method. This standard is effective for the Company in the first quarter of 2017 and will be applied prospectively. Early adoption is permitted. The Company does not expect the adoption of this standard to have a significant impact on its consolidated results of operations, financial position or cash flows. In May 2015, the FASB issued an update that removes the requirement to categorize within the fair value hierarchy all investments for which fair value is measured using the net asset value per share practical expedient. The amendment also removes certain disclosure requirements regarding all investments that are eligible to be measured using the net asset value per share practical expedient and only requires certain disclosures on those investments for which an entity elects to use the net asset value per share expedient. This standard is effective for the Company in the first quarter of 2016 and will be applied on a retrospective basis. Early adoption is permitted. This standard only modifies disclosure requirements; as such, there will be no impact on the Company’s consolidated results of operations, financial position or cash flows. In April 2015, the FASB issued an update that requires debt issuance costs to be presented in the balance sheet as a direct reduction from the associated debt liability. This standard is effective for the Company in the first quarter of 2016 and early adoption is permitted. The Company is evaluating the provisions of this accounting standards update and assessing the impact, if any, it may have on its consolidated results of operations, financial position or cash flows. In February 2015, the FASB issued an amendment to the guidance for determining whether an entity is a variable interest entity (“VIE”). The standard does not add or remove any of the five characteristics that determine if an entity is a VIE. However, it does change the manner in which a reporting entity assesses one of the characteristics. In particular, when decision-making over the entity’s most significant activities has been outsourced, the standard changes how a reporting entity assesses if the equity holders at risk lack decision making rights. This standard is effective for the Company for annual periods beginning after December 15, 2015 and early adoption is permitted, including in interim periods. The Company does not expect the adoption of this standard to have a significant impact on its consolidated results of operations, financial position or cash flows. Recently adopted In November 2015, the FASB issued an update that requires an entity to classify deferred income tax liabilities and assets as noncurrent in a classified statement of financial position. The amendments are effective for the Company in the first quarter of 2017 and early adoption is permitted. The Company elected to early adopt these amendments in the fourth quarter of 2015 on a prospective basis. Adoption of this standard did not have a significant impact on the Company’s consolidated results of operations, financial position or cash flows. In August 2014, the FASB issued an update that requires management to assess an entity’s ability to continue as a going concern by incorporating and expanding upon certain principles that are currently in U.S. auditing standards. This standard is effective for the Company in the first quarter of 2017 and early adoption is permitted. The Company elected to early adopt and has provided disclosures in conformity with this new standard. In April 2014, the FASB issued an amendment to accounting standards that changes the criteria for reporting discontinued operations while enhancing related disclosures. Under the amendment, only disposals representing a strategic shift in operations should be presented as discontinued operations. Those strategic shifts should have a major effect on the organization’s operations and financial results. Expanded disclosures about the assets, liabilities, income and expenses of discontinued operations are required. In addition, disclosure of the pre-tax income attributable to a disposal of a significant part of an organization that does not qualify for discontinued operations reporting will be made in order to provide users with information about the ongoing trends in an organization’s results from continuing operations. The amendments were effective for the Company in the first quarter of 2015. Adoption of this standard did not have a significant impact on the Company’s consolidated results of operations, financial position or cash flows.

ORGANIZATION AND CONSOLIDATION

ORGANIZATION AND CONSOLIDATION	12 Months Ended
	Dec. 31, 2015
Organization, Consolidation and Presentation of Financial Statements [Abstract]
ORGANIZATION AND CONSOLIDATION	On September 10, 2014, a wholly owned subsidiary of the Company merged with and into Yuma Energy, Inc., a Delaware corporation (“Yuma Co.”), in exchange for 66,336,701 shares of the Company’s common stock, and the Company subsequently changed its name from “Pyramid Oil Company” to “Yuma Energy, Inc.” which the Company refers to as the “merger”. As a result of the merger, the former Yuma Co. stockholders held approximately 93%, of the then-outstanding common stock of the Company, and thus acquired voting control. Although Pyramid was the legal acquirer, for financial reporting purposes the merger was accounted for as a reverse acquisition of Pyramid by Yuma Co. See Note 14 – Merger with Pyramid Oil Company and Goodwill for additional information. Simultaneously with the closing of the merger, Yuma Co. changed its name to “The Yuma Companies, Inc.” In addition, a subsidiary of the Company, Pyramid Oil LLC, a California limited liability company, was formed to hold Pyramid’s oil and natural gas properties. The Consolidation YEI was incorporated on October 9, 1909 and has six 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 10/30/96 Yuma Exploration and Production Company, Inc. “Exploration” Delaware 01/16/92 Yuma Petroleum Company “Petroleum” Delaware 12/19/91 Texas Southeastern Gas Marketing Company “TSM” Texas 09/12/96 Pyramid Oil LLC “POL” California 08/08/14 Pyramid Delaware Merger Subsidiary, Inc. “PDMS” Delaware 02/04/14 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 identifies and captures economic deposits of hydrocarbons by using: (i) 3-D seismic imaging and other advanced technologies, with an emphasis on acquiring proprietary 3-D seismic to systematically explore, exploit and develop onshore and offshore crude oil and natural gas provinces; (ii) unconventional oil resource plays; and (iii) high impact deep structural prospects located beneath known producing trends. Historically, Exploration has sold working interests in prospects to industry partners on traditional terms. Exploration’s operations are primarily conducted in the Gulf Coast region. Petroleum became relatively inactive during 1998 due to the transfer of substantially all exploration and production activities to Exploration. TSM is primarily engaged in the marketing of natural gas in Louisiana. TSM has elected to discontinue operations in 2016 (see Note 24 – Subsequent Events). POL is primarily engaged in holding assets located in the State of California. PDMS was inactive during 2015.

LIQUIDITY CONSIDERATIONS AND GO

LIQUIDITY CONSIDERATIONS AND GOING CONCERN	12 Months Ended
	Dec. 31, 2015
Organization, Consolidation and Presentation of Financial Statements [Abstract]
LIQUIDITY CONSIDERATIONS AND GOING CONCERN	The Company has borrowings which require, among other things, compliance with certain financial ratios. Due to operating losses the Company has sustained during recent quarters as a result of the prolonged weak commodity price environment and other factors, the Company was not in compliance with the trailing four quarter funded debt to EBITDA financial ratio covenant under its credit facility at September 30, 2015 and at December 31, 2015 as well as its EBITDA to interest expense ratio as of December 31, 2015. On December 30, 2015, the Company entered into the Waiver, Borrowing Base Redetermination and Ninth Amendment to the credit agreement which provided for a $29.8 million conforming borrowing base, which will be automatically reduced to $20.0 million on May 31, 2016 unless otherwise reduced by or adjusted to a different number by the lenders under the credit agreement, and waived the compliance with the trailing four quarter funded debt to EBITDA and EBITDA to interest expense financial ratio covenants or any other events of default under the credit facility for the quarters ended September 30, 2015 and December 31, 2015. As of December 31, 2015, the Company had a working capital deficit of $27.2 million inclusive of the Company's outstanding debt under its credit facility, which was fully drawn with no additional borrowing capacity available. A breach of any of the terms and conditions of the credit agreement or a breach of the financial covenants under the Company’s credit facility could result in acceleration of the Company’s indebtedness, in which case the debt would become immediately due and payable. Given that the Company anticipates being in violation of the funded debt to EBITDA and EBITDA to interest expense covenants as of March 31, 2016, the Company has classified its bank debt as a current liability in its financial statements. During 2015, the Company initiated several strategic alternatives to remedy its debt covenant compliance issues and provide working capital to develop the Company’s existing assets. On February 10, 2016, the Company entered into an Agreement and Plan of Merger and Reorganization with Davis Petroleum Acquisition Corp. (“Davis”) for an all-stock transaction. Upon completion of the transaction, which is subject to the approval of the stockholders of both companies, Davis will become a wholly owned subsidiary of Yuma. Subject to bank approval, it is anticipated that the Company will enter into another credit agreement amendment that will take into account the contemplated merger with Davis (see Note 24 – Subsequent Events). However, the Company's management can provide no assurance that the merger with Davis and the amendment to the credit agreement will actually occur. The significant risks and uncertainties described above raise substantial doubt about the Company's ability to continue as a going concern. The consolidated financial statements have been prepared on a going concern basis of accounting, which contemplates continuity of operations, realization of assets, and satisfaction of liabilities and commitments in the normal course of business. The consolidated financial statements do not include any adjustments that might result from the outcome of the going concern uncertainty.

ADDISON ACQUISITION

ADDISON ACQUISITION	12 Months Ended
	Dec. 31, 2015
Business Combinations [Abstract]
ADDISON ACQUISITION	On April 5, 2013, the Company acquired from Addison Oil, L.L.C. (“Addison”) approximately 51,460 net acres held by production in the Austin Chalk adjacent to 25,926 net acres held by the Company at that time. This acquisition increased the Company’s acreage holdings in the Austin Chalk to over 77,000 net acres at the time of closing. The purchase price was $7.5 million, with an effective date of January 1, 2013. The Company granted a two percent overriding royalty to the sellers, and sellers have a right to participate in new wells or new side tracks for a twenty-five percent (25%) working interest. This acquisition complemented the Company’s existing acreage position and substantially increased the Company’s number of proved undeveloped drilling locations and proved reserve values. Associated with this acquisition, the Company recorded $6,043,412 for the associated future asset retirement obligations and $1,440,702 in suspended royalty and revenue obligations, net of related receivables at the time of the merger.

ASSET RETIREMENT OBLIGATIONS

ASSET RETIREMENT OBLIGATIONS	12 Months Ended
	Dec. 31, 2015
Asset Retirement Obligation Disclosure [Abstract]
ASSET RETIREMENT OBLIGATIONS	The Company records the cost of obligations associated with the retirement of tangible long-lived assets at fair value when the asset is acquired. The asset retirement obligations (“ARO’s”) are recorded as liabilities and the associated costs are capitalized as part of the related long-lived assets and then depreciated over the remaining useful lives. Changes in the liabilities resulting from the passage of time are recognized as operating (accretion) expenses and are allocated using the interest method. For the Company, ARO’s relate to the abandonment of oil and gas producing facilities. Since the Company uses the full cost method, settlement recognition is impacted. If a liability is settled for an amount other than the recorded amount, an adjustment is made to the full cost pool, with no gain or loss recognized, unless the adjustment would significantly alter the relationship between capitalized costs and proved reserves. In addition, the Company carries ARO assets on the balance sheet as part of its full cost pool, and includes these ARO assets in its amortization base for the purposes of calculating depreciation, depletion and amortization expense. The net decrease of $3,697,272 to ARO during 2015 is due primarily to revised estimates of P&A cost for Masters Creek and Main Pass properties. P&A cost were revised to reflect current market conditions and efficiencies gained by developing P&A programs for multiple wells. Asset Retirement Obligations December 31, 2015 2014 Beginning of year balance $ 12,487,770 $ 10,697,679 Pyramid liabilities assumed in the merger - 943,951 Liabilities incurred during year 24,588 416,162 Liabilities settled during year (35,455 ) - Accretion expense 604,538 604,511 Revisions in estimated cash flows (4,290,943 ) (174,533 ) End of year balance $ 8,790,498 $ 12,487,770

RECEIVABLES AND PAYABLES WITH A

RECEIVABLES AND PAYABLES WITH AFFILIATES, CHIEF EXECUTIVE OFFICER AND EMPLOYEES	12 Months Ended
	Dec. 31, 2015
Receivables And Payables With Affiliates Chief Executive Officer And Employees
RECEIVABLES AND PAYABLES WITH AFFILIATES, CHIEF EXECUTIVE OFFICER AND EMPLOYEES	The following table provides information with respect to related party transactions with affiliates, the 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 7 – Related Party Transactions). December 31, 2015 2014 Receivables from affiliates, CEO and employees: Current: Yuma CEO $ 63,329 $ 174,720 Employees 12,075 141,357 Total $ 75,404 $ 316,077

RELATED PARTY TRANSACTIONS

RELATED PARTY TRANSACTIONS	12 Months Ended
	Dec. 31, 2015
Related Party Transactions [Abstract]
RELATED PARTY TRANSACTIONS	Chief Executive Officer Effective August 15, 2011, the Company entered into a Working Interest Incentive Plan (“WIIP”) with the Company’s CEO, Sam L. Banks. 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 purchase price for any working interests acquired from the Company under the plan was no better than the terms agreed to by unaffiliated third parties. The Board of Directors terminated the WIIP effective September 21, 2015. Working interests acquired during fiscal years 2014 and 2013 under the WIIP are listed below (no working interests were acquired under the WIIP during fiscal year 2015): Working Amount Year Well, prospect or project interest paid 2014 Anaconda Prospect (Talbot 23-1) 1.95000 % $ 16,900 2014 Gardner Island Well & 1.43600 % Main Pass 4 Facility 1.85500 % $ 78,988 2014 Austin Chalk (Additional W.I.) 1.00000 % $ 16,000 2013 Bell City East Prospect .71063 % $ 5,330 2013 Austin Chalk 1.00000 % $ 9,412 2013 Addison Acquisition 2.00000 % $ 150,000 In 2006, the Company entered into participation agreements with several unrelated industry participants under which it would receive a 20% back-in interest after payout to the participants and the CEO would receive a 5% back-in interest. The agreements were renegotiated in 2010 reducing the total back-in interest by 40% with the Company receiving 12.5% and the CEO receiving 2.5%. The project, named La Posada, achieved multiple discrete payouts during 2013 based on differing participant cost basis and the participants assigned the agreed working interests directly to each of the Company and the CEO at time of payout.

FAIR VALUE MEASUREMENTS

FAIR VALUE MEASUREMENTS	12 Months Ended
	Dec. 31, 2015
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 1 – 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, 2015 Significant Quoted prices other Significant in active observable unobservable markets inputs inputs (Level 1) (Level 2) (Level 3) Total Assets: Commodity derivatives – oil $ - $ 3,442,693 $ - $ 3,442,693 Commodity derivatives – gas - 285,895 - 285,895 Total assets $ - $ 3,728,588 $ - $ 3,728,588 Fair value measurements at December 31, 2014 Significant Quoted prices other Significant in active observable unobservable markets inputs inputs (Level 1) (Level 2) (Level 3) Total Assets: Commodity derivatives – oil $ - $ 2,858,387 $ - $ 2,858,387 Commodity derivatives – gas - 1,883,259 - 1,883,259 Total assets $ - $ 4,741,646 $ - $ 4,741,646 Derivative instruments listed above include swaps, reverse swaps, three-way collars and put spreads. For additional information on the Company’s derivative instruments and derivative liabilities, see Note 9 – Commodity Derivative Instruments. On September 10, 2014, the value of the Series A and Series B Preferred Stock and associated derivative was marked to market. The preferred stock was converted to common stock as further described in Note 14 – Merger with Pyramid Oil Company and Goodwill. With the conversion of the shares of Series A and Series B Preferred Stock to common stock, the value of the associated derivative liability was marked to market, then transferred to common stock equity. Debt Asset Retirement Obligations

COMMODITY DERIVATIVE INSTRUMENT

COMMODITY DERIVATIVE INSTRUMENTS	12 Months Ended
	Dec. 31, 2015
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. Net derivative losses attributable to derivatives previously subject to hedge accounting resided in AOCI and were reclassified to earnings as the transactions to which the derivatives related were recognized in earnings. The remaining contracts that were subject to hedge accounting expired during 2015 and AOCI is now zero. The Company elected to discontinue hedge accounting for all commodity derivative instruments beginning with the 2013 financial year. The balance in other comprehensive income (“OCI”) at year-end 2012 remained in AOCI until the original hedged forecasted transactions occurred. The last of these contracts expired in December 2015. No mark-to-market adjustments for commodity derivative contracts are made to AOCI, but instead are recognized in earnings. As a result of discontinuing the application of hedge accounting, the Company’s earnings are potentially more volatile. See Note 8 – Fair Value Measurements for a discussion of methods and assumptions used to estimate the fair values of the Company’s commodity derivative instruments. Counterparty Credit Risk On February 18, 2015, the Company settled all of its natural gas and crude oil options, realizing $4.03 million. The Company retained its existing natural gas swap positions. Concurrent with the settlement of the Company’s option positions and during the following day, the Company entered into new swap transactions for crude oil and natural gas for the balance of 2015 and all of 2016. In addition, the Company entered into three-way collars for 2017 for both natural gas and crude oil. In conjunction with certain derivative hedging activity, the Company deferred the payment of $153,389 put premiums which was recorded in both current other deferred charges and current other accrued liabilities at year-end 2014 and was for production months January 2015 through December 2015. The put premium liabilities became payable monthly as the hedge production month became the prompt production month. The Company amortized the deferred put premium liabilities in January and February 2015; however, the liability for the remainder of the year was settled as part of the $4.03 million settlement. Commodity derivative instruments open as of December 31, 2015 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”), except for the oil swaps noted below that are based on Argus Light Louisiana Sweet (“LLS”). 2016 2017 Settlement Settlement NATURAL GAS (MMBtu): Swaps Volume 298,957 - Price (NYMEX) $ 3.28 - 3-way collars Volume - 67,361 Ceiling sold price (call) (NYMEX) - $ 4.03 Floor purchased price (put) (NYMEX) - $ 3.50 Floor sold price (short put) (NYMEX) - $ 3.00 CRUDE OIL (Bbls): Put spread Volume 138,286 - Floor purchased price (put) (LLS) $ 62.27 - Floor sold price (short put) (LLS) $ 40.00 - 3-way collars Volume - 113,029 Ceiling sold price (call) (WTI) - $ 77.00 Floor purchased price (put) (WTI) - $ 60.00 Floor sold price (short put) (WTI) - $ 45.00 Derivatives for each commodity are netted on the Consolidated Balance Sheets as they are all contracts with the same counterparty. 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, 2015 2014 Asset commodity derivatives: Current assets $ 3,069,115 $ 6,413,935 Noncurrent assets 1,841,120 3,163,891 4,910,235 9,577,826 Liability commodity derivatives: Current liabilities (411,068 ) (3,075,398 ) Noncurrent liabilities (770,579 ) (1,760,782 ) (1,181,647 ) (4,836,180 ) Total commodity derivative instruments $ 3,728,588 $ 4,741,646 Sales of natural gas and crude oil on the Consolidated Statements of Operations are comprised of the following: Years Ended December 31, 2015 2014 2013 Sales of natural gas and crude oil $ 18,680,584 $ 38,659,392 $ 28,235,413 Gains (losses) realized from sale of commodity derivatives 4,030,000 - - Other gains (losses) realized on commodity derivatives 1,958,793 (1,420,217 ) (524 ) Unrealized gains (losses) on commodity derivatives (949,967 ) 4,724,985 (231,886 ) Amortized gains from benefit of sold qualified gas options - 93,750 72,600 Total revenue from natural gas and crude oil $ 23,719,410 $ 42,057,910 $ 28,075,603 A reconciliation of the components of accumulated other comprehensive income (loss) in the Consolidated Statements of Changes in Equity is presented below: Years Ended December 31, 2015 2014 2013 Before tax After tax Before tax After tax Before tax After tax Balance, beginning of period $ 63,091 $ 38,801 $ 63,041 $ 38,770 $ 437,140 $ 268,841 Sale of unexpired contracts previously subject to hedge accounting rules (119,917 ) (73,749 ) - - - - Other reclassifications due to expired contracts previously subject to hedge accounting rules 56,826 34,948 50 31 (374,099 ) (230,071 ) Balance, end of period $ - $ - $ 63,091 $ 38,801 $ 63,041 $ 38,770

PREFERRED STOCK

PREFERRED STOCK	12 Months Ended
	Dec. 31, 2015
PreferredStockAbstract
PREFERRED STOCK	9.25% Series A Cumulative Redeemable Preferred Stock - Dividends on the Series A Preferred Stock are declared monthly based on the assessment of the Company’s financial position by the Board of Directors. Due to the current depressed commodity price environment as well as other factors which have adversely affected the Company’s cash flows and liquidity, the monthly dividends on the Series A Preferred Stock were suspended beginning with the month ended November 30, 2015 until such time as the Company and the Board of Directors have deemed that the Company has sufficient liquidity to restore their payment. Pursuant to the merger agreement with Davis, the Company has agreed as part of the reincorporation from California to Delaware, subject to approval of the holders of Series A Preferred Stock, to convert each share of the Company’s existing Series A Preferred Stock into 35 shares of common stock prior to giving effect for the reverse split (3.5 shares post reverse split). See Note 24 – Subsequent Events for a discussion of the merger agreement with Davis. Series A and Series B Preferred Stock of Yuma Co. – The Series A and Series B Preferred Stock is presented on the Company’s balance sheet between Other Noncurrent Liabilities and Equity (the mezzanine section) since it has characteristics of both debt and equity. The carrying amount on the Company’s balance sheets represents the net proceeds increased by accretion of stock issue costs less the value at time of origination of the embedded conversion feature. The accretion of issue costs increased the Preferred Stock by amortizing the costs to equity through the trigger date for the Company’s repurchase of such shares. On June 30, 2013, December 31, 2013, and June 30, 2014, Yuma Co. elected to pay the semi-annual dividends to the preferred stockholders in additional shares of preferred stock (in kind), with cash payments being made in lieu of any fractional shares. The following shares and cash payments were issued to the existing preferred stockholders as of the record dates: June 30, 2013 December 31, 2013 June 30, 2014 Additional Additional Additional preferred Cash preferred Cash preferred Cash shares payments shares payments shares payments Series A Preferred Stock 403 $ 35,150 630 $ 45,360 893 $ 45,280 Series B Preferred Stock 533 $ 24,700 533 $ 40,690 536 $ 53,680 On September 15, 2014, the Company made the final cash dividend payment to the holders of record of the Series A and Series B Preferred Stock. The amount of the preferred stock dividends paid was as follows: Series A Preferred Stock Dividends $ 214,903 Series B Preferred Stock Dividends 131,289 Total Dividends $ 346,192 The payment in kind to preferred stockholders was recorded at fair value using the valuation of the common stock performed by an outside consulting firm as further described in Note 8 – Fair Value Measurements, at the preferred conversion rate to common stock as of June 30, 2013 and December 31, 2013. Components of the total fair value of $4,133,380 for fiscal year 2014 and $5,412,281 for fiscal year 2013 for the preferred stock dividends consist of: December 31, 2014 December 31, 2013 Additional Additional preferred Dividends preferred Dividends shares in kind shares in kind Series A Preferred Stock 893 $ 3,299,603 1,033 $ 3,779,521 Series B Preferred Stock 536 $ 833,777 1,066 $ 1,632,760 Yuma Co. issued the above additional preferred shares to each class of preferred stock. The outstanding shares at December 31, 2014 and 2013 are as follows: Shares Shares Shares 2013 outstanding 2014 converted to outstanding Original stock December 31, stock common stock December 31, shares dividends 2013 dividends in 2014 2014 Series A Preferred Stock 14,605 1,033 15,638 893 (16,531 ) - Series B Preferred Stock 18,590 1,066 19,656 536 (20,192 ) - At the closing of the merger, the shares of Series A and Series B preferred stock were converted to common stock as reflected in the table below. Number Conversion Conversion of ratio to ratio to Number preferred Yuma Co. Company of shares common stock common stock shares Series A Preferred Stock 16,531 1.207101257 757.3374389993 15,112,295 Series B Preferred Stock 20,192 .508185000 757.3374389993 7,771,192

STOCK-BASED COMPENSATION

STOCK-BASED COMPENSATION	12 Months Ended
	Dec. 31, 2015
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
STOCK-BASED COMPENSATION	The Yuma Co. 2011 Stock Option Plan (the “Yuma Co. Plan”) was adopted on June 21, 2011. On September 10, 2014, the shareholders of Pyramid adopted the 2014 Long-Term Incentive Plan (the “2014 Plan”). Under these plans, the Board of Directors is authorized to grant stock options, stock awards (including restricted stock and restricted stock unit awards) and performance awards to officers, directors, employees and consultants. At December 31, 2015, 4,307,672 shares of the 8,900,000 shares of Yuma 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. 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, 2015 is presented below. Number of Weighted average unvested grant-date RSA shares fair value Unvested shares as of January 1, 2015 2,063,100 $3.40 per share Granted on March 12, 2015 73,194 $1.38 per share Granted on August 18, 2015 2,155,538 $0.61 per share Granted on September 30, 2015 75,000 $0.48 per share Granted on October 5, 2015 295,586 $0.50 per share Vested on January 25, 2015 (65,638 ) $3.14 per share Vested on April 1, 2015 (1,272,834 ) $3.16 per share Vested on May 1, 2015 (6,232 ) $2.39 per share Vested on May 20, 2015 (76,744 ) $3.96 per share Vested on July 14, 2015 (29,789 ) $3.89 per share Vested on October 15, 2015 (48,747 ) $2.74 per share Vested on November 1, 2015 (6,232 ) $2.39 per share Vested on November 30, 2015 (16,157 ) $3.88 per share Vested on December 31, 2015 (106,280 ) $3.88 per share Forfeited (690,392 ) $1.72 per share Unvested shares as of December 31, 2015 2,343,373 $0.98 per share The weighted average grant-date fair value per RSA share granted was $3.87 for 2014 and $3.22 for 2013. A summary of the status of the RSAs and changes for the year to date ended December 31, 2015 for former Yuma employees acting as consultants is presented below. Number of unvested Weighted average RSA shares fair value Unvested shares as of January 1, 2015 - Granted November 30, 2015 45,297 $0.19 per share Granted December 15, 2015 173,224 $0.19 per share Vested on December 31, 2015 (47,460 ) $0.19 per share Unvested shares as of December 31, 2015 171,061 $0.19 per share Stock compensation cost for consultants is adjusted at the end of each reporting period to reflect cost based on the closing stock price at the end of that reporting period. That price was $0.19 at December 31, 2015. At December 31, 2015, total unrecognized RSA compensation cost of $1,247,595 is expected to be recognized over a weighted average remaining service period of 1.4 years. Stock Appreciation Rights – Weighted Number of average unvested grant-date SARs fair value Unvested shares as of January 1, 2015 - Granted on August 18, 2015 2,159,855 $0.318 per share Forfeited (371,155 ) $0.318 per share Unvested shares as of December 31, 2015 1,788,700 $0.318 per share Weighted average assumptions used to estimate fair value were expected life of five years, 61.17% volatility, 1.60% risk-free rate, and zero annual dividends. Below is a summary of the SARs and changes for the year to date ended December 31, 2015 for former Yuma employees acting as consultants. Number of Weighted unvested average SARs fair value Unvested shares as of January 1, 2015 - Granted on November 30, 2015 19,080 $0.036 per share Granted on December 15, 2015 104,639 $0.036 per share Unvested shares as of December 31, 2015 123,719 $0.036 per share Stock compensation cost for consultants is adjusted at the end of each reporting period to reflect the cost based on the closing stock price at the end of that reporting period. That price was $0.19 at December 31, 2015 and was used to compute a new fair value of $0.036 per share. Weighted average assumptions used to estimate fair value were expected option life of .91 years, 130% volatility, 0.65% risk-free interest rate, and zero expected dividend rate. At December 31, 2015, total unrecognized SAR compensation cost of $418,039 is expected to be recognized over a weighted average remaining service period of 1.5 years. The SARs in the tables above have a weighted average exercise price of $.605 and an aggregate intrinsic value of zero. The Company intends to settle these SARs in equity, as opposed to cash. Stock Options – 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, 2014 105,000 $ 5.17 2.65 $ - Granted - - - - Exercised - - - - Forfeited - - - - Outstanding at December 31, 2015 105,000 $ 5.17 2.65 $ - Vested at December 31, 2015 105,000 $ 5.17 2.65 $ - Exercisable at December 31, 2015 105,000 $ 5.17 2.65 $ - As of December 31, 2015, there were no unvested stock options or unrecognized stock option expenses. The following table summarizes the information about stock options outstanding and exercisable at December 31, 2015. Options Outstanding Options Exercisable Weighted- Weighted Weighted average average average Exercise Number of remaining exercise Number of exercise price shares life (years) price shares price $ 5.40 5,000 0.10 $ 5.40 5,000 $ 5.40 $ 5.16 100,000 2.77 $ 5.16 100,000 $ 5.16 105,000 105,000 Restricted Stock Units – A summary of the status of the unvested RSUs and changes during the year ended December 31, 2015 is presented below. Weighted Number of average unvested grant-date RSUs fair value Unvested shares as of January 1, 2015 95,424 $2.72 per share Forfeited (15,146 ) $2.72 per share Unvested shares as of December 31, 2015 80,278 $2.72 per share On December 25, 2014, the Company entered into a Separation Agreement and General Release of Claims (“Separation Agreement”) with its former President and Chief Operating Officer which provided for, among other things, the forfeiture of 355,192 RSAs with various vesting dates and the issuance of an aggregate of 273,907 RSUs that vested December 31, 2014, with 254,973 to be issued on April 1, 2015 and 18,934 to be issued on May 20, 2015. These RSUs were valued under the equity method, and valued as of December 25, 2014.

EARNINGS PER COMMON SHARE

EARNINGS PER COMMON SHARE	12 Months Ended
	Dec. 31, 2015
EARNINGS (LOSS) PER COMMON SHARE:
EARNINGS PER COMMON SHARE	Earnings per common share are computed by dividing earnings available to common stockholders by the weighted average number of shares of common stock outstanding during the period. Potential common stock equivalents are determined using the “if converted” method. Potentially dilutive securities for the computation of diluted weighted average number of shares are as follows: Years Ended December 31, 2014 2015 2014 2013 Restricted Stock Awards 1,786,812 2,280,137 1,334,452 Stock Appreciation Rights 791,675 - - Restricted Stock Units 93,733 105,643 91,762 Series A Preferred Stock - 10,031,104 12,964,860 Series B Preferred Stock - 5,263,585 7,259,079 2,672,220 17,680,469 21,650,153 The Series A and Series B Preferred Stock were converted to common stock on September 10, 2014, 253 days into the total 365 days for the twelve month period ended December 31, 2014. This shorter period accounts for the decrease in weighted average number of shares in the twelve months ended December 31, 2014 compared to the same period in 2013. The Company excludes preferred stock and stock-based awards whose effect would be anti-dilutive from the calculation. For the years ended December 31, 2015, 2014 and 2013, adjusted earnings were losses, therefore common stock equivalents were excluded from the calculation of diluted net loss per share of common stock, as their effect was anti-dilutive.

DEBT AND INTEREST EXPENSE

DEBT AND INTEREST EXPENSE	12 Months Ended
	Dec. 31, 2015
Debt Disclosure [Abstract]
DEBT AND INTEREST EXPENSE	December 31, December 31, 2015 2014 Variable rate revolving credit agreement payable to Société Générale, CIT Bank, NAC, and LegacyTexas Bank, maturing May 20, 2017, secured by the stock of Exploration and its interest in POL, and guaranteed by The Yuma Companies, Inc. $ 29,800,000 $ 22,900,000 Installment loan due February 29, 2016, originating from the financing of insurance premiums at 3.74% interest rate. 108,894 - Installment loan due June 11, 2016, originating from the financing of insurance premiums at 3.76% interest rate. 154,741 - Installment loan due June 11, 2015, originating from the financing of insurance premiums at 3.76% interest rate. - 154,750 Installment loan due February 28, 2015, originating from the financing of insurance premiums at 3.65% interest rate. - 128,093 30,063,635 23,182,843 Less: current portion (30,063,635 ) (282,843 ) Total long-term debt $ - $ 22,900,000 On August 10, 2011, Exploration entered into a $125.0 million syndicated credit agreement with Amegy Bank National Association (“Amegy”) as Administrative Agent, or Agent Bank (the “credit agreement”). The maximum available under the revolving credit facility is determined by a formula based on the discounted value of the producing and non-producing crude oil and natural gas reserves (the borrowing base). Interest on the facility accrues at the Company’s option based on prime as published by the Wall Street Journal, or a rate based on London Interbank Offering Rate (“LIBOR”). On September 24, 2012, the credit agreement was amended whereby Union Bank N. A. (“Union”) joined the facility as a participant at 64.29% (Amegy was reduced to 35.71%) and replaced Amegy as Administrative Agent. Amegy, however, remained the Company’s bank for regular operational banking functions. On February 13, 2013, the credit agreement was further amended to add SocGen as a new participant and as a replacement for Union as the Administrative Agent, and to remove Amegy from the syndication. The participation allocation became 68.75% for SocGen and 31.25% for Union. The new interest rate margins effective February 13, 2013 are as follows: Borrowing base utilization Prime margin LIBOR margin Utilization > 90% 2.25 % 3.25 % 75% < utilization < 90% 2.00 % 3.00 % 50% < utilization < 75% 1.75 % 2.75 % 25% < utilization < 50% 1.50 % 2.50 % Utilization < 25% 1.25 % 2.25 % On May 20, 2013, a Third Amendment to the credit agreement added CIT Bank, NAC (“CIT”, previously OneWest Bank, FSB) to replace Union with the new participation for SocGen and CIT equal at 50/50. With the third amendment, the credit agreement maturity date was changed to May 20, 2017. On September 27, 2013, the Borrowing Base Redetermination Agreement and Assignment added LegacyTexas Bank (“Legacy”, previously View Point Bank, N.A.) as a third lender in the credit agreement. Participating percentages at September 27, 2013 became 37.5% for SocGen, 37.5% for CIT and 25% for Legacy. Effective April 22, 2014, Exploration entered into the Fourth Amendment to the credit agreement, which among other things, provided for a borrowing base of $40.0 million. On October 14, 2014, Exploration entered into the Fifth Amendment to the credit agreement to permit YEI to make dividend payments on the Series A Preferred Stock, subject to certain limitations. On January 23, 2015, Exploration entered into the Sixth Amendment to the credit agreement. Pursuant to this amendment, (i) the borrowing base under the credit agreement remained at $40.0 million until the next borrowing base redetermination date which occurred on April 7, 2015, subject to a loan covenant requiring a ten percent availability under the line in order to pay dividends on any preferred stock, (ii) the Company could issue additional series of preferred stock subject to certain restrictions, (iii) the definition of “Change of Control” was amended and restated; (iv) the Company pledged the stock of Exploration; (v) Exploration pledged its interest in its wholly owned subsidiary, Pyramid Oil LLC (“POL”), and (vi) the oil and natural gas properties held by the Company in the state of California were transferred from the Company to POL and were mortgaged under the credit agreement. In addition, Exploration’s properties in North Dakota were mortgaged. On April 7, 2015, Exploration entered into the Seventh Amendment to the credit agreement, which reduced the Company’s borrowing base to $33.0 million, with an additional $3.0 million non-conforming borrowing base that expired on September 1, 2015. On July 7, 2015, Exploration entered into the Eighth Amendment to the credit agreement that changed the borrowing base to $33.5 million with a $1.5 million additional but non-conforming portion that expired on October 1, 2015. The banks participate in the Company’s revolving line of credit at 37.5%, 37.5% and 25% for SocGen, CIT and Legacy, respectively. During September 2015, Legacy replaced Amegy as the Company’s bank for treasury operations. On December 30, 2015, Exploration entered into the Waiver, Borrowing Base Redetermination and Ninth Amendment to the credit agreement in which the borrowing base was reduced to $29.8 million and will automatically be reduced to $20 million on May 31, 2016 unless otherwise reduced by or to a different amount by the lenders under the credit agreement. This amendment also provided a waiver of the financial covenant related to the maximum permitted ratio of funded debt to EBITDA for the fiscal quarter ended September 30, 2015 and any failure to comply with that financial covenant and certain other financial covenants for the fiscal quarter ended December 31, 2015. Pursuant to the amendment, Exploration agreed that on or before February 6, 2016, it would engage an investment bank to explore strategic options for its finances and, on or before March 31, 2016, would either enter into an underwritten commitment for additional capital in an aggregate amount sufficient to pay any borrowing base deficiency then existing or enter into a definitive agreement for the acquisition by a third party of all or substantially all of the assets of Exploration and its subsidiaries by merger, asset purchase, equity purchase or other structure acceptable to the Administrative Agent and the lenders. On February 10, 2016, the Company entered into the merger agreement with Davis (see Note 24 – Subsequent Events), and expects to enter into another amendment to the credit agreement to account for the contemplated merger with Davis. Costs and fees paid to the banks in connection with the revolving credit facility are amortized through May 31, 2016, due to the possible accelerated maturity date per the SocGen Ninth Amendment. SocGen, as Agent Bank, is also paid an annual administrative fee of $25,000 that is usually amortized over the year, but will also be amortized through May 31, 2016. The following summarizes interest expense for the years ended December 31, 2015, 2014 and 2013. Years Ended December 31, 2015 2014 2013 Credit facility $ 1,104,231 $ 1,109,153 $ 1,010,539 Credit facility commitment fees 34,512 70,813 56,092 Amortization and write offs of credit facility loan costs 286,009 188,669 480,261 Insurance installment loan 13,654 13,640 16,161 Louisiana Mineral Board - - 32,383 Other interest charges 1,489 3,275 4,056 Capitalized interest (983,472 ) (1,059,350 ) (1,031,816 ) Total interest expense $ 456,423 $ 326,200 $ 567,676 The terms of the credit agreement require Exploration to meet a specific current ratio, interest coverage ratio, and a funded debt to EBITDA ratio. The credit agreement also contains a covenant requiring ten percent availability under the current borrowing line in order to pay dividends on the Series A Preferred Stock. In addition, the credit agreement requires the guarantee of YCI. Exploration was not in compliance with all of the loan covenants as of December 31, 2015; however, it received a waiver pursuant to the Waiver, Borrowing Base Redetermination and Ninth Amendment to the credit agreement dated December 30, 2015. Aggregate principal payments based on the Company’s current borrowings as of December 31, 2015 for the next five years are shown below: 2016 $ 30,063,635 * 2017 - 2018 - 2019 - 2020 - *Includes $29,800,000 for possible accelerated maturity per Ninth Amendment to the credit agreement which otherwise matures May 20, 2017.

MERGER WITH PYRAMID OIL COMPANY

MERGER WITH PYRAMID OIL COMPANY AND GOODWILL	12 Months Ended
	Dec. 31, 2015
Business Combinations [Abstract]
MERGER WITH PYRAMID OIL COMPANY AND GOODWILL	On September 10, 2014, a wholly owned subsidiary of Pyramid merged with and into Yuma Co. in exchange for 66,336,701 shares of common stock and Pyramid changed its name to “Yuma Energy, Inc.” (the “merger”). As a result of the merger, the former Yuma Co. stockholders received approximately 93% of the then outstanding common stock of the Company and thus acquired voting control. Although the Company was the legal acquirer, for financial reporting purposes the merger was accounted for as a reverse acquisition of Pyramid by Yuma Co. The transaction qualified as a tax-deferred reorganization under Section 368(a) of the Internal Revenue Code of 1986, as amended (the “Code”). As a result of the merger announcement with Pyramid on February 6, 2014, expenses of approximately $1.3 million previously incurred by the Company in connection with exploring options to obtain a public listing were written off during the first quarter of 2014. The 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 values. A table of adjustments reflecting the allocation of the fair values and computation of goodwill is provided below. These adjustments reflect the elimination of the components of Pyramid’s historical stockholders’ equity, the estimated value of consideration paid by the Company in the merger using the closing price of its common stock on September 10, 2014, and the adjustments to the historical book values of Pyramid’s assets and liabilities to their estimated fair values, in accordance with acquisition accounting. The Company believes the purchase price allocation is final as of the fourth quarter 2014 and that these estimates are reasonable and the significant effects of the merger are properly reflected. September 10, 2014 (as initially Measurement period (i) September 10, 2014 Purchase Price(i): Shares of Pyramid common stock held by Pyramid shareholders 4,788,085 - 4,788,085 Pyramid common stock price (September 10, 2014 closing price) $ 4.70 $ - $ 4.70 Fair value of Pyramid common stock issued $ 22,504,000 $ - $ 22,504,000 Consideration paid to Pyramid’s shareholders - - - Issuance of 100,000 shares to Pyramid affiliated persons at $5.01 per share (September 11, 2014 closing price) 501,000 - 501,000 Fair value of Pyramid options assumed by the Company (ii) 100,500 - 100,500 Total purchase price 23,105,500 - 23,105,500 Estimated Fair Value of Liabilities Assumed: Current liabilities 633,917 - 633,917 Noncurrent deferred tax liability (iii) 4,879,724 - 4,879,724 Other noncurrent liabilities (asset retirement obligation) 1,334,278 (390,327 ) 943,951 Amount attributable to liabilities assumed 6,847,919 (390,327 ) 6,457,592 Total purchase price plus liabilities assumed 29,953,419 (390,327 ) 29,563,092 Estimated Fair Value of Assets Acquired: Current assets 9,066,589 - 9,066,589 Oil and natural gas properties (iv) 10,726,715 - 10,726,715 Net other property and equipment 4,158,420 - 4,158,420 Other noncurrent assets 261,380 - 261,380 Amount attributable to assets acquired 24,213,104 - 24,213,104 Goodwill (i) $ 5,740,315 $ (390,327 ) $ 5,349,988 (i) During the fourth quarter 2014 (within the allowed measurement period for adjustments to goodwill), the Pyramid asset retirement obligation as of the merger date was re-evaluated for cost projections, asset lives were adjusted to reflect the updated reserve report, inflation factors were updated and the credit adjusted risk-free rate became based on the Company’s outstanding debt cost. The result was a decrease of $390,327 to the liability and an equal decrease to goodwill. (ii) (iii) (iv) The drop in crude oil prices after the merger and the resulting decline in the Company’s common share price caused the Company to test goodwill for impairment at June 30, 2015. Goodwill was determined to be fully impaired and as a result, the balance of $5,349,988 was written off. The following unaudited pro forma combined results of operations are provided for the years ended December 31, 2014 and 2013 as though the merger had been completed as of the beginning of the earliest period presented, or January 1, 2013. These pro forma combined results of operations have been prepared by adjusting the historical results of the Company to include the historical results of Pyramid. Pyramid’s historical property impairment expenses recognized under the successful efforts method of accounting were eliminated as they would not have been incurred under full cost accounting. Pyramid’s historical depletion of oil and gas property was also adjusted to reflect the change to full cost accounting. 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 merger or any estimated costs that will be incurred to integrate Pyramid. 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, 2014 2013 Revenues $ 46,238,208 $ 33,534,396 Net income (loss) $ (3,388,094 ) $ (7,834,907 ) Net income (loss) per share: Basic $ (.07 ) $ (.19 ) Diluted $ (.07 ) $ (.19 ) For the year ended December 31, 2014, the Company recognized $945,580 of sales of natural gas and crude oil less lease operating expenses, production taxes and other operating expenses of $1,285,200 related to properties acquired in the merger. Additionally, non-recurring transaction costs of $2,226,719 and $124,222 related to the merger for the fiscal years 2014 and 2013, respectively, and costs of $1,287,285 to explore other options for a public listing expensed in 2014 are included in the Consolidated Statements of Operations as general and administrative expenses; however, these non-recurring transaction costs have been excluded from the pro forma results in the above table.

STOCKHOLDERS' EQUITY

STOCKHOLDERS' EQUITY	12 Months Ended
	Dec. 31, 2015
EQUITY:
STOCKHOLDERS' EQUITY	Common Stock The Company is authorized to issue up to 300,000,000 shares of common stock, no 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. From the date of issuance of the Series A Preferred Stock (July 2011) and the Series B Preferred Stock (July and August 2012), until their conversion into common stock at the closing of the merger, no dividends could be declared or paid or set apart for payment and no other distribution could be declared or made or set apart for payment, in each case except for certain property distributions as defined in the Certificate of Incorporation of Yuma Co., and detailed in Note 7 – Related Party Transactions. In addition, during this period, holders of common stock could not vote on any amendment to the Certificate of Incorporation of Yuma Co. that related solely to the terms of the preferred stock. Yuma Co. 2011 Stock Option Plan Effective June 21, 2011, Yuma Co. adopted the 2011 Stock Option Plan (“Yuma Co. Plan”). The Yuma Co. Plan provided, among other things, for the granting of up to 6,000 (or approximately 4,544,025 shares based on the merger exchange ratio) shares of common stock as awards to key employees, officers, directors, and consultants of the Company by the Board of Directors. An award could take the form of stock options, SARs, RSAs or RSUs. At its meeting on August 1, 2014, the Board of Directors of Pyramid approved the assumption and amendment and restatement of the Yuma Co. Plan, which assumption was effective as of September 10, 2014 (“Plan Effective Date”). Following the Plan Effective Date, there were approximately 2,454,785 shares of common stock that were subject to outstanding RSAs and RSUs granted by Yuma Co. under the Yuma Co. Plan and that were assumed by the Company. Further, on September 11, 2014, the Board determined that no additional awards would be granted under the Yuma Co. Plan, and that the 2014 Plan would be used going forward. 2014 Long-Term Incentive Plan On August 1, 2014, the board of directors of Pyramid adopted the 2014 Long-Term Incentive Plan (the “2014 Plan”), subject to shareholder approval at the 2014 Special Meeting of Shareholders. The shareholders of Pyramid approved this proposal at the Special Meeting held September 10, 2014 and became effective as of that date. Under the 2014 Plan, YEI may grant stock options, RSAs, RSUs, SARs, performance units, performance bonuses, stock awards and other incentive awards to YEI employees or those of YEI’s subsidiaries or affiliates. YEI may also grant nonqualified stock options, RSAs, RSUs, SARs, performance units, stock awards and other incentive awards to any persons rendering consulting or advisory services and non-employee directors, subject to the conditions set forth in the 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 8,900,000 shares of common stock may be issued in conjunction with awards granted under the 2014 Plan. 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.

INCOME TAXES

INCOME TAXES	12 Months Ended
	Dec. 31, 2015
Income Tax Disclosure [Abstract]
INCOME TAXES	Income taxes are provided for the tax effects of transactions reported in the financial statements and consist of taxes currently due plus deferred taxes related primarily to differences between the basis of property and equipment for financial reporting versus income tax reporting. The deferred taxes represent the future tax return consequences of those differences that will either be taxable or deductible when the differences in the basis of assets and liabilities reverse. The Company recognizes and measures income tax benefits that are more likely than not to be sustained on eventual examination or settlement. Deferred tax assets are recorded to the extent the Company believes these assets will more likely than not be realized. The Company does not have any unrecognized tax benefits for the years ended December 31, 2015, 2014 and 2013. In addition, the Company does not anticipate any unrecognized tax benefits during the next twelve months from the date these financials were available to be issued, March 29, 2016. The Company did not incur any income tax deficiencies during fiscal years 2012, 2013, 2014, and 2015, and therefore had no interest or penalties assessed during the years ended December 31, 2012, 2013, 2014, and 2015. The tax years of the Company that remain subject to examination by the Internal Revenue Service and other tax authorities are fiscal years 2012, 2013, 2014 and 2015. The Company follows the liability and asset approach in accounting for income and state franchise taxes as required by the provisions of FASB concerning accounting for income taxes. Deferred tax liabilities and assets are determined using the tax rates for the period in which those accounts are expected to be paid or received. Provisions for income taxes are composed of the following for the years ended December 31, 2015, 2014 and 2013: Years Ended December 31, 2015 2014 2013 Current income taxes (benefit): Federal $ (29,226 ) $ - $ - State (1,963 ) - - Total (31,189 ) - - Deferred income taxes (benefit): Federal (7,227,361 ) (2,377,192 ) 2,705,688 State (724,489 ) (176,662 ) 374,584 Total (7,951,850 ) (2,553,854 ) 3,080,272 Total taxes (benefit) on income $ (7,983,039 ) $ (2,553,854 ) $ 3,080,272 Deferred tax liabilities (assets) that are recognized for the estimated future tax effects attributable to temporary differences and carryforwards at year-end are as follows: Years Ended December 31, 2015 2014 Deferred tax liability (hedges) $ - $ 1,843,409 Deferred tax liability from excess of book basis over tax basis of certain assets including property, plant and equipment 30,009,264 30,081,226 Deferred tax liability 30,009,264 31,924,635 Stock-based compensation (608,442 ) (1,205,722 ) Alternative minimum tax credit carryforwards (121,686 ) (121,686 ) Net operating loss (“NOL”) carryforwards (22,481,966 ) (15,585,820 ) Other deferred tax (asset) - (396,668 ) Deferred tax asset (23,212,094 ) (17,309,896 ) Net deferred tax liability $ 6,797,170 $ 14,614,739 The deferred tax assets at December 31, 2015 and 2014 of $23,212,094 and $17,309,896, respectively, consist of deductible temporary differences related to operating loss carryforwards, unrealized losses from oil and natural gas hedges, and tax credit carryforwards and stock-based compensation generated by the consolidated group: Year NOL NOL Year of generated remaining expiration 2015 $ 14,926,752 2035 2014 14,943,985 2034 2013 9,417,693 2033 2012 8,082,421 2032 2011 5,511,938 2031 2009 4,844,318 2029 2007 1,095,474 2027 2002 3,050,662 2022 Total $ 61,873,243 The Company retroactively early adopted Accounting Standards Update 2015-14 during the fourth quarter of 2015 which requires the presentation of deferred tax assets and liabilities as noncurrent in the Consolidated Balance Sheet. See Not 1 - Summary of Significant Accounting Policies, Changes in Accounting Principles for further information regarding the adoption of Accounting Standards Update 2015-14. The tax provisions differ from the amounts that would be calculated by using federal statutory rate of 35 percent to calculate income taxes because (i) no tax benefit has been recognized for nondeductible expenses; (ii) the Companies are subject to various state income taxes; and (iii) the tax provisions consider the effect of graduated rates, as follows: Years Ended December 31, 2015 2014 2013 Amount computed using the statutory rate $ (6,645,827 ) $ (7,972,651 ) $ (10,489,441 ) Increase (reduction) in taxes resulting from: Non-deductible change in value of preferred stock derivative liability - 5,486,895 9,190,496 State taxes (726,452 ) (210,021 ) 254,645 Other (610,760 ) 141,923 4,124,572 Income tax expense (benefit) $ (7,983,039 ) $ (2,553,854 ) $ 3,080,272 For the year ended December 31, 2013, the Other, net amount relates primarily to changes in estimates to net operating losses, depletion and amortization. When the Company believes that it is more likely than not that a net operating loss or credit carryforward may expire unused, it establishes a valuation allowance against the loss or credit. No valuation allowance has been established as of December 31, 2015, 2014 or 2013. Income taxes are allocated among the companies in the consolidated group on the basis of the tax effect each company contributed to income taxes for the years 2015 and 2014.

CONTINGENCIES

CONTINGENCIES	12 Months Ended
	Dec. 31, 2015
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. On July 9, 2014, Nabors Drilling USA, L.P. and other Nabors entities and Yuma Energy, Inc. and several of its wholly owned subsidiaries were named in a lawsuit filed in the District Court of Harris County, Texas, in the 80th Judicial District, concerning the death of an employee of Timco Services during the drilling of the Crosby 12-1 well. The Company has tendered its defense to its liability insurance carriers who are responding. There has been one unsuccessful mediation session. Depositions are being scheduled. Management believes that the Company has adequate insurance to meet this potential claim. 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. 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 and one other owner, have executed amendments signifying their concurrence that the 1950 Community Oil and Gas Lease is still in force and effect. The parties are presently in the process of document discovery. Environmental Remediation Contingencies As of December 31, 2015, 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. Exploration has been named as one of 97 defendants in a matter entitled Board of Commissioners of the Southeast Louisiana Flood Protection Authority – East, Individually and As the Board Governing the Orleans Levee District, the Lake Borgne Basin Levee District, and the East Jefferson Levee District v. Tennessee Gas Pipeline Company, LLC, et al., Civil District Court for the Parish of Orleans, State of Louisiana, No. 13-6911, Division “J” - 5, now removed as Civil Action No. 13-5410, before the United States District Court, Eastern District of Louisiana. Plaintiff filed the suit on July 24, 2013 seeking damages and injunctive relief arising out of defendants’ drilling, exploration, and production activities from the early 1900s to the present day in coastal areas east of the Mississippi River in Southeast Louisiana. The suit alleges that defendants’ activities have caused “removal, erosion, and submergence” of coastal lands resulting in significant reduction or loss of the protection such lands afforded against hurricanes and tropical storms. Plaintiff alleges that it now faces increased costs to maintain and operate the man-made hurricane protection system and may reach the point where that system no longer adequately protects populated areas. Plaintiff lists hundreds of wells, pipelines, and dredging events as possible sources of the alleged land loss. Exploration is named in association with 11 wells, four rights-of-way, and one dredging permit. The suit does not specify any deficiency or harm caused by any individual activity or facility. Although the suit references various federal statutes as sources of standards of care, plaintiff claims that all causes of action arise under state law: negligence, strict liability, natural servitude of drain, public nuisance, private nuisance, and as third-party beneficiary under breach of contract. The Company tendered its defense to its liability insurance carriers, who are responding. On February 13, 2015, the federal judge adjudicating the matter granted defendants “Joint Motion to Dismiss for Failure to State a Claim Under Rule 12(b)(6)”, thereby dismissing plaintiff’s claims with prejudice in the matter. On February 20, 2015, the Board of Orleans filed a notice of appeal to the U.S. Fifth Circuit. On February 29, 2016, oral arguments were held regarding the appeal, but as of March 29, 2016, no ruling on the appeal has been made. The Company will continue to contest plaintiff’s legal arguments and factual assertions. 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. Escheat Audits The States of Louisiana, Texas, Minnesota 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.

EMPLOYEE BENEFIT PLANS

EMPLOYEE BENEFIT PLANS	12 Months Ended
	Dec. 31, 2015
Compensation and Retirement Disclosure [Abstract]
EMPLOYEE BENEFIT PLANS	The Company has a defined contribution 401(k) plan (the “Plan”) for its qualified employees. Employees may contribute any amount of their compensation to the Plan, subject to certain Internal Revenue Service annual limits and certain limitations for employees classified as high income. The Plan provides for discretionary matching contributions by the Company, and the Company currently provides a match for non-highly compensated employees only at a rate of 100 percent of each employee’s contribution up to 4 percent of the employee’s base salary. The Company contributed $56,051 and $38,827 under the Plan for the years ended December 31, 2015 and 2014, 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 85 percent for the employee portion of the premium, and a variable percentage of the dependent portion, depending on employee compensation levels. 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 $138,962 and $166,660 for the years ended December 31, 2015 and 2014, respectively. The Company maintains employment contracts with members of its exploration staff and with certain key employees of the Company. As of December 31, 2015, future employment contract salary commitments were $1,399,242, excluding automatic renewals, evergreen and month-to-month provisions, and potential Annual Incentive Plan awards as described below. The Company adopted the 2014 Plan as described in Note 15 – Stockholders’ Equity. Note 11 – Stock-Based Compensation describes restricted stock awards granted under the 2014 Plan. During December 2011, the Company adopted an employee Annual Incentive Plan (“AIP”). Under the AIP, the Board of Directors establishes certain performance metrics by which management is to be measured annually. These metrics are determined annually and awards of restricted stock, cash, or some combination of both may be made to members of the management team. The Board of Directors will meet during 2016 to evaluate the management team and determine any awards that may be due for 2015. To the extent compensation costs relate to employees directly involved in exploration and development activities, such amounts are capitalized to oil and natural gas properties. Amounts not capitalized to oil and natural gas properties are recognized as general and administrative expense.

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, 2015
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 Exploration’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 significant 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.

OTHER DISCLOSURES

OTHER DISCLOSURES	12 Months Ended
	Dec. 31, 2015
Other Disclosures
OTHER DISCLOSURES	Other Operating Expenses December 31, 2015 2014 2013 Bad debt expense $ 839,171 $ 97,068 $ 193,601 Recovery of bad debts (342,944 ) (1,984 ) (2,520 ) Loss (gain) on disposal of property (28,006 ) 3,392 (19,307 ) Total $ 468,221 $ 98,476 $ 171,774 Other Non-Operating Income (Expense) December 31, 2015 2014 2013 Interest income $ 19,587 $ 23,632 $ 7,336 Rental income 16,000 - - Bank-mandated derivative instruments novation cost - - (175,000 ) Louisiana sales tax settlement - - (44,149 ) Louisiana Mineral Board audit - - (23,686 ) Other 751 1,746 (5,118 ) Total $ 36,338 $ 25,378 $ (240,617 ) Other Receivables December 31, 2015 2014 December 2015 and December 2014 settled oil derivative instruments $ 257,286 $ 407,003 Tax refund 177,157 158,571 Debit balances for trade payables 109,586 187,031 Refund from PPI for duplicate charges 89,544 89,544 D&O insurance premium adjustment - 16,356 Other - (1,943 ) Total $ 633,573 $ 856,562 Prepayments December 31, 2015 2014 Insurance $ 570,379 $ 536,410 Taxes and fees 39,687 21,882 Property taxes 41,583 56,992 Other subscriptions 16,508 6,355 Software maintenance agreements 14,572 19,105 Geological well database subscription 8,883 19,055 Software licenses 2,065 44,172 Exploration and drilling costs - 71,893 Services - 4,530 Other 10,846 1,840 Total $ 704,523 $ 782,234 Other Current Deferred Charges December 31, 2015 2014 Loan fees $ 415,740 $ 189,409 Deferred premium on 2015 oil derivative instruments - 153,389 Total $ 415,740 $ 342,798 Other Noncurrent Assets December 31, 2015 2014 Deferred offering costs $ 38,104 $ - Loan fees - 262,200 Total $ 38,104 $ 262,200 Other Accrued Liabilities December 31, 2015 2014 Employee termination benefits $ 422,037 $ - Salaries and bonuses 393,072 479,537 Accounting and audit 202,297 22,964 Severance taxes 157,941 164,374 Ad valorem taxes 143,957 172,444 Vacation 138,962 166,660 Sales and use tax 85,076 81,661 Insurance 67,532 119,121 Fees for commodity hedging advisor 64,953 48,590 Interest expense 39,471 9,327 Financing cost 35,000 - Employee restricted stock unit awards 13,981 - Commodity hedge settlement - 153,389 Other 17,205 1,498 Total $ 1,781,484 $ 1,419,565

SALES TO MAJOR CUSTOMERS

SALES TO MAJOR CUSTOMERS	12 Months Ended
	Dec. 31, 2015
Risks and Uncertainties [Abstract]
SALES TO MAJOR CUSTOMERS	The Company generally sells crude oil and natural gas to numerous customers on a month-to-month basis. Three customers accounted for approximately 67 and 73 percent of unaffiliated oil and natural gas sales in the years ended December 31, 2015 and 2014, respectively. Four customers accounted for approximately 78 percent of unaffiliated oil and natural gas sales in the year ended December 31, 2013.

LEASES

LEASES	12 Months Ended
	Dec. 31, 2015
Leases [Abstract]
LEASES	The Company leases its primary office space of 15,180 square feet for $23,403 per month, plus $50 per month for each employee or contractor parking space. The lease term expires on December 31, 2017. On November 1, 2012, the monthly rent was reduced to $21,821 on a triple-net basis, and then escalated by 1.45 percent for the period November 1, 2013 through October 31, 2014. The lease then escalates by approximately 2.8 percent each year thereafter. 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. The lease called for a security deposit of $2,684, and monthly rent of $1,949 commencing on May 1, 2014, escalating to $2,045 on May 1, 2015 and $2,141 on May 1, 2016. Aggregate rental expense for fiscal years 2015, 2014 and 2013 was $575,905, $531,127 and $534,275, respectively. As of December 31, 2015, future minimum rentals under all noncancellable operating leases are as follows: 2016 579,873 2017 564,326 2018 2,264 2019 - 2020 -

AT MARKET SECURITY SALES

AT MARKET SECURITY SALES	12 Months Ended
	Dec. 31, 2015
Marketable Securities [Abstract]
AT MARKET SECURITY SALES	The Company entered into an At Market Issuance Sales Agreement (“Sales Agreement”) with an investment banking firm (the “Agent”) on December 19, 2014. Under the Sales Agreement, the Company may sell both common stock and Series A Preferred Stock pursuant to the Registration Statement on Form S-3 of the Company filed on November 5, 2013 (Registration No. 333-192094), which became effective under the Securities Act on November 21, 2013. Upon the Company’s delivery and the Agent’s acceptance of a placement notice, the Agent will use its commercially reasonable efforts, consistent with its sales and trading practices, to sell any shares subject to the placement notice. The Company initiated the sales of securities under the Sales Agreement on February 18, 2015, and as of December 31, 2015, the Company has sold the following securities for the net proceeds listed below (the Company made no sales of securities during the third or fourth quarters of 2015). Shares Net Proceeds Common Stock 1,347,458 $ 1,363,160 Series A Preferred Stock 46,857 870,386 Total $ 2,233,546

SUBSEQUENT EVENTS

SUBSEQUENT EVENTS	12 Months Ended
	Dec. 31, 2015
Subsequent Events [Abstract]
SUBSEQUENT EVENTS	The Company has evaluated subsequent events through March 29, 2016, the date these financial statements were available to be issued. The Company is not aware of any subsequent events which would require recognition or disclosure in the financial statements, except as noted below or already recognized or disclosed. Agreement and Plan of Merger and Reorganization On February 10, 2016, YEI and privately held Davis Petroleum Acquisition Corp. (“Davis”) entered into a definitive merger agreement for an all-stock transaction. Upon completion of the transaction, YEI will reincorporate in Delaware, implement a one for ten reverse split of its common stock, and convert each share of its existing Series A Preferred Stock into 35 shares of common stock prior to giving effect for the reverse split (3.5 shares post reverse split). Following these actions, YEI will issue additional shares of common stock in an amount sufficient to result in approximately 61.1% of the common stock being owned by the current common stockholders of Davis. In addition, YEI will issue approximately 3.3 million shares of a new Series D preferred stock to existing Davis preferred stockholders, which is estimated to have a conversion price of approximately $5.70 per share, after giving effect for the reverse split. The Series D preferred stock is estimated to have a liquidation preference of approximately $18.7 million at closing, and will be paid dividends in the form of additional Series D preferred stock at a rate of 7% per annum. Upon closing, there will be an aggregate of approximately 23.7 million shares of common stock outstanding (after giving effect to the reverse stock split and conversion of Series A Preferred Stock to common stock). The transaction is expected to qualify as a tax-deferred reorganization under Section 368(a) of the Code. The merger agreement is subject to the approval of the shareholders of both companies, as well as other customary approvals, including authorization to list the newly issued shares on the NYSE MKT. The parties anticipate completing the transaction in mid-2016. Greater Masters Creek Field Area During the first quarter of 2016, the Company shut-in 14 Austin Chalk wells in Beauregard, Rapides and Vernon Parishes, Louisiana due to low oil and natural gas prices. If production is not restarted from these wells, the associated leases will expire, reducing the Company’s proved reserves by approximately 1,629 MBoe, acreage by 22,021 gross (18,140 net) acres, operated proved undeveloped locations by three, and operated non-proved undeveloped locations by seven. During the first quarter of 2016, the Company received notice from the operator of certain wells in Rapides and Vernon Parishes, Louisiana, that certain wells in which the Company has an interest were shut-in due to current economic conditions. The operator plans to sell their interest. If the operator does not restart production from these wells or if a subsequent operator does not restart production from these wells, the associated leases will expire, which would reduce the Company’s proved reserves by approximately 285 MBoe, acreage by 18,895 gross (3,737 net) acres, non-operated proved undeveloped locations by three, and non-operated non-proved undeveloped locations by 18. The Company is currently negotiating with a certain mineral owner to amend the oil and gas lease agreement to extend the expiration date of certain acreage that is not held by production as of March 29, 2016. The total acreage is approximately 25,139 acres which will expire July 1, 2016 unless the Company initiates drilling of a development well on the pooled lands or pays a deferred development payment by July 1, 2016. If the leased acreage expires, the Company’s proved reserves would be reduced by approximately 5,096 MBoe, the number of operated proved undeveloped locations and operated non-proved locations would be reduced by 13 and 16, respectively. Texas Southeastern Gas Marketing Company As of January 1, 2016, the Company decided to discontinue the operations of Texas Southeastern Gas Marketing Company due to the limited volumes of natural gas that it marketed, as well as the costs associated with accounting for the entity.

SUPPLEMENTARY INFORMATION ON OI

SUPPLEMENTARY INFORMATION ON OIL AND NATURAL GAS EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES (UNAUDITED)	12 Months Ended
	Dec. 31, 2015
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
SUPPLEMENTARY INFORMATION ON OIL AND NATURAL GAS EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES (UNAUDITED)	Costs Incurred Costs incurred in oil and natural gas property acquisition, exploration and development activities, all of which are conducted within the continental United States, are summarized below: December 31, 2015 2014 2013 Property acquisition costs - unproved $ (9,635,309 ) $ 1,105,782 $ 3,865,932 Property acquisition costs - proved 7,587,965 3,349,473 8,539,134 Sales proceeds - unproved (30,442 ) (359,667 ) (679,266 ) Sales proceeds - proved - (307,600 ) (718,000 ) Exploration costs 3,217,161 426,909 2,504,087 Development costs 1,121,654 20,139,409 11,910,179 Capitalized asset retirements costs 4,301,810 241,629 5,795,400 Total costs incurred $ 6,562,839 $ 24,595,935 $ 31,217,466 The Company sells oil and natural gas prospects. The gains or losses from these sales are recorded as adjustments to the full cost pool under U.S. Securities and Exchange Commission (“SEC”) guidelines. Prospect profits were $30,442, $28,616 and $50,346 for fiscal years 2015, 2014 and 2013, respectively. Capitalized Costs Relating to Oil and Gas Producing Activities The following table illustrates the total amount of capitalized costs relating to natural gas and crude oil producing activities and the total amount of related accumulated depreciation, depletion and amortization: December 31, 2015 2014 Oil and gas properties, full cost method: Not subject to amortization: Prospect inventory $ 7,719,857 $ 14,913,126 Property acquisition costs - unproved 6,150,862 8,623,344 Well development costs - unproved 417,997 2,170,582 Subject to amortization: Property acquisition costs - proved 58,393,861 50,744,401 Well development costs - proved 81,063,335 74,440,227 Capitalized costs - unsuccessful 60,549,824 52,539,407 Capitalized asset retirement costs 4,505,018 8,806,828 Total capitalized costs 218,800,754 212,237,915 Less accumulated depreciation, depletion and amortization (117,304,945 ) (103,929,493 ) Net capitalized costs $ 101,495,809 $ 108,308,422 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. The Company only prepares engineering studies of estimated oil and natural gas quantities on a consolidated basis. The Company has a quantity of interests that, individually, are immaterial and are excluded from prepared engineering studies. Accounting sales volumes and receipts differ from amounts prepared by internal engineers and included in the following tables. 2015 2014 2013 Barrels of oil and condensate: Proved developed and undeveloped reserves: Beginning of year 14,011,343 14,381,960 7,739,964 Revisions of previous estimates (5,596,379 ) (565,143 ) (1,142,654 ) Purchases of oil and gas properties 103,387 472,132 7,959,600 Extensions and discoveries 769,661 51,993 92,152 Sale of oil and gas properties - - - Production (321,687 ) (329,599 ) (267,102 ) End of year 8,966,325 14,011,343 14,381,960 Proved developed reserves - January 1, 2,347,482 2,099,701 1,474,015 Proved developed reserves - December 31, 2,117,559 2,347,482 2,099,701 Proved undeveloped reserves - January 1, 11,663,861 12,282,259 6,265,949 Proved undeveloped reserves - December 31, 6,848,766 11,663,861 12,282,259 2015 2014 2013 Thousands of cubic feet of natural gas: Proved developed and undeveloped reserves: Beginning of year 35,259,522 38,372,369 31,071,137 Revisions of previous estimates (11,436,325 ) (479,438 ) (8,281,139 ) Purchases of oil and gas properties 264,981 81,177 16,495,803 Extensions and discoveries 3,675,358 - 362,806 Sale of oil and gas properties - - - Production (1,993,842 ) (2,714,586 ) (1,276,238 ) End of year 25,769,694 35,259,522 38,372,369 Proved developed reserves - January 1, 7,786,537 10,316,516 10,156,754 Proved developed reserves - December 31, 8,552,249 7,786,537 10,316,516 Proved undeveloped reserves - January 1, 27,472,985 28,055,853 20,914,383 Proved undeveloped reserves - December 31, 17,217,445 27,472,985 28,055,853 Revisions in 2015 to previously estimated reserves for both natural gas and crude oil were primarily caused by (i) commodity price reductions of 6,771,739 Mcf of natural gas and 3,427,849 Boe of oil and condensate causing wells to reach their economic limits sooner and causing some proved undeveloped locations to become uneconomic; (ii) upward revisions of 2,337,685 Mcf of natural gas and 1,127,131 Boe of oil and condensate primarily associated with increased performance of Bayou Hebert (La Posada) field; and (iii) reclassifying PUD reserves of 7,002,271 Mcf and 3,295,661 Boe of oil and condensate to probable reserves primarily in Masters Creek due to the current economic conditions and uncertainty in future development plans. Internal Controls Over Reserve and Future Net Revenue Estimation The Company’s principle 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 Society of Petroleum Engineers. The Executive Vice President and Chief Operating Officer reports directly to the Company’s Chief Executive Officer. At December 31, 2015, 2014 and 2013, Netherland, Sewell & Associates, Inc. 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 The 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, 2015, 2014, and 2013. The Chief Operating Officer and the reservoir engineering staff presented the outside engineering firm 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 Exploration for fiscal years 2015, 2014 and 2013. December 31, 2015 2014 2013 Future cash inflows $ 438,816,500 $ 1,339,372,300 $ 1,450,469,000 Future oil and natural gas operating expenses (129,636,500 ) (322,298,300 ) (334,883,800 ) Future development costs (126,463,700 ) (405,900,900 ) (424,256,900 ) Future income tax expenses (23,334,886 ) (133,467,940 ) (163,704,120 ) Future net cash flows 159,381,414 477,705,160 527,624,180 10% annual discount for estimating timing of cash flows (53,318,652 ) (183,249,968 ) (202,270,201 ) Standardized measure of discounted future net cash flows $ 106,062,762 $ 294,455,192 $ 325,353,979 Estimates of future net cash flows from proved reserves of gas, oil, and condensate for fiscal years 2015, 2014 and 2013 are computed using the average first-day-of-the-month price during the 12-month period. Prices used in computing year-end future cash flows were $50.28, $91.48 and $96.94 for crude oil and $2.59, $4.35 and $3.67 for natural gas for fiscal years 2015, 2014 and 2013, respectively. The ceiling test for many companies following the full cost method of accounting for oil and natural gas properties, including the Company, could be negatively impacted by prolonged unfavorable crude oil and natural gas prices. Future operating expenses and development costs are computed primarily by the Company’s petroleum engineer by estimating the expenditures to be incurred in developing and producing the Company’s proved oil and natural gas reserves at the end of the year, based on the year-end costs and assuming continuation of existing economic conditions. Future income taxes are based on year-end statutory rates, adjusted for tax basis and applicable tax credits. A discount factor of ten percent was used to reflect the timing of future net cash flows. The standardized measure of discounted future net cash flows is not intended to represent the replacement cost or fair market value of the Company’s oil and natural gas properties. An estimate of fair value would also take into account, among other things, the recovery of reserves not presently classified as proved, anticipated future changes in prices and costs, and a discount factor more representative of the time value of money and the risks inherent in reserve estimates. Change in Standardized Measure Changes in the standardized measure of future net cash flows relating to proved oil and natural gas reserves for Exploration are summarized below: 2015 2014 2013 Changes due to current year operation: Sales of oil and natural gas, net of oil and natural gas operating expenses $ (7,069,544 ) $ (25,270,455 ) $ (17,255,824 ) Extensions and discoveries 16,660 2,743,800 37,750,617 Purchases of oil and gas properties 2,268,907 12,827,533 215,427,459 Development costs incurred during the period that reduced future development costs 4,052,919 9,178,400 100,500 Changes due to revisions in standardized variables: Prices and operating expenses (373,506,778 ) (42,125,763 ) (30,773,529 ) Income taxes 65,424,175 19,303,313 (38,340,467 ) Estimated future development costs 245,056,050 7,218,529 32,430,504 Quantity estimates (80,454,131 ) (21,028,476 ) (107,070,514 ) Sale of reserves in place - - - Accretion of discount 37,672,481 43,124,820 27,910,664 Production rates, timing and other (81,853,169 ) (36,870,488 ) (6,378,317 ) Net change (188,392,430 ) (30,898,787 ) 113,801,093 Beginning of year 294,455,192 325,353,979 211,552,886 End of year $ 106,062,762 $ 294,455,192 $ 325,353,979 Sales of oil and natural gas, net of oil and natural gas operating expenses, are based on historical pre-tax results. Sales of oil and natural gas properties, extensions and discoveries, purchases of minerals in place and the changes due to revisions in standardized variables are reported on a pre-tax discounted basis.

SUMMARY OF SIGNIFICANT ACCOUN33

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)	12 Months Ended
	Dec. 31, 2015
Accounting Policies [Abstract]
Basis of Presentation	Basis of Presentation The accompanying financial statements include the accounts of YEI on a consolidated basis. All significant intercompany accounts and transactions between YEI, YCI, Exploration, Petroleum, TSM and POL have been eliminated in the consolidation. All events described or referred to as prior to September 10, 2014 relate to Yuma Co. as the accounting acquirer. All references to “Pyramid” refer to the Company prior to the closing of the merger on September 10, 2014. 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 financial statements were prepared on a going concern basis. The Company has been operating in a weak commodity price environment and was not in compliance with the trailing four quarter funded debt to EBITDA financial ratio covenant under its credit facility at September 30, 2015 and December 31, 2015 as well as the EBITDA to interest expense ratio at December 31, 2015. On December 30, 2015, the Company entered into a waiver with the lenders under its credit facility. On February 10, 2016, the Company entered into an Agreement and Plan of Merger and Reorganization with Davis Petroleum Acquisition Corp. (“Davis”) for an all-stock transaction. See Note 24 – Subsequent Events.
Management's Use of Estimates	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 assets; obligations related to employee benefits; and legal and environmental risks and exposures.
Reclassifications	Reclassifications When required for comparability, reclassifications are made to the prior period financial statements to conform to the current year presentation.
Fair Value	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 8 – Fair Value Measurements). The carrying amount of cash and cash equivalents, accounts receivable and accounts payable reported on the balance sheet approximates fair value. The fair value of debt is the estimated amount the Company would have to pay to repurchase its debt. Nonfinancial assets and liabilities initially measured at fair value include certain assets acquired in a business combination, goodwill, asset retirement obligations and exit or disposal costs. Level 3 Valuation Techniques
Cash Equivalents	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.
Short-term Investments	Short-term Investments Short-term investments consisted of commercial bank certificates of deposit which matured in May 2015 and were valued at cost.
Trade Receivables	Trade Receivables Accounts receivable are stated net of allowance for doubtful accounts of $532,719 and $138,960 at December 31, 2015 and 2014, respectively. Management evaluates accounts receivable quarterly on an individual account basis, making individual assessments of collectability, and reserves those amounts it deems potentially uncollectible.
Inventories	Inventories Inventories, consisting principally of oilfield equipment, are carried at the lower of cost or market. The Company will often have tangible materials purchased for a well carried for the joint account (oil and gas property full cost pool on the balance sheet) pending sale or disposition.
Derivative Instruments	Derivative Instruments All derivative instruments (including certain derivative instruments embedded in other contracts) are recorded in the Company’s Consolidated Balance Sheets as either an asset or liability and measured at fair value. Changes in the derivative instrument’s fair value are recognized in earnings. Under cash flow hedge accounting, unrealized gains and losses were reflected in stockholders’ equity as accumulated other comprehensive income (“AOCI”) to the extent they were effective until the forecasted transaction occurred. Absent cash-flow accounting, all hedges are treated as non-qualifying derivative instruments and mark-to-market adjustments are in the Consolidated Statements of Operations. The Company discontinued cash flow hedge accounting effective January 1, 2013. The result of this change in policy was that the amount carried in AOCI at December 31, 2012 was amortized to oil and gas revenues during the month the hedges settled. Subsequent to December 31, 2012, all hedges are treated as non-qualifying derivative instruments and all new mark-to-market adjustments are in “Sales of natural gas and crude oil” in the Consolidated Statements of Operations. The final contracts that were included within AOCI expired at the end of 2015; therefore, the AOCI balance was zero at December 31, 2015.
Oil and Natural Gas Properties	Oil and Natural Gas Properties Investments in oil and natural gas properties are accounted for using the full cost method of accounting. Under this method, all costs directly related to the acquisition, exploration, exploitation and development of oil and natural gas properties 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 Impairments 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. Management reviews the costs of these properties periodically for impairment, with the impairment provision included in the cost of oil and natural gas properties subject to amortization. Factors considered by management in impairment assessments include drilling results by the Company and other operators, the terms of oil and gas leases not held for production, and available funds for exploration and development. The table below shows the cost of unproved properties, along with well and development costs in progress not subject to amortization at December 31, 2015, and the year in which those costs were incurred. Year of acquisition 2015 2014 2013 Prior Total Leasehold acquisition cost $ (9,039,268 ) $ 154,194 $ 1,704,190 $ 19,247,036 $ 12,066,152 Exploration and development cost (1,739,341 ) 891,610 1,059,262 172,159 383,690 Capitalized interest (639,726 ) 609,970 829,456 1,027,969 1,827,669 Total $ (11,418,335 ) $ 1,655,774 $ 3,592,908 $ 20,447,164 $ 14,277,511 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. In doing this, the Company typically earns a profit over its actual costs in seismic, land, brokerage, brochuring and marketing. It typically markets interests in the project on a “third for a quarter” basis, whereby the participant pays a percentage of the cost to casing point or through prospect payout and then has its participation interest reduced by twenty-five percent (25%) with the Company earning the difference. This difference is referred to as the “carried interest.” The Company assembles 3-D seismic survey projects and markets participating interests in the projects. The Company typically recovers all of its costs plus allocated overhead, and receives a quarterly general and administrative (“G&A”) expense reimbursement paid by the various participants in the project during the 3-D seismic acquisition phase and the 3-D seismic interpretation phase. The proceeds from the sale of the 3-D seismic survey along with the quarterly G&A reimbursements are included in the full cost pool caption “Not subject to amortization.” In addition, the participants in the 3-D seismic survey typically carry the Company for a percentage of the costs associated with the 3-D survey acquisition, ranging from 25 to 35 percent. The Company received G&A expense reimbursements of $-0-, $-0- and $42,329 in fiscal years 2015, 2014 and 2013, respectively.
Other Property and Equipment	Other Property and Equipment Other property and equipment is generally recorded at cost, with the exception of the Pyramid property that was acquired in the merger, which was marked to fair value as of the closing date of the merger. 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. 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. Office business machines and furniture and fixtures are depreciated using the modified accelerated cost recovery system (“MACRS”) for financial reporting purposes. MACRS depreciation methods approximate depreciation expense computed under GAAP using the double declining balance method. Depreciation of drilling and operating equipment, automotive, and buildings is computed using the straight-line method over the shorter of the estimated useful lives or the applicable lease terms. Leasehold improvements for the corporate office space in Houston, Texas are depreciated by the straight line method over the term of the lease. Estimated useful December 31, life in years 2015 2014 Land n/a $ 2,469,000 $ 2,469,000 Office business machines 3 - 5 1,381,968 1,361,149 Drilling and operating equipment 14 982,010 982,010 Furniture and fixtures 7 412,215 412,215 Automotive 5 351,707 351,707 Office leasehold improvements 5 332,607 332,607 Buildings and improvements 3 - 25 326,000 326,000 Total other property and equipment 6,255,507 6,234,688 Less: Accumulated depreciation and leasehold improvement amortization (2,174,316 ) (1,909,352 ) Net book value $ 4,081,191 $ 4,325,336 Depreciation and leasehold improvement amortization expense totaled $275,756, $174,338 and $149,496 for the years ended December 31, 2015, 2014 and 2013, respectively.
Goodwill	Goodwill Goodwill represents the excess of the purchase price over the estimated fair value of the assets acquired net of the fair value of liabilities assumed in an acquisition. The provisions of Accounting Standards Codification (“ASC”) 350, Intangibles – Goodwill and Other (“ASC 350”) require that intangible assets with indefinite lives, including goodwill, be evaluated on an annual basis for impairment, or more frequently if events occur or circumstances change that could potentially result in impairment. The goodwill impairment test requires the allocation of goodwill and all other assets and liabilities to reporting units. However, the Company has only one reporting unit. To assess impairment, the Company has the option to qualitatively assess if it is more likely than not that the fair value of the reporting unit is less than the book value. Absent a qualitative assessment, or, through the qualitative assessment, if the Company determines it is more likely than not that the fair value of the reporting unit is less than the book value, a quantitative assessment is prepared to calculate the fair market value of the reporting unit. If it is determined that the fair value of the reporting unit is less than the book value, the recorded goodwill is impaired to its implied fair value with a charge to operating expense. The Company’s goodwill as of December 31, 2014 related to its acquisition of Pyramid. The drop in crude oil prices and the resulting decline in the Company’s common share price caused the Company to test goodwill for impairment at June 30, 2015. Goodwill was determined to be fully impaired and as a result, the balance of $5,349,988 was written off. Refer to Note 14 – Merger with Pyramid Oil Company and Goodwill for more details.
Accounts Payable	Accounts Payable Accounts payable consist principally of trade payables and costs associated with oil and natural gas exploration.
Commitments and Contingencies	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 Recognition Revenue is recognized by the Company when deliveries of 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”). TSM recognizes revenue from sales of natural gas primarily to other marketing companies and industrials in the period in which the natural gas is delivered and billed to the customer. 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.
Income Taxes	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 (see Note 16 – Income Taxes).
Other Taxes	Other Taxes Taxes incurred, other than income taxes, are as follows: December 31, 2015 2014 2013 Production and severance tax $ 1,678,825 $ 2,693,396 $ 2,403,263 Ad valorem tax 1,103,913 1,046,134 732,302 Sales tax 18,534 62,864 180,498 State franchise taxes 68,248 40,740 41,072 Total $ 2,869,520 $ 3,843,134 $ 3,357,135 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. Sales taxes are collected from customers on sales of natural gas by TSM, and remitted to the appropriate state agency. Exploration accrues sales tax on applicable purchases of materials, and remits funds directly to the taxing jurisdictions.
Financial Instruments	Financial Instruments The Company’s financial instruments consist of cash, receivables, payables, long-term debt, oil and natural gas derivatives, and (prior to the merger as described in Note 14 – Merger with Pyramid Oil Company and Goodwill) Series A and Series B Preferred Stock. The carrying amount of cash, receivables and payables approximates fair value because of the short-term nature of these items.
Accumulated Other Comprehensive Income	Accumulated Other Comprehensive Income AOCI includes changes in equity that are excluded from the Consolidated Statements of Operations and recorded directly into a separate section of equity on the Consolidated Balance Sheets. The Company’s AOCI shown on the Consolidated Balance Sheets and the Consolidated Statements of Changes in Equity consists of unrealized income and losses on cash flow hedges; however, the Company discontinued hedge accounting effective January 1, 2013. The final contracts that were included within AOCI expired at the end of 2015; therefore, the AOCI balance was zero at December 31, 2015.
General and Administrative Expenses - Stock-Based Compensation	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 2011 Stock Option Plan on June 21, 2011, and the 2014 Long-Term Incentive Plan effective September 10, 2014 (see Note 15 – Stockholders’ Equity). The Company adopted an Annual Incentive Plan for fiscal years 2015, 2014 and 2013 (see Note 18 – Employee Benefit Plans). The Company accounts for stock-based compensation at fair value. The Company grants equity-classified awards including stock options and 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 market price of common stock. 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 11 – Stock-Based Compensation.
General and Administrative Expenses - Other	General and Administrative Expenses - Other G&A expenses are reported net of amounts capitalized pursuant to the full cost method of accounting.
Re-engineering and Workovers	Re-engineering and Workovers One of the Company’s core business strategies is to perform a comprehensive field re-engineering and design to increase and maintain production, lower per-unit operating expenses, and improve field economics. Re-engineering projects are undertaken with the intent of lowering per-unit operating expenses and/or reducing field down-time. In addition, the Company seeks to implement more efficient production practices in order to increase production and/or arrest natural field production declines. These practices are often deployed in fields in connection with or in anticipation of further field development activities such as installation of secondary recovery operations or additional drilling. Workovers included within this category relate to significant non-recurring operations.
Other Noncurrent Assets	Other Noncurrent Assets Noncurrent assets at December 31, 2015 are comprised of deferred costs related to future potential equity raises. If these potential equity raises come to fruition, then costs are netted from the new equity issuance; if not, then those costs are charged to G&A. In 2014, noncurrent assets were comprised of debt financing costs, which were moved to current in 2015.
Earnings per Share	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 15 – Stockholders’ Equity.
Changes in Accounting Principles	Changes in Accounting Principles Not Yet Adopted In May 2014 and August 2015, the Financial Accounting Standards Board (“FASB”) issued an update that supersedes the existing revenue recognition requirements. This standard includes a five-step revenue recognition model to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for those goods or services. Among other things, the standard requires enhanced disclosures about revenue, provides guidance for transactions that were not previously addressed comprehensively and improves guidance for multiple-element arrangements. This standard is effective for the Company in the first quarter of 2018 and should be applied retrospectively to each prior reporting period presented or with the cumulative effect of initially applying the update recognized at the date of initial application. Early adoption is permitted. The Company is evaluating the provisions of this accounting standards update and assessing the impact, if any, it may have on its consolidated results of operations, financial position or cash flows. In July 2015, the FASB issued an update that requires an entity to measure inventory at the lower of cost and net realizable value. This excludes inventory measured using LIFO or the retail inventory method. This standard is effective for the Company in the first quarter of 2017 and will be applied prospectively. Early adoption is permitted. The Company does not expect the adoption of this standard to have a significant impact on its consolidated results of operations, financial position or cash flows. In May 2015, the FASB issued an update that removes the requirement to categorize within the fair value hierarchy all investments for which fair value is measured using the net asset value per share practical expedient. The amendment also removes certain disclosure requirements regarding all investments that are eligible to be measured using the net asset value per share practical expedient and only requires certain disclosures on those investments for which an entity elects to use the net asset value per share expedient. This standard is effective for the Company in the first quarter of 2016 and will be applied on a retrospective basis. Early adoption is permitted. This standard only modifies disclosure requirements; as such, there will be no impact on the Company’s consolidated results of operations, financial position or cash flows. In April 2015, the FASB issued an update that requires debt issuance costs to be presented in the balance sheet as a direct reduction from the associated debt liability. This standard is effective for the Company in the first quarter of 2016 and early adoption is permitted. The Company is evaluating the provisions of this accounting standards update and assessing the impact, if any, it may have on its consolidated results of operations, financial position or cash flows. In February 2015, the FASB issued an amendment to the guidance for determining whether an entity is a variable interest entity (“VIE”). The standard does not add or remove any of the five characteristics that determine if an entity is a VIE. However, it does change the manner in which a reporting entity assesses one of the characteristics. In particular, when decision-making over the entity’s most significant activities has been outsourced, the standard changes how a reporting entity assesses if the equity holders at risk lack decision making rights. This standard is effective for the Company for annual periods beginning after December 15, 2015 and early adoption is permitted, including in interim periods. The Company does not expect the adoption of this standard to have a significant impact on its consolidated results of operations, financial position or cash flows. Recently adopted In November 2015, the FASB issued an update that requires an entity to classify deferred income tax liabilities and assets as noncurrent in a classified statement of financial position. The amendments are effective for the Company in the first quarter of 2017 and early adoption is permitted. The Company elected to early adopt these amendments in the fourth quarter of 2015 on a prospective basis. Adoption of this standard did not have a significant impact on the Company’s consolidated results of operations, financial position or cash flows. In August 2014, the FASB issued an update that requires management to assess an entity’s ability to continue as a going concern by incorporating and expanding upon certain principles that are currently in U.S. auditing standards. This standard is effective for the Company in the first quarter of 2017 and early adoption is permitted. The Company elected to early adopt and has provided disclosures in conformity with this new standard. In April 2014, the FASB issued an amendment to accounting standards that changes the criteria for reporting discontinued operations while enhancing related disclosures. Under the amendment, only disposals representing a strategic shift in operations should be presented as discontinued operations. Those strategic shifts should have a major effect on the organization’s operations and financial results. Expanded disclosures about the assets, liabilities, income and expenses of discontinued operations are required. In addition, disclosure of the pre-tax income attributable to a disposal of a significant part of an organization that does not qualify for discontinued operations reporting will be made in order to provide users with information about the ongoing trends in an organization’s results from continuing operations. The amendments were effective for the Company in the first quarter of 2015. Adoption of this standard did not have a significant impact on the Company’s consolidated results of operations, financial position or cash flows.

SUMMARY OF SIGNIFICANT ACCOUN34

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Tables)	12 Months Ended
	Dec. 31, 2015
Summary Of Significant Accounting Policies Tables
Cost of unproved properties	Year of acquisition 2015 2014 2013 Prior Total Leasehold acquisition cost $ (9,039,268 ) $ 154,194 $ 1,704,190 $ 19,247,036 $ 12,066,152 Exploration and development cost (1,739,341 ) 891,610 1,059,262 172,159 383,690 Capitalized interest (639,726 ) 609,970 829,456 1,027,969 1,827,669 Total $ (11,418,335 ) $ 1,655,774 $ 3,592,908 $ 20,447,164 $ 14,277,511
Other Property and Equipment	Estimated useful December 31, life in years 2015 2014 Land n/a $ 2,469,000 $ 2,469,000 Office business machines 3 - 5 1,381,968 1,361,149 Drilling and operating equipment 14 982,010 982,010 Furniture and fixtures 7 412,215 412,215 Automotive 5 351,707 351,707 Office leasehold improvements 5 332,607 332,607 Buildings and improvements 3 - 25 326,000 326,000 Total other property and equipment 6,255,507 6,234,688 Less: Accumulated depreciation and leasehold improvement amortization (2,174,316 ) (1,909,352 ) Net book value $ 4,081,191 $ 4,325,336
Other Taxes	December 31, 2015 2014 2013 Production and severance tax $ 1,678,825 $ 2,693,396 $ 2,403,263 Ad valorem tax 1,103,913 1,046,134 732,302 Sales tax 18,534 62,864 180,498 State franchise taxes 68,248 40,740 41,072 Total $ 2,869,520 $ 3,843,134 $ 3,357,135

ORGANIZATION, CONSOLIDATION AND

ORGANIZATION, CONSOLIDATION AND NATURE OF BUSINESS (Tables)	12 Months Ended
	Dec. 31, 2015
Organization Consolidation And Nature Of Business Tables
Incorporated date	State of Date of Company name Reference incorporation incorporation The Yuma Companies, Inc. “YCI” Delaware 10/30/96 Yuma Exploration and Production Company, Inc. “Exploration” Delaware 01/16/92 Yuma Petroleum Company “Petroleum” Delaware 12/19/91 Texas Southeastern Gas Marketing Company “TSM” Texas 09/12/96 Pyramid Oil LLC “POL” California 08/08/14 Pyramid Delaware Merger Subsidiary, Inc. “PDMS” Delaware 02/04/14

ASSET RETIREMENT OBLIGATIONS (T

ASSET RETIREMENT OBLIGATIONS (Tables)	12 Months Ended
	Dec. 31, 2015
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligations	December 31, 2015 2014 Beginning of year balance $ 12,487,770 $ 10,697,679 Pyramid liabilities assumed in the merger - 943,951 Liabilities incurred during year 24,588 416,162 Liabilities settled during year (35,455 ) - Accretion expense 604,538 604,511 Revisions in estimated cash flows (4,290,943 ) (174,533 ) End of year balance $ 8,790,498 $ 12,487,770

RECEIVABLES AND PAYABLES WITH37

RECEIVABLES AND PAYABLES WITH AFFILIATES, CHIEF EXECUTIVE OFFICER AND EMPLOYEES (Tables)	12 Months Ended
	Dec. 31, 2015
Receivables And Payables With Affiliates Chief Executive Officer And Employees
Information with respect to related party transactions with affiliates	December 31, 2015 2014 Receivables from affiliates, CEO and employees: Current: Yuma CEO $ 63,329 $ 174,720 Employees 12,075 141,357 Total $ 75,404 $ 316,077

RELATED PARTY TRANSACTIONS (Tab

RELATED PARTY TRANSACTIONS (Tables)	12 Months Ended
	Dec. 31, 2015
Related Party Transactions [Abstract]
Working interests acquired	Working Amount Year Well, prospect or project interest paid 2014 Anaconda Prospect (Talbot 23-1) 1.95000 % $ 16,900 2014 Gardner Island Well & 1.43600 % Main Pass 4 Facility 1.85500 % $ 78,988 2014 Austin Chalk (Additional W.I.) 1.00000 % $ 16,000 2013 Bell City East Prospect .71063 % $ 5,330 2013 Austin Chalk 1.00000 % $ 9,412 2013 Addison Acquisition 2.00000 % $ 150,000

FAIR VALUE MEASUREMENTS (Tables

FAIR VALUE MEASUREMENTS (Tables)	12 Months Ended
	Dec. 31, 2015
Fair Value Disclosures [Abstract]
Fair value measurements by hierarchy	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 $ - $ 3,442,693 $ - $ 3,442,693 Commodity derivatives – gas - 285,895 - 285,895 Total assets $ - $ 3,728,588 $ - $ 3,728,588 Fair value measurements at December 31, 2014 Significant Quoted prices other Significant in active observable unobservable markets inputs inputs (Level 1) (Level 2) (Level 3) Total Assets: Commodity derivatives – oil $ - $ 2,858,387 $ - $ 2,858,387 Commodity derivatives – gas - 1,883,259 - 1,883,259 Total assets $ - $ 4,741,646 $ - $ 4,741,646

COMMODITY DERIVATIVE INSTRUME40

COMMODITY DERIVATIVE INSTRUMENTS (Tables)	12 Months Ended
	Dec. 31, 2015
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Commodity derivative instruments	2016 2017 Settlement Settlement NATURAL GAS (MMBtu): Swaps Volume 298,957 - Price (NYMEX) $ 3.28 - 3-way collars Volume - 67,361 Ceiling sold price (call) (NYMEX) - $ 4.03 Floor purchased price (put) (NYMEX) - $ 3.50 Floor sold price (short put) (NYMEX) - $ 3.00 CRUDE OIL (Bbls): Put spread Volume 138,286 - Floor purchased price (put) (LLS) $ 62.27 - Floor sold price (short put) (LLS) $ 40.00 - 3-way collars Volume - 113,029 Ceiling sold price (call) (WTI) - $ 77.00 Floor purchased price (put) (WTI) - $ 60.00 Floor sold price (short put) (WTI) - $ 45.00
Fair value and balance sheet location of each classification of commodity derivative contracts	Fair value as of December 31, 2015 2014 Asset commodity derivatives: Current assets $ 3,069,115 $ 6,413,935 Noncurrent assets 1,841,120 3,163,891 4,910,235 9,577,826 Liability commodity derivatives: Current liabilities (411,068 ) (3,075,398 ) Noncurrent liabilities (770,579 ) (1,760,782 ) (1,181,647 ) (4,836,180 ) Total commodity derivative instruments $ 3,728,588 $ 4,741,646
Sales of natural gas and crude oil	Years Ended December 31, 2015 2014 2013 Sales of natural gas and crude oil $ 18,680,584 $ 38,659,392 $ 28,235,413 Gains (losses) realized from sale of commodity derivatives 4,030,000 - - Other gains (losses) realized on commodity derivatives 1,958,793 (1,420,217 ) (524 ) Unrealized gains (losses) on commodity derivatives (949,967 ) 4,724,985 (231,886 ) Amortized gains from benefit of sold qualified gas options - 93,750 72,600 Total revenue from natural gas and crude oil $ 23,719,410 $ 42,057,910 $ 28,075,603
Reconciliation of the components of accumulated other comprehensive income (loss)	Years Ended December 31, 2015 2014 2013 Before tax After tax Before tax After tax Before tax After tax Balance, beginning of period $ 63,091 $ 38,801 $ 63,041 $ 38,770 $ 437,140 $ 268,841 Sale of unexpired contracts previously subject to hedge accounting rules (119,917 ) (73,749 ) - - - - Other reclassifications due to expired contracts previously subject to hedge accounting rules 56,826 34,948 50 31 (374,099 ) (230,071 ) Balance, end of period $ - $ - $ 63,091 $ 38,801 $ 63,041 $ 38,770

PREFERRED STOCK (Tables)

PREFERRED STOCK (Tables)	12 Months Ended
	Dec. 31, 2015
PreferredStockAbstract
Shares and cash payments were issued to the existing preferred stockholders	June 30, 2013 December 31, 2013 June 30, 2014 Additional Additional Additional preferred Cash preferred Cash preferred Cash shares payments shares payments shares payments Series A Preferred Stock 403 $ 35,150 630 $ 45,360 893 $ 45,280 Series B Preferred Stock 533 $ 24,700 533 $ 40,690 536 $ 53,680
Amount of the preferred stock dividends paid	Series A Preferred Stock Dividends $ 214,903 Series B Preferred Stock Dividends 131,289 Total Dividends $ 346,192
Preferred stock dividends consist	December 31, 2014 December 31, 2013 Additional Additional preferred Dividends preferred Dividends shares in kind shares in kind Series A Preferred Stock 893 $ 3,299,603 1,033 $ 3,779,521 Series B Preferred Stock 536 $ 833,777 1,066 $ 1,632,760
Outstanding shares	Shares Shares Shares 2013 outstanding 2014 converted to outstanding Original stock December 31, stock common stock December 31, shares dividends 2013 dividends in 2014 2014 Series A Preferred Stock 14,605 1,033 15,638 893 (16,531 ) - Series B Preferred Stock 18,590 1,066 19,656 536 (20,192 ) -
Series A and Series B preferred stock were converted to common stock	Number Conversion Conversion of ratio to ratio to Number preferred Yuma Co. Company of shares common stock common stock shares Series A Preferred Stock 16,531 1.207101257 757.3374389993 15,112,295 Series B Preferred Stock 20,192 .508185000 757.3374389993 7,771,192

STOCK-BASED COMPENSATION (Table

STOCK-BASED COMPENSATION (Tables)	12 Months Ended
	Dec. 31, 2015
Summary of the Company's stock option activity, RSUs	Number of Weighted average unvested grant-date RSA shares fair value Unvested shares as of January 1, 2015 2,063,100 $3.40 per share Granted on March 12, 2015 73,194 $1.38 per share Granted on August 18, 2015 2,155,538 $0.61 per share Granted on September 30, 2015 75,000 $0.48 per share Granted on October 5, 2015 295,586 $0.50 per share Vested on January 25, 2015 (65,638 ) $3.14 per share Vested on April 1, 2015 (1,272,834 ) $3.16 per share Vested on May 1, 2015 (6,232 ) $2.39 per share Vested on May 20, 2015 (76,744 ) $3.96 per share Vested on July 14, 2015 (29,789 ) $3.89 per share Vested on October 15, 2015 (48,747 ) $2.74 per share Vested on November 1, 2015 (6,232 ) $2.39 per share Vested on November 30, 2015 (16,157 ) $3.88 per share Vested on December 31, 2015 (106,280 ) $3.88 per share Forfeited (690,392 ) $1.72 per share Unvested shares as of December 31, 2015 2,343,373 $0.98 per share
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, 2014 105,000 $ 5.17 2.65 $ - Granted - - - - Exercised - - - - Forfeited - - - - Outstanding at December 31, 2015 105,000 $ 5.17 2.65 $ - Vested at December 31, 2015 105,000 $ 5.17 2.65 $ - Exercisable at December 31, 2015 105,000 $ 5.17 2.65 $ -
Information about stock options outstanding and exercisable	Options Outstanding Options Exercisable Weighted- Weighted Weighted average average average Exercise Number of remaining exercise Number of exercise price shares life (years) price shares price $ 5.40 5,000 0.10 $ 5.40 5,000 $ 5.40 $ 5.16 100,000 2.77 $ 5.16 100,000 $ 5.16 105,000 105,000
Summary of the status of the unvested RSUs	Weighted Number of average unvested grant-date RSUs fair value Unvested shares as of January 1, 2015 95,424 $2.72 per share Forfeited (15,146 ) $2.72 per share Unvested shares as of December 31, 2015 80,278 $2.72 per share
Stock Appreciation Rights (RSAs) [Member]
Summary of the Company's stock option activity, RSUs	Number of unvested Weighted average RSA shares fair value Unvested shares as of January 1, 2015 - Granted November 30, 2015 45,297 $0.19 per share Granted December 15, 2015 173,224 $0.19 per share Vested on December 31, 2015 (47,460 ) $0.19 per share Unvested shares as of December 31, 2015 171,061 $0.19 per share
Stock Appreciation Rights (SARs) [Member]
Summary of the Company's stock option activity, RSUs	Stock Appreciation Rights – Weighted Number of average unvested grant-date SARs fair value Unvested shares as of January 1, 2015 - Granted on August 18, 2015 2,159,855 $0.318 per share Forfeited (371,155 ) $0.318 per share Unvested shares as of December 31, 2015 1,788,700 $0.318 per share Below is a summary of the SARs and changes for the year to date ended December 31, 2015 for consultants. Number of Weighted unvested average SARs fair value Unvested shares as of January 1, 2015 - Granted on November 30, 2015 19,080 $0.036 per share Granted on December 15, 2015 104,639 $0.036 per share Unvested shares as of December 31, 2015 123,719 $0.036 per share

EARNINGS PER COMMON SHARE (Tabl

EARNINGS PER COMMON SHARE (Tables)	12 Months Ended
	Dec. 31, 2015
EARNINGS (LOSS) PER COMMON SHARE:
Potentially dilutive securities for the computation of diluted weighted average number of shares	Years Ended December 31, 2014 2015 2014 2013 Restricted Stock Awards 1,786,812 2,280,137 1,334,452 Stock Appreciation Rights 791,675 - - Restricted Stock Units 93,733 105,643 91,762 Series A Preferred Stock - 10,031,104 12,964,860 Series B Preferred Stock - 5,263,585 7,259,079 2,672,220 17,680,469 21,650,153

DEBT AND INTEREST EXPENS (Table

DEBT AND INTEREST EXPENS (Tables)	12 Months Ended
	Dec. 31, 2015
Debt And Interest Expens Tables
Long term Debt	December 31, December 31, 2015 2014 Variable rate revolving credit agreement payable to Société Générale, CIT Bank, NAC, and LegacyTexas Bank, maturing May 20, 2017, secured by the stock of Exploration and its interest in POL, and guaranteed by The Yuma Companies, Inc. $ 29,800,000 $ 22,900,000 Installment loan due February 29, 2016, originating from the financing of insurance premiums at 3.74% interest rate. 108,894 - Installment loan due June 11, 2016, originating from the financing of insurance premiums at 3.76% interest rate. 154,741 - Installment loan due June 11, 2015, originating from the financing of insurance premiums at 3.76% interest rate. - 154,750 Installment loan due February 28, 2015, originating from the financing of insurance premiums at 3.65% interest rate. - 128,093 30,063,635 23,182,843 Less: current portion (30,063,635 ) (282,843 ) Total long-term debt $ - $ 22,900,000
Prime and LIBOR base rates	Borrowing base utilization Prime margin LIBOR margin Utilization > 90% 2.25 % 3.25 % 75% < utilization < 90% 2.00 % 3.00 % 50% < utilization < 75% 1.75 % 2.75 % 25% < utilization < 50% 1.50 % 2.50 % Utilization < 25% 1.25 % 2.25 %
Summarizes interest expense	Years Ended December 31, 2015 2014 2013 Credit facility $ 1,104,231 $ 1,109,153 $ 1,010,539 Credit facility commitment fees 34,512 70,813 56,092 Amortization and write offs of credit facility loan costs 286,009 188,669 480,261 Insurance installment loan 13,654 13,640 16,161 Louisiana Mineral Board - - 32,383 Other interest charges 1,489 3,275 4,056 Capitalized interest (983,472 ) (1,059,350 ) (1,031,816 ) Total interest expense $ 456,423 $ 326,200 $ 567,676
Aggregate principal payments	2016 $ 30,063,635 * 2017 - 2018 - 2019 - 2020 -

MERGER WITH PYRAMID OIL COMPA45

MERGER WITH PYRAMID OIL COMPANY AND GOODWILL (Tables)	12 Months Ended
	Dec. 31, 2014
Business Combinations [Abstract]
Purchase price allocation	September 10, 2014 (as initially Measurement period (i) September 10, 2014 Purchase Price(i): Shares of Pyramid common stock held by Pyramid shareholders 4,788,085 - 4,788,085 Pyramid common stock price (September 10, 2014 closing price) $ 4.70 $ - $ 4.70 Fair value of Pyramid common stock issued $ 22,504,000 $ - $ 22,504,000 Consideration paid to Pyramid’s shareholders - - - Issuance of 100,000 shares to Pyramid affiliated persons at $5.01 per share (September 11, 2014 closing price) 501,000 - 501,000 Fair value of Pyramid options assumed by the Company (ii) 100,500 - 100,500 Total purchase price 23,105,500 - 23,105,500 Estimated Fair Value of Liabilities Assumed: Current liabilities 633,917 - 633,917 Noncurrent deferred tax liability (iii) 4,879,724 - 4,879,724 Other noncurrent liabilities (asset retirement obligation) 1,334,278 (390,327 ) 943,951 Amount attributable to liabilities assumed 6,847,919 (390,327 ) 6,457,592 Total purchase price plus liabilities assumed 29,953,419 (390,327 ) 29,563,092 Estimated Fair Value of Assets Acquired: Current assets 9,066,589 - 9,066,589 Oil and natural gas properties (iv) 10,726,715 - 10,726,715 Net other property and equipment 4,158,420 - 4,158,420 Other noncurrent assets 261,380 - 261,380 Amount attributable to assets acquired 24,213,104 - 24,213,104 Goodwill (i) $ 5,740,315 $ (390,327 ) $ 5,349,988
Pro forma financial information	Years Ended December 31, 2014 2013 Revenues $ 46,238,208 $ 33,534,396 Net income (loss) $ (3,388,094 ) $ (7,834,907 ) Net income (loss) per share: Basic $ (.07 ) $ (.19 ) Diluted $ (.07 ) $ (.19 )

INCOME TAXES (Tables)

INCOME TAXES (Tables)	12 Months Ended
	Dec. 31, 2015
Income Tax Disclosure [Abstract]
Provisions for income taxes	Years Ended December 31, 2015 2014 2013 Current income taxes (benefit): Federal $ (29,226 ) $ - $ - State (1,963 ) - - Total (31,189 ) - - Deferred income taxes (benefit): Federal (7,227,361 ) (2,377,192 ) 2,705,688 State (724,489 ) (176,662 ) 374,584 Total (7,951,850 ) (2,553,854 ) 3,080,272 Total taxes (benefit) on income $ (7,983,039 ) $ (2,553,854 ) $ 3,080,272
Deferred tax liabilities (assets)	Years Ended December 31, 2015 2014 Deferred tax liability (hedges) $ - $ 1,843,409 Deferred tax liability from excess of book basis over tax basis of certain assets including property, plant and equipment 30,009,264 30,081,226 Deferred tax liability 30,009,264 31,924,635 Stock-based compensation (608,442 ) (1,205,722 ) Alternative minimum tax credit carryforwards (121,686 ) (121,686 ) Net operating loss (“NOL”) carryforwards (22,481,966 ) (15,585,820 ) Other deferred tax (asset) - (396,668 ) Deferred tax asset (23,212,094 ) (17,309,896 ) Net deferred tax liability $ 6,797,170 $ 14,614,739
Tax credit carryforwards and stock based compensation generated by the consolidated group	Year NOL NOL Year of generated remaining expiration 2015 $ 14,926,752 2035 2014 14,943,985 2034 2013 9,417,693 2033 2012 8,082,421 2032 2011 5,511,938 2031 2009 4,844,318 2029 2007 1,095,474 2027 2002 3,050,662 2022 Total $ 61,873,243
Income taxes	Years Ended December 31, 2015 2014 2013 Amount computed using the statutory rate $ (6,645,827 ) $ (7,972,651 ) $ (10,489,441 ) Increase (reduction) in taxes resulting from: Non-deductible change in value of preferred stock derivative liability - 5,486,895 9,190,496 State taxes (726,452 ) (210,021 ) 254,645 Other (610,760 ) 141,923 4,124,572 Income tax expense (benefit) $ (7,983,039 ) $ (2,553,854 ) $ 3,080,272

OTHER DISCLOSURES (Tables)

OTHER DISCLOSURES (Tables)	12 Months Ended
	Dec. 31, 2015
Other Disclosures
Other Operating Expenses	December 31, 2015 2014 2013 Bad debt expense $ 839,171 $ 97,068 $ 193,601 Recovery of bad debts (342,944 ) (1,984 ) (2,520 ) Loss (gain) on disposal of property (28,006 ) 3,392 (19,307 ) Total $ 468,221 $ 98,476 $ 171,774
Other Non-operating Income (Expense)	December 31, 2015 2014 2013 Interest income $ 19,587 $ 23,632 $ 7,336 Rental income 16,000 - - Bank-mandated derivative instruments novation cost - - (175,000 ) Louisiana sales tax settlement - - (44,149 ) Louisiana Mineral Board audit - - (23,686 ) Other 751 1,746 (5,118 ) Total $ 36,338 $ 25,378 $ (240,617 )
Other Receivables	December 31, 2015 2014 December 2015 and December 2014 settled oil derivative instruments $ 257,286 $ 407,003 Tax refund 177,157 158,571 Debit balances for trade payables 109,586 187,031 Refund from PPI for duplicate charges 89,544 89,544 D&O insurance premium adjustment - 16,356 Other - (1,943 ) Total $ 633,573 $ 856,562
Prepayments	December 31, 2015 2014 Insurance $ 570,379 $ 536,410 Taxes and fees 39,687 21,882 Property taxes 41,583 56,992 Other subscriptions 16,508 6,355 Software maintenance agreements 14,572 19,105 Geological well database subscription 8,883 19,055 Software licenses 2,065 44,172 Exploration and drilling costs - 71,893 Services - 4,530 Other 10,846 1,840 Total $ 704,523 $ 782,234
Other Current Deferred Charges	December 31, 2015 2014 Loan fees $ 415,740 $ 189,409 Deferred premium on 2015 oil derivative instruments - 153,389 Total $ 415,740 $ 342,798
Other Noncurrent Assets	December 31, 2015 2014 Deferred offering costs $ 38,104 $ - Loan fees - 262,200 Total $ 38,104 $ 262,200
Other Accrued Liabilities	December 31, 2015 2014 Employee termination benefits $ 422,037 $ - Salaries and bonuses 393,072 479,537 Accounting and audit 202,297 22,964 Severance taxes 157,941 164,374 Ad valorem taxes 143,957 172,444 Vacation 138,962 166,660 Sales and use tax 85,076 81,661 Insurance 67,532 119,121 Fees for commodity hedging advisor 64,953 48,590 Interest expense 39,471 9,327 Financing cost 35,000 - Employee restricted stock unit awards 13,981 - Commodity hedge settlement - 153,389 Other 17,205 1,498 Total $ 1,781,484 $ 1,419,565

LEASES (Tables)

LEASES (Tables)	12 Months Ended
	Dec. 31, 2015
Leases [Abstract]
Future minimum rentals under all noncancellable leases	2016 579,873 2017 564,326 2018 2,264 2019 - 2020 -

AT MARKET SECURITY SALES (Table

AT MARKET SECURITY SALES (Tables)	12 Months Ended
	Dec. 31, 2015
Marketable Securities [Abstract]
Sales of Securities	Shares Net Proceeds Common Stock 1,347,458 $ 1,363,160 Series A Preferred Stock 46,857 870,386 Total $ 2,233,546

SUPPLEMENTARY INFORMATION ON 50

SUPPLEMENTARY INFORMATION ON OIL AND NATURAL GAS EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES (UNAUDITED) (Tables)	12 Months Ended
	Dec. 31, 2015
Costs Incurred	December 31, 2015 2014 2013 Property acquisition costs - unproved $ (9,635,309 ) $ 1,105,782 $ 3,865,932 Property acquisition costs - proved 7,587,965 3,349,473 8,539,134 Sales proceeds - unproved (30,442 ) (359,667 ) (679,266 ) Sales proceeds - proved - (307,600 ) (718,000 ) Exploration costs 3,217,161 426,909 2,504,087 Development costs 1,121,654 20,139,409 11,910,179 Capitalized asset retirements costs 4,301,810 241,629 5,795,400 Total costs incurred $ 6,562,839 $ 24,595,935 $ 31,217,466
Capitalized Costs Relating to Oil and Gas Producing Activities	December 31, 2015 2014 Oil and gas properties, full cost method: Not subject to amortization: Prospect inventory $ 7,719,857 $ 14,913,126 Property acquisition costs - unproved 6,150,862 8,623,344 Well development costs - unproved 417,997 2,170,582 Subject to amortization: Property acquisition costs - proved 58,393,861 50,744,401 Well development costs - proved 81,063,335 74,440,227 Capitalized costs - unsuccessful 60,549,824 52,539,407 Capitalized asset retirement costs 4,505,018 8,806,828 Total capitalized costs 218,800,754 212,237,915 Less accumulated depreciation, depletion and amortization (117,304,945 ) (103,929,493 ) Net capitalized costs $ 101,495,809 $ 108,308,422
Discounted future net cash flows	December 31, 2015 2014 2013 Future cash inflows $ 438,816,500 $ 1,339,372,300 $ 1,450,469,000 Future oil and natural gas operating expenses (129,636,500 ) (322,298,300 ) (334,883,800 ) Future development costs (126,463,700 ) (405,900,900 ) (424,256,900 ) Future income tax expenses (23,334,886 ) (133,467,940 ) (163,704,120 ) Future net cash flows 159,381,414 477,705,160 527,624,180 10% annual discount for estimating timing of cash flows (53,318,652 ) (183,249,968 ) (202,270,201 ) Standardized measure of discounted future net cash flows $ 106,062,762 $ 294,455,192 $ 325,353,979
Change in Standardized Measure	2015 2014 2013 Changes due to current year operation: Sales of oil and natural gas, net of oil and natural gas operating expenses $ (7,069,544 ) $ (25,270,455 ) $ (17,255,824 ) Extensions and discoveries 16,660 2,743,800 37,750,617 Purchases of oil and gas properties 2,268,907 12,827,533 215,427,459 Development costs incurred during the period that reduced future development costs 4,052,919 9,178,400 100,500 Changes due to revisions in standardized variables: Prices and operating expenses (373,506,778 ) (42,125,763 ) (30,773,529 ) Income taxes 65,424,175 19,303,313 (38,340,467 ) Estimated future development costs 245,056,050 7,218,529 32,430,504 Quantity estimates (80,454,131 ) (21,028,476 ) (107,070,514 ) Sale of reserves in place - - - Accretion of discount 37,672,481 43,124,820 27,910,664 Production rates, timing and other (81,853,169 ) (36,870,488 ) (6,378,317 ) Net change (188,392,430 ) (30,898,787 ) 113,801,093 Beginning of year 294,455,192 325,353,979 211,552,886 End of year $ 106,062,762 $ 294,455,192 $ 325,353,979
Barrels of oil and condensate [Member]
Reserve	2015 2014 2013 Barrels of oil and condensate: Proved developed and undeveloped reserves: Beginning of year 14,011,343 14,381,960 7,739,964 Revisions of previous estimates (5,596,379 ) (565,143 ) (1,142,654 ) Purchases of oil and gas properties 103,387 472,132 7,959,600 Extensions and discoveries 769,661 51,993 92,152 Sale of oil and gas properties - - - Production (321,687 ) (329,599 ) (267,102 ) End of year 8,966,325 14,011,343 14,381,960 Proved developed reserves - January 1, 2,347,482 2,099,701 1,474,015 Proved developed reserves - December 31, 2,117,559 2,347,482 2,099,701 Proved undeveloped reserves - January 1, 11,663,861 12,282,259 6,265,949 Proved undeveloped reserves - December 31, 6,848,766 11,663,861 12,282,259
Thousands of cubic feet of natural gas [Member]
Reserve	2015 2014 2013 Thousands of cubic feet of natural gas: Proved developed and undeveloped reserves: Beginning of year 35,259,522 38,372,369 31,071,137 Revisions of previous estimates (11,436,325 ) (479,438 ) (8,281,139 ) Purchases of oil and gas properties 264,981 81,177 16,495,803 Extensions and discoveries 3,675,358 - 362,806 Sale of oil and gas properties - - - Production (1,993,842 ) (2,714,586 ) (1,276,238 ) End of year 25,769,694 35,259,522 38,372,369 Proved developed reserves - January 1, 7,786,537 10,316,516 10,156,754 Proved developed reserves - December 31, 8,552,249 7,786,537 10,316,516 Proved undeveloped reserves - January 1, 27,472,985 28,055,853 20,914,383 Proved undeveloped reserves - December 31, 17,217,445 27,472,985 28,055,853

SUMMARY OF SIGNIFICANT ACCOUN51

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details)	12 Months Ended
	Dec. 31, 2015USD ($)
Leasehold acquisition cost	$ 12,066,152
Exploration and development cost	383,690
Capitalized interest	1,827,669
Total	14,277,511
2015 [Member]
Leasehold acquisition cost	(9,039,268)
Exploration and development cost	(1,739,341)
Capitalized interest	(639,726)
Total	(11,418,335)
2014 [Member]
Leasehold acquisition cost	154,194
Exploration and development cost	891,610
Capitalized interest	609,970
Total	1,655,774
2013 [Member]
Leasehold acquisition cost	1,704,190
Exploration and development cost	1,059,262
Capitalized interest	829,456
Total	3,592,908
Prior Year [Member]
Leasehold acquisition cost	19,247,036
Exploration and development cost	172,159
Capitalized interest	1,027,969
Total	$ 20,447,164

SUMMARY OF SIGNIFICANT ACCOUN52

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details 1) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Land	$ 2,469,000	$ 2,469,000
Office business machines	1,381,968	1,361,149
Drilling and operating equipment	982,010	982,010
Furniture and fixtures	412,215	412,215
Automotive	351,707	351,707
Office leasehold improvements	332,607	332,607
Buildings and improvements	326,000	326,000
Total other property and equipment	6,255,507	6,234,688
Less: Accumulated depreciation and leasehold improvement amortization	(2,174,316)	(1,909,352)
Net book value	$ 4,081,191	$ 4,325,336
Office business machines [Member] | Minimum [Member]
Estimated useful life in years	3 years
Office business machines [Member] | Maximum [Member]
Estimated useful life in years	5 years
Drilling and operating equipment [Member]
Estimated useful life in years	14 years
Furniture and fixtures [Member]
Estimated useful life in years	7 years
Automotive [Member]
Estimated useful life in years	5 years
Office leasehold improvements [Member]
Estimated useful life in years	5 years
Buildings and improvements [Member] | Minimum [Member]
Estimated useful life in years	3 years
Buildings and improvements [Member] | Maximum [Member]
Estimated useful life in years	25 years

SUMMARY OF SIGNIFICANT ACCOUN53

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details 2) - USD ($)	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Accounting Policies [Abstract]
Production and severance tax	$ 1,678,825	$ 2,693,396	$ 2,403,263
Ad valorem tax	1,103,913	1,046,134	732,302
Sales tax	18,534	62,864	180,498
State franchise taxes	68,248	40,740	41,072
Total	$ 2,869,520	$ 3,843,134	$ 3,357,135

SUMMARY OF SIGNIFICANT ACCOUN54

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details Textual)	12 Months Ended
	Dec. 31, 2015USD ($)$ / Unit	Dec. 31, 2014USD ($)$ / Unit	Dec. 31, 2013USD ($)$ / Unit
Summary Of Significant Accounting Policies Details Textual
Allowance for doubtful accounts	$ 532,719	$ 138,960
Depreciation, depletion and amortization rate per boe | $ / Unit	20.45	24.92	23.87
Depreciation, depletion and amortization expense for oil and natural gas properties	$ 13,375,452	$ 19,490,653	$ 11,927,872
Capitalized interest associated with line of credit	983,472	1,059,350	1,031,816
Capitalized internal costs	3,090,013	3,442,095	2,702,952
General and administrative expense reimbursements	0	0	42,329
Depreciation and leasehold improvement amortization expense	$ 275,756	$ 174,338	$ 149,496

ORGANIZATION AND CONSOLIDATION

ORGANIZATION AND CONSOLIDATION (Details)	12 Months Ended
	Dec. 31, 2015
The Yuma Companies, Inc. [Member]
Company name	The Yuma Companies, Inc.
Reference	“YCI”
State of incorporation	Delaware
Date of incorporation	Oct. 30, 1996
Yuma Exploration and Production Company, Inc. [Member]
Company name	Yuma Exploration and Production Company, Inc.
Reference	“Exploration”
State of incorporation	Delaware
Date of incorporation	Jan. 16, 1992
Yuma Petroleum Company [Member]
Company name	Yuma Petroleum Company
Reference	“Petroleum”
State of incorporation	Delaware
Date of incorporation	Dec. 19, 1991
Texas Southeastern Gas Marketing Company [Member]
Company name	Texas Southeastern Gas Marketing Company
Reference	“TSM”
State of incorporation	Texas
Date of incorporation	Sep. 12, 1996
Pyramid Oil LLC [Member]
Company name	Pyramid Oil LLC
Reference	“POL”
State of incorporation	California
Date of incorporation	Aug. 8, 2014
Pyramid Delaware Merger Subsidiary, Inc. [Member]
Company name	Pyramid Delaware Merger Subsidiary, Inc.
Reference	“PDMS”
State of incorporation	Delaware
Date of incorporation	Feb. 4, 2014

ASSET RETIREMENT OBLIGATIONS (D

ASSET RETIREMENT OBLIGATIONS (Details) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Asset Retirement Obligation Disclosure [Abstract]
Beginning of year balance	$ 12,487,770	$ 10,697,679
Pyramid liabilities assumed in the merger		943,951
Liabilities incurred during year	$ 24,588	$ 416,162
Liabilities settled during year	(35,455)
Accretion expense	604,538	$ 604,511	$ 668,497
Revisions in estimated cash flows	(4,290,943)	(174,533)
End of year balance	$ 8,790,498	$ 12,487,770	$ 10,697,679

ASSET RETIREMENT OBLIGATIONS 57

ASSET RETIREMENT OBLIGATIONS (Details Narrative)	12 Months Ended
	Dec. 31, 2015USD ($)
Asset Retirement Obligation Disclosure [Abstract]
Decrease ARO estimate	$ 3,697,272

RECEIVABLES AND PAYABLES WITH58

RECEIVABLES AND PAYABLES WITH AFFILIATES, CHIEF EXECUTIVE OFFICER AND EMPLOYEES (Details) - USD ($)	Dec. 31, 2015	Dec. 31, 2014
Current	$ 75,404	$ 316,077
Yuma CEO [Member]
Current	63,329	174,720
Employee [Member]
Current	$ 12,075	$ 141,357

RELATED PARTY TRANSACTIONS (Det

RELATED PARTY TRANSACTIONS (Details)	12 Months Ended
	Dec. 31, 2015USD ($)
Anaconda Prospect [Member]
Working interest	1.95%
Amount paid	$ 16,900
Gardner Island Well [Member]
Working interest	1.436%
Main Pass 4 Facility [Member]
Working interest	1.855%
Amount paid	$ 78,988
Austin Chalk (Additional W.I) [Member]
Working interest	1.00%
Amount paid	$ 16,000
Bell City East Prospect [Member]
Working interest	0.71063%
Amount paid	$ 5,330
Austin Chalk [Member]
Working interest	1.00%
Amount paid	$ 9,412
Addison Acquisition [Member]
Working interest	2.00%
Amount paid	$ 150,000

FAIR VALUE MEASUREMENTS (Detail

FAIR VALUE MEASUREMENTS (Details) - USD ($)	Dec. 31, 2015	Dec. 31, 2014
Total assets	$ 3,728,588	$ 4,741,646
Commodity derivatives oil
Total assets	3,442,693	2,858,387
Commodity derivatives gas
Total assets	$ 285,895	$ 1,883,259
Level 1
Total assets
Level 1 | Commodity derivatives oil
Total assets
Level 1 | Commodity derivatives gas
Total assets
Level 2
Total assets	$ 3,728,588	$ 4,741,646
Level 2 | Commodity derivatives oil
Total assets	3,442,693	2,858,387
Level 2 | Commodity derivatives gas
Total assets	$ 285,895	$ 1,883,259
Level 3
Total assets
Level 3 | Commodity derivatives oil
Total assets
Level 3 | Commodity derivatives gas
Total assets

COMMODITY DERIVATIVE INSTRUME61

COMMODITY DERIVATIVE INSTRUMENTS (Details) - USD ($)	Dec. 31, 2015	Dec. 31, 2014
Asset commodity derivatives:
Current assets	$ 3,069,115	$ 6,413,935
Noncurrent assets	1,841,120	3,163,891
Total	4,910,235	9,577,826
Liability commodity derivatives:
Current liabilities	(411,068)	(3,075,398)
Noncurrent liabilities	(770,579)	(1,760,782)
Total	(1,181,647)	(4,836,180)
Total commodity derivative instruments	$ 3,728,588	$ 4,741,646

COMMODITY DERIVATIVE INSTRUME62

COMMODITY DERIVATIVE INSTRUMENTS (Details 1) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
C. Commodity Derivative Instruments Details 1
Sales of natural gas and crude oil	$ 18,680,584	$ 38,659,392	$ 28,235,413
Gains (losses) realized from sale of commodity derivatives	4,030,000
Other gains (losses) realized on commodity derivatives	1,958,793	$ (1,420,217)	$ (524)
Unrealized gains (losses) on commodity derivatives	$ (949,967)	4,724,985	(231,886)
Amortized gains from benefit of sold qualified gas options		93,750	72,600
Total revenue from natural gas and crude oil	$ 23,719,410	$ 42,057,910	$ 28,075,603

COMMODITY DERIVATIVE INSTRUME63

COMMODITY DERIVATIVE INSTRUMENTS (Details 2) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Balance, beginning of period, before tax	$ 63,091	$ 63,041	$ 437,140
Balance, beginning of period, after tax	38,801	$ 38,770	$ 268,841
Sale of unexpired contracts previously subject to hedge accounting rules, before tax	(119,917)
Sale of unexpired contracts previously subject to hedge accounting rules, after tax	(73,749)
Other reclassifications due to expired contracts previously subject to hedge accounting rules, before tax	56,826	$ 50	$ (374,099)
Other reclassifications due to expired contracts previously subject to hedge accounting rules, after tax	$ 34,948	31	(230,071)
Balance, end of period, before tax		63,091	63,041
Balance, end of period, after tax		$ 38,801	$ 38,770

PREFERRED STOCK (Details)

PREFERRED STOCK (Details) - USD ($)	Jun. 30, 2014	Dec. 31, 2013	Jun. 30, 2013
Series A Preferred Stock [Member]
Additional preferred shares	893	630	403
Cash payments	$ 45,280	$ 45,360	$ 35,150
Series B Preferred Stock [Member]
Additional preferred shares	536	533	533
Cash payments	$ 53,680	$ 40,690	$ 24,700

PREFERRED STOCK (Details 1)

PREFERRED STOCK (Details 1)	Sep. 15, 2014USD ($)
Dividends	$ 346,192
Series A Preferred Stock [Member]
Dividends	214,903
Series B Preferred Stock [Member]
Dividends	$ 131,289

PREFERRED STOCK (Details 2)

PREFERRED STOCK (Details 2) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Dividends paid in kind (Series A and Series B)		$ 4,133,380	$ 5,412,281
Series A Preferred Stock [Member]
Additional preferred shares		893	1,033
Dividends paid in kind (Series A and Series B)		$ 3,299,603	$ 3,779,521
Series B Preferred Stock [Member]
Additional preferred shares		536	1,066
Dividends paid in kind (Series A and Series B)		$ 833,777	$ 1,632,760

PREFERRED STOCK (Details 3)

PREFERRED STOCK (Details 3) - shares	Dec. 31, 2014	Dec. 31, 2013
Series A Preferred Stock [Member]
Original shares		14,605
Stock dividends	893	1,033
Shares converted to common stock	(16,531)
Shares outstanding	0	15,638
Series B Preferred Stock [Member]
Original shares		18,590
Stock dividends	536	1,066
Shares converted to common stock	(20,192)
Shares outstanding		19,656

PREFERRED STOCK (Details 4)

PREFERRED STOCK (Details 4)	12 Months Ended
	Dec. 31, 2015shares
Series A Preferred Stock [Member]
Number of preferred shares	16,531
Conversion ratio to Yuma Co. common stock	1.207101257
Conversion ratio to Company common stock	757.3374389993
Number of shares	15,112,295
Series B Preferred Stock [Member]
Number of preferred shares	20,192
Conversion ratio to Yuma Co. common stock	.508185000
Conversion ratio to Company common stock	757.3374389993
Number of shares	7,771,192

PREFERRED STOCK (Details Narrat

PREFERRED STOCK (Details Narrative) - USD ($)	Dec. 31, 2014	Dec. 31, 2013
PreferredStockAbstract
Fair value of derivative	$ 4,133,380	$ 5,412,281

STOCK-BASED COMPENSATION (Detai

STOCK-BASED COMPENSATION (Details) - RSA	12 Months Ended
	Dec. 31, 2015$ / sharesshares
Number of unvested RSA shares
Unvested shares as of January 1, 2015 | shares	2,063,100
Granted on March 12, 2015 | shares	73,194
Granted on August 18, 2015 | shares	2,155,538
Granted on September 30, 2015 | shares	75,000
Granted on October 5, 2015 | shares	295,586
Vested on January 25, 2015 | shares	(65,638)
Vested on April 1, 2015 | shares	(1,272,834)
Vested on May 1, 2015 | shares	(6,232)
Vested on May 20, 2015 | shares	(76,744)
Vested on July 14, 2015 | shares	(29,789)
Vested on October 15, 2015 | shares	(48,747)
Vested on November 1, 2015 | shares	(6,232)
Vested on November 30, 2015 | shares	(16,157)
Vested on December 31, 2015 | shares	(106,280)
Forfeited | shares	(690,392)
Unvested shares as of December 31, 2015 | shares	2,343,373
Weighted Average Grant-Date Fair Value
Unvested per shares as of January 1, 2015 | $ / shares	$ 3.40
Granted on March 12, 2015 | $ / shares	1.38
Granted on August 18, 2015 | $ / shares	0.61
Granted on September 30, 2015 | $ / shares	0.48
Granted on October 5, 2015 | $ / shares	0.50
Vested on January 25, 2015 | $ / shares	3.14
Vested on April 1, 2015 | $ / shares	3.16
Vested on May 1, 2015 | $ / shares	2.39
Vested on May 20, 2015 | $ / shares	3.96
Vested on July 14, 2015 | $ / shares	3.89
Vested on October 15, 2015 | $ / shares	2.74
Vested on November 1, 2015 | $ / shares	2.39
Vested on November 30, 2015 | $ / shares	3.88
Vested on December 31, 2015 | $ / shares	3.88
Forfeited | $ / shares	1.72
Unvested per shares as of December 31, 2015 | $ / shares	$ 0.98

STOCK-BASED COMPENSATION (Det71

STOCK-BASED COMPENSATION (Details 1) - RSA	12 Months Ended
	Dec. 31, 2015$ / sharesshares
Number of unvested RSA shares
Unvested shares as of January 1, 2015 | shares	2,063,100
Vested on December 31, 2015 | shares	(106,280)
Unvested shares as of December 31, 2015 | shares	2,343,373
Weighted Average Grant-Date Fair Value
Unvested per shares as of January 1, 2015 | $ / shares	$ 3.40
Vested on December 31, 2015 | $ / shares	3.88
Unvested per shares as of December 31, 2015 | $ / shares	$ 0.98
Consultant [Member]
Number of unvested RSA shares
Unvested shares as of January 1, 2015 | shares	0
Granted November 30, 2015 | shares	45,297
Granted December 15, 2015 | shares	173,224
Vested on December 31, 2015 | shares	(47,460)
Unvested shares as of December 31, 2015 | shares	171,061
Weighted Average Grant-Date Fair Value
Unvested per shares as of January 1, 2015 | $ / shares	$ 0
Granted November 30, 2015 | $ / shares	0.19
Granted December 15, 2015 | $ / shares	0.19
Vested on December 31, 2015 | $ / shares	0.19
Unvested per shares as of December 31, 2015 | $ / shares	$ 0.19

STOCK-BASED COMPENSATION (Det72

STOCK-BASED COMPENSATION (Details 2) - Stock Appreciation Rights (SARs) [Member]	12 Months Ended
	Dec. 31, 2015$ / sharesshares
Employees [Member]
Number of unvested SAR shares
Unvested shares as of January 1, 2015 | shares	0
Granted on August 18, 2015 | shares	2,159,855
Forfeited | shares	(371,155)
Unvested shares as of December 31, 2015 | shares	1,788,700
Weighted Average Grant-Date Fair Value
Unvested per shares as of January 1, 2015 | $ / shares	$ 0
Granted on August 18, 2015 | $ / shares	0.318
Forfeited | $ / shares	0.318
Unvested per shares as of December 31, 2015 | $ / shares	$ 0.318
Consultant [Member]
Number of unvested SAR shares
Unvested shares as of January 1, 2015 | shares	0
Granted November 30, 2015 | shares	19,080
Granted December 15, 2015 | shares	104,639
Unvested shares as of December 31, 2015 | shares	123,719
Weighted Average Grant-Date Fair Value
Unvested per shares as of January 1, 2015 | $ / shares	$ 0
Granted November 30, 2015 | $ / shares	0.036
Granted December 15, 2015 | $ / shares	0.036
Unvested per shares as of December 31, 2015 | $ / shares	$ 0.036

STOCK-BASED COMPENSATION (Det73

STOCK-BASED COMPENSATION (Details 3) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Number of Options Outstanding, Beginning	105,000
Number of Options Granted	0
Number of Options Exercised	0
Number of Options Forfeited	0
Number of Options Outstanding, Ending	105,000	105,000
Vested and expected to vest December 31, 2015	105,000
Number of shares Options Exercisable	105,000
Weighted Average Exercise Price Outstanding	$ 5.17
Weighted Average Exercise Price Outstanding	5.17	$ 5.17
Weighted Average Exercise Price Vested and expected to vest December 31, 2015	5.17
Weighted Average Exercise Price Exercisable	$ 5.17
Weighted Average Remaining Contractual Life (in years) Outstanding	2 years 7 months 24 days	2 years 7 months 24 days
Weighted Average Remaining Contractual Life (in years) Vested and expected to vest at	2 years 7 months 24 days
Weighted Average Remaining Contractual Life (in years) Exercisable	2 years 7 months 24 days
Aggregate Intrinsic Value Outstanding, Beginning	$ 0
Aggregate Intrinsic Value Outstanding, Ending	0	$ 0
Aggregate Intrinsic Value Vested and expected to vest at	$ 0

STOCK-BASED COMPENSATION (Det74

STOCK-BASED COMPENSATION (Details 4) - $ / shares	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Number of Options Outstanding, Ending	105,000	105,000
Weighted average remaining life (years) Options Outstanding	2 years 7 months 24 days	2 years 7 months 24 days
Weighted Average Exercise Price Outstanding	$ 5.17	$ 5.17
Number of shares Options Exercisable	105,000
Weighted Average Exercise Price Exercisable	$ 5.17
Exercise Price 5.40 [Member]
Number of Options Outstanding, Ending	5,000
Weighted average remaining life (years) Options Outstanding	1 month 6 days
Weighted Average Exercise Price Outstanding	$ 5.40
Number of shares Options Exercisable	5,000
Weighted Average Exercise Price Exercisable	$ 5.40
Exercise Price 5.16 [Member]
Number of Options Outstanding, Ending	100,000
Weighted average remaining life (years) Options Outstanding	2 years 9 months 7 days
Weighted Average Exercise Price Outstanding	$ 5.16
Number of shares Options Exercisable	100,000
Weighted Average Exercise Price Exercisable	$ 5.16

STOCK-BASED COMPENSATION (Det75

STOCK-BASED COMPENSATION (Details 5) - RSUs	12 Months Ended
	Dec. 31, 2015$ / sharesshares
Number of unvested RSU shares
Unvested shares as of January 1, 2015 | shares	95,424
Forfeited | shares	(15,146)
Unvested shares as of December 31, 2015 | shares	80,278
Weighted Average Grant-Date Fair Value
Unvested per shares as of January 1, 2015 | $ / shares	$ 2.72
Forfeited | $ / shares	2.72
Unvested per shares as of December 31, 2015 | $ / shares	$ 2.72

STOCK-BASED COMPENSATION (Det76

STOCK-BASED COMPENSATION (Details Narrative) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Unrecognized SAR compensation cost	$ 1,247,595
Weighted average remaining service period	2 years 7 months 24 days	2 years 7 months 24 days
RSA, Weighted average assumptions used to estimate fair value expected life	1 year 4 months 22 days
SAR, Weighted average assumptions used to estimate fair value volatility	61.17%
SAR, Weighted average assumptions used to estimate fair value risk-free rate	1.60%
Stock Appreciation Rights (SARs) [Member]
Unrecognized SAR compensation cost	$ 418,039
Weighted average remaining service period	1 year 6 months

EARNINGS PER COMMON SHARE (Deta

EARNINGS PER COMMON SHARE (Details) - shares	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
EARNINGS (LOSS) PER COMMON SHARE:
Restricted Stock Awards	1,786,812	2,280,137	1,334,452
Stock Appreciation Rights	791,675	0	0
Restricted Stock Units	93,733	105,643	91,762
Series A Preferred Stock	0	10,031,104	12,964,860
Series B Preferred Stock	0	5,263,585	7,259,079
Total	2,672,220	17,680,469	21,650,153

DEBT AND INTEREST EXPENSE (Deta

DEBT AND INTEREST EXPENSE (Details) - USD ($)	Dec. 31, 2015	Dec. 31, 2014
Total Debt	$ 30,063,635	$ 23,182,843
Less: current portion	(30,063,635)	(282,843)
Total long-term debt	0	22,900,000
Variable rate revolving credit facility payable [Member]
Total Debt	29,800,000	22,900,000
Installment loan due February 28, 2015 [Member]
Total Debt	108,894	0
Installment loan due June 11, 2016 [Member]
Total Debt	154,741	0
Installment loan due June 11, 2015 [Member]
Total Debt	0	154,750
Installment loan due February 28, 2015 [Member]
Total Debt	$ 0	$ 128,093

DEBT AND INTEREST EXPENSE (De79

DEBT AND INTEREST EXPENSE (Details 1)	Feb. 13, 2013
Utilization 90% [Member]
Prime margin	2.25%
Libor margin	3.25%
75% utilization 90% [Member]
Prime margin	2.00%
Libor margin	3.00%
50% utilization 75% [Member]
Prime margin	1.75%
Libor margin	2.75%
25% utilization 50% [Member]
Prime margin	1.50%
Libor margin	2.50%
Utilization 25% [Member]
Prime margin	1.25%
Libor margin	2.25%

DEBT AND INTEREST EXPENSE (De80

DEBT AND INTEREST EXPENSE (Details 2) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Debt Disclosure [Abstract]
Credit facility	$ 1,104,231	$ 1,109,153	$ 1,010,539
Credit facility commitment fees	34,512	70,813	56,092
Amortization and write offs of credit facility loan costs	286,009	188,669	480,261
Insurance installment loan	13,654	13,640	16,161
Louisiana Mineral Board	0	0	32,383
Other interest charges	1,489	3,275	4,056
Capitalized interest	(983,472)	(1,059,350)	(1,031,816)
Total interest expense	$ 456,423	$ 326,200	$ 567,676

DEBT AND INTEREST EXPENSE (De81

DEBT AND INTEREST EXPENSE (Details 3)	Dec. 31, 2015USD ($)
Debt And Interest Expens Tables
2,016	$ 30,063,635	[1]
2,017	0
2,018	0
2,019	0
2,020	$ 0
[1]	Includes $29,800,000 for possible accelerated maturity per Ninth Amendment to the credit agreement which otherwise matures May 20, 2017.

MERGER WITH PYRAMID OIL COMPA82

MERGER WITH PYRAMID OIL COMPANY AND GOODWILL (Details) - USD ($)	Dec. 31, 2015	Dec. 31, 2014	Sep. 10, 2014
Estimated Fair Value of Assets Acquired:
Goodwill(i)		$ 5,349,988
As initially Reported [Member]
Purchase Price(i):
Shares of Pyramid common stock held by Pyramid shareholders			4,788,085
Pyramid common stock price (September 10, 2014 closing price)			$ 4.70
Fair value of Pyramid common stock issued			$ 22,504,000
Consideration paid to Pyramid's shareholders			0
Issuance of 100,000 shares to Pyramid affiliated persons at $5.01 per share (September 11, 2014 closing price)			501,000
Fair value of Pyramid options assumed by the Company(ii)			100,500
Total purchase price			23,105,500
Estimated Fair Value of Liabilities Assumed:
Current liabilities			633,917
Noncurrent deferred tax liability(iii)			4,879,724
Other noncurrent liabilities (asset retirement obligation)			1,334,278
Amount attributable to liabilities assumed			6,847,919
Total purchase price plus liabilities assumed			29,953,419
Estimated Fair Value of Assets Acquired:
Current assets			9,066,589
Oil and natural gas properties(iv)			10,726,715
Net other property and equipment			4,158,420
Other noncurrent assets			261,380
Amount attributable to assets acquired			24,213,104
Goodwill(i)			$ 5,740,315
Measurement Period Adjustment [Member]
Purchase Price(i):
Shares of Pyramid common stock held by Pyramid shareholders
Pyramid common stock price (September 10, 2014 closing price)
Fair value of Pyramid common stock issued
Issuance of 100,000 shares to Pyramid affiliated persons at $5.01 per share (September 11, 2014 closing price)
Fair value of Pyramid options assumed by the Company(ii)
Total purchase price
Estimated Fair Value of Liabilities Assumed:
Current liabilities
Noncurrent deferred tax liability(iii)
Other noncurrent liabilities (asset retirement obligation)			$ (390,327)
Amount attributable to liabilities assumed			(390,327)
Total purchase price plus liabilities assumed			$ (390,327)
Estimated Fair Value of Assets Acquired:
Current assets
Oil and natural gas properties(iv)
Net other property and equipment
Other noncurrent assets
Amount attributable to assets acquired
Goodwill(i)			$ (390,327)
As adjusted [Member]
Purchase Price(i):
Shares of Pyramid common stock held by Pyramid shareholders			4,788,085
Pyramid common stock price (September 10, 2014 closing price)			$ 4.70
Fair value of Pyramid common stock issued			$ 22,504,000
Consideration paid to Pyramid's shareholders			0
Issuance of 100,000 shares to Pyramid affiliated persons at $5.01 per share (September 11, 2014 closing price)			501,000
Fair value of Pyramid options assumed by the Company(ii)			100,500
Total purchase price			23,105,500
Estimated Fair Value of Liabilities Assumed:
Current liabilities			633,917
Noncurrent deferred tax liability(iii)			4,879,724
Other noncurrent liabilities (asset retirement obligation)			943,951
Amount attributable to liabilities assumed			6,457,592
Total purchase price plus liabilities assumed			29,563,092
Estimated Fair Value of Assets Acquired:
Current assets			9,066,589
Oil and natural gas properties(iv)			10,726,715
Net other property and equipment			4,158,420
Other noncurrent assets			261,380
Amount attributable to assets acquired			24,213,104
Goodwill(i)			$ 5,349,988

MERGER WITH PYRAMID OIL COMPA83

MERGER WITH PYRAMID OIL COMPANY AND GOODWILL (Details 1) - USD ($)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Business Combinations [Abstract]
Revenues	$ 46,238,208	$ 33,534,396
Net income (loss)	$ (3,388,094)	$ (7,834,907)
Net income (loss) per share:
Basic	$ (0.07)	$ (0.19)
Diluted	$ (0.07)	$ (0.19)

MERGER WITH PYRAMID OIL COMPA84

MERGER WITH PYRAMID OIL COMPANY AND GOODWILL (Details Narrative) - USD ($)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Business Combinations [Abstract]
Sales of natural gas and crude oil	$ 945,580
Other operating expenses	1,285,200
Non-recurring transaction costs	2,226,719	$ 124,222
Public listing expensed	$ 1,287,285

INCOME TAXES (Details)

INCOME TAXES (Details) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Current income taxes (benefit):
Federal	$ (29,226)	$ 0	$ 0
State	(1,963)	0	0
Total	(31,189)	0	0
Deferred income taxes (benefit):
Federal	(7,227,361)	(2,377,192)	2,705,688
State	(724,489)	(176,662)	374,584
Total	(7,951,850)	(2,553,854)	3,080,272
Total taxes (benefit) on income	$ (7,983,039)	$ (2,553,854)	$ 3,080,272

INCOME TAXES (Details 1)

INCOME TAXES (Details 1) - USD ($)	Dec. 31, 2015	Dec. 31, 2014
Income Tax Disclosure [Abstract]
Deferred tax liability (hedges)		$ 1,843,409
Deferred tax liability from excess of book basis over tax basis of certain assets including property, plant and equipment	$ 30,009,264	30,081,226
Deferred tax liability	30,009,264	31,924,635
Stock based compensation	(608,442)	(1,205,722)
Alternative minimum tax credit carryforwards	(121,686)	(121,686)
Net operating loss ("NOL") carryforwards	$ (22,481,966)	(15,585,820)
Other deferred tax (asset)		(396,668)
Deferred tax asset	$ (23,212,094)	(17,309,896)
Net deferred tax liability	$ 6,797,170	$ 14,614,739

INCOME TAXES (Details 2)

INCOME TAXES (Details 2)	12 Months Ended
	Dec. 31, 2015USD ($)
NOL remaining	$ 61,873,243
Year NOL generated 2015 [Member]
NOL remaining	$ 14,926,752
Year of expiration	Dec. 31, 2035
Year NOL generated 2014 [Member]
NOL remaining	$ 14,943,985
Year of expiration	Dec. 31, 2034
Year NOL generated 2013 [Member]
NOL remaining	$ 9,417,693
Year of expiration	Dec. 31, 2033
Year NOL generated 2012 [Member]
NOL remaining	$ 8,082,421
Year of expiration	Dec. 31, 2032
Year NOL generated 2011 [Member]
NOL remaining	$ 5,511,938
Year of expiration	Dec. 31, 2031
Year NOL generated 2009 [Member]
NOL remaining	$ 4,844,318
Year of expiration	Dec. 31, 2029
Year NOL generated 2007 [Member]
NOL remaining	$ 1,095,474
Year of expiration	Dec. 31, 2027
Year NOL generated 2002 [Member]
NOL remaining	$ 3,050,662
Year of expiration	Dec. 31, 2022

INCOME TAXES (Details 3)

INCOME TAXES (Details 3) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Income Taxes Details 3
Amount computed using the statutory rate	$ (6,645,827)	$ (7,972,651)	$ (10,489,441)
Increase (reduction) in taxes resulting from:
Non-deductible change in value of preferred stock derivative liability	0	5,486,895	9,190,496
State taxes	(726,452)	(210,021)	254,645
Other	(610,760)	141,923	4,124,572
Income tax expense (benefit)	$ (7,983,039)	$ (2,553,854)	$ 3,080,272

EMPLOYEE BENEFIT PLANS (Details

EMPLOYEE BENEFIT PLANS (Details Textual) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Compensation and Retirement Disclosure [Abstract]
Defined Contribution Plan, Employer Contribution	$ 56,051	$ 38,827
Accrued liability for compensated absences	138,962	$ 166,660
Future employment contract salary commitments	$ 1,399,242

OTHER DISCLOSURES (Details)

OTHER DISCLOSURES (Details) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Other Operating Expenses
Bad debt expense	$ 839,171	$ 97,068	$ 193,601
Recovery of bad debts	(342,944)	(1,984)	(2,520)
Loss (gain) on disposal of property	(28,006)	3,392	(19,307)
Total	$ 468,221	$ 98,476	$ 171,774

OTHER DISCLOSURES (Details 1)

OTHER DISCLOSURES (Details 1) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Other Non-Operating Income (Expense)	$ 36,338	$ 25,378	$ (240,617)
Bank-Mandated Derivative Instruments Novation Cost [Member]
Other Non-Operating Income (Expense)	0	0	(175,000)
Louisiana Sales Tax Settlement [Member]
Other Non-Operating Income (Expense)	0	0	(44,149)
Louisiana Mineral Board Audit [Member]
Other Non-Operating Income (Expense)	0	0	(23,686)
Other [Member]
Other Non-Operating Income (Expense)	751	1,746	(5,118)
Interest Income [Member]
Other Non-Operating Income (Expense)	19,587	23,632	7,336
Rental Income [Member]
Other Non-Operating Income (Expense)	$ 16,000	$ 0	$ 0

OTHER DISCLOSURES (Details 2)

OTHER DISCLOSURES (Details 2) - USD ($)	Dec. 31, 2015	Dec. 31, 2014
Other Receivables	$ 633,573	$ 856,562
December 2015 and 2014 Settled Oil Derivative Instruments [Member]
Other Receivables	257,286	407,003
Tax refund [Member]
Other Receivables	177,157	158,571
Debit Balances For Trade Payables [Member]
Other Receivables	109,586	187,031
Refund From PPI For Duplicate Charges [Member]
Other Receivables	89,544	89,544
D&O Insurance Premium Adjustment [Member]
Other Receivables	0	16,356
Other [Member]
Other Receivables	$ 0	$ (1,943)

OTHER DISCLOSURES (Details 3)

OTHER DISCLOSURES (Details 3) - USD ($)	Dec. 31, 2015	Dec. 31, 2014
Prepayments	$ 704,523	$ 782,234
Insurance [Member]
Prepayments	570,379	536,410
Taxes And Fees [Member]
Prepayments	39,687	21,882
Property Taxes [Member]
Prepayments	41,583	56,992
Other Subscriptions [Member]
Prepayments	16,508	6,355
Software Maintenance Agreements [Member]
Prepayments	14,572	19,105
Geological Well Database Subscription [Member]
Prepayments	8,883	19,055
Software Licenses [Member]
Prepayments	$ 2,065	44,172
Exploration And Drilling Costs [Member]
Prepayments		71,893
Services [Member]
Prepayments		4,530
Other [Member]
Prepayments	$ 10,846	$ 1,840

OTHER DISCLOSURES (Details 4)

OTHER DISCLOSURES (Details 4) - USD ($)	Dec. 31, 2015	Dec. 31, 2014
Other Current Deferred Charges	$ 415,740	$ 342,798
Loan Fees [Member]
Other Current Deferred Charges	415,740	189,409
Deferred Premium On 2015 Oil Derivative Instruments [Member]
Other Current Deferred Charges	$ 0	$ 153,389

OTHER DISCLOSURES (Details 5)

OTHER DISCLOSURES (Details 5) - USD ($)	Dec. 31, 2015	Dec. 31, 2014
Other Noncurrent Assets	$ 38,104	$ 262,200
Loan Fees [Member]
Other Noncurrent Assets	0	262,200
Deferred Offering Costs [Member]
Other Noncurrent Assets	$ 38,104	$ 0

OTHER DISCLOSURES (Details 6)

OTHER DISCLOSURES (Details 6) - USD ($)	Dec. 31, 2015	Dec. 31, 2014
Other Accrued Liabilities	$ 1,781,484	$ 1,419,565
Employee termination benefits [Member]
Other Accrued Liabilities	422,037	0
Salaries And Bonuses [Member]
Other Accrued Liabilities	393,072	479,537
Accounting And Audit [Member]
Other Accrued Liabilities	202,297	22,964
Severance Taxes [Member]
Other Accrued Liabilities	157,941	164,374
Ad Valorem Taxes [Member]
Other Accrued Liabilities	143,957	172,444
Vacation [Member]
Other Accrued Liabilities	138,962	166,660
Sales And Use Tax [Member]
Other Accrued Liabilities	85,076	81,661
Insurance [Member]
Other Accrued Liabilities	67,532	119,121
Fees For Commodity Hedging Advisor [Member]
Other Accrued Liabilities	64,953	48,590
Interest Expense [Member]
Other Accrued Liabilities	39,471	9,327
Financing cost [Member]
Other Accrued Liabilities	35,000	0
Employee restricted stock unit awards [Member]
Other Accrued Liabilities	$ 13,981	0
Commodity Hedge Settlement [Member]
Other Accrued Liabilities		153,389
Other [Member]
Other Accrued Liabilities	$ 17,205	$ 1,498

SALES TO MAJOR CUSTOMERS (Detai

SALES TO MAJOR CUSTOMERS (Details Textual))	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Sales To Major Customers Details Textual
Number of major customer	3	3	4
Oil and natural gas sales to major customers (percent)	67.00%	73.00%	78.00%

LEASES (Details)

LEASES (Details)	Dec. 31, 2015USD ($)
Future minimum rentals under all noncancellable operating leases
2,016	$ 579,873
2,017	564,326
2,018	2,264
2,019	0
2,020	$ 0

LEASES (Details Textual)

LEASES (Details Textual)	12 Months Ended
	Dec. 31, 2015USD ($)ft²	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)
Leases Details Textual
Primary office space | ft²	15,180
Primary office space rent	$ 23,403
Parking space rent	50
Lease term expires		Dec. 31, 2017
Aggregate rental expense	$ 575,905	$ 531,127	$ 534,275

AT MARKET SECURITY SALES (Detai

AT MARKET SECURITY SALES (Details) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Marketable Securities [Abstract]
Common Stock Shares	1,347,458
Series A Preferred Stock Shares	46,857
Common Stock Net Proceeds	$ 1,363,160
Series A Preferred Stock Net Proceeds	870,386
Total Net Proceeds	$ 2,233,546

SUPPLEMENTARY INFORMATION ON101

SUPPLEMENTARY INFORMATION ON OIL AND NATURAL GAS EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES (UNAUDITED) (Details) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Property acquisition costs - unproved	$ (9,635,309)	$ 1,105,782	$ 3,865,932
Property acquisition costs - proved	7,587,965	3,349,473	8,539,134
Sales proceeds - unproved	(30,442)	(359,667)	(679,266)
Sales proceeds - proved	0	(307,600)	(718,000)
Exploration costs	3,217,161	426,909	2,504,087
Development costs	1,121,654	20,139,409	11,910,179
Capitalized asset retirements costs	4,301,810	241,629	5,795,400
Total costs incurred	$ 6,562,839	$ 24,595,935	$ 31,217,466

SUPPLEMENTARY INFORMATION ON102

SUPPLEMENTARY INFORMATION ON OIL AND NATURAL GAS EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES (UNAUDITED) (Details 1) - USD ($)	Dec. 31, 2015	Dec. 31, 2014
Oil and gas properties, full cost method Not subject to amortization:
Prospect inventory	$ 7,719,857	$ 14,913,126
Property acquisition costs - unproved	6,150,862	8,623,344
Well development costs - unproved	417,997	2,170,582
Subject to amortization:
Property acquisition costs - proved	58,393,861	50,744,401
Well development costs - proved	81,063,335	74,440,227
Capitalized costs - unsuccessful	60,549,824	52,539,407
Capitalized asset retirement costs	4,505,018	8,806,828
Total capitalized costs	218,800,754	212,237,915
Less accumulated depreciation, depletion and amortization	(117,304,945)	(103,929,493)
Net capitalized costs	$ 101,495,809	$ 108,308,422

SUPPLEMENTARY INFORMATION ON103

SUPPLEMENTARY INFORMATION ON OIL AND NATURAL GAS EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES (UNAUDITED) (Details 2)	12 Months Ended
	Dec. 31, 2015MBblsMMcf	Dec. 31, 2014MBblsMMcf	Dec. 31, 2013MBblsMMcf
Oil in (Bbls) [Member]
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves, Beginning of year | MBbls	14,011,343	14,381,960	7,739,964
Revisions of Previous Estimates | MBbls	(5,596,379)	(565,143)	(1,142,654)
Purchases of oil and gas properties | MBbls	103,387	472,132	7,959,600
Extensions and discoveries | MBbls	769,661	51,993	92,152
Sale of oil and gas properties | MBbls	0	0	0
Production | MBbls	(321,687)	(329,599)	(267,102)
Proved developed and undeveloped reserves, End of year | MBbls	8,966,325	14,011,343	14,381,960
Proved developed reserves, Beginning of the year | MBbls	2,347,482	2,099,701	1,474,015
Proved developed reserves, End of year | MBbls	2,117,559	2,347,482	2,099,701
Proved undeveloped reserves, Beginning of year | MBbls	11,663,861	12,282,259	6,265,949
Proved undeveloped reserves, End of year | MBbls	6,848,766	11,663,861	12,282,259
Natural Gas (in Mcf) [Member]
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves, Beginning of year | MMcf	35,259,522	38,372,369	31,071,137
Revisions of Previous Estimates | MMcf	(11,436,325)	(479,438)	(8,281,139)
Purchases of oil and gas properties | MMcf	264,981	81,177	16,495,803
Extensions and discoveries | MMcf	3,675,358	0	362,806
Sale of oil and gas properties | MMcf	0	0	0
Production | MMcf	(1,993,842)	(2,714,586)	(1,276,238)
Proved developed and undeveloped reserves, End of year | MMcf	25,759,694	35,259,522	38,372,369
Proved developed reserves, Beginning of the year | MMcf	7,786,537	10,316,516	10,156,754
Proved developed reserves, End of year | MMcf	8,552,249	7,786,537	10,316,516
Proved undeveloped reserves, Beginning of year | MMcf	27,472,985	28,055,853	20,914,383
Proved undeveloped reserves, End of year | MMcf	17,217,445	27,472,985	28,055,853

SUPPLEMENTARY INFORMATION ON104

SUPPLEMENTARY INFORMATION ON OIL AND NATURAL GAS EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES (UNAUDITED) (Details 3) - USD ($)	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Future cash inflows	$ 438,816,500	$ 1,339,372,300	$ 1,450,469,000
Future oil and natural gas operating expenses	(129,636,500)	(322,298,300)	(334,883,800)
Future development costs	(126,463,700)	(405,900,900)	(424,256,900)
Future income tax expenses	(23,334,886)	(133,467,940)	(163,704,120)
Future net cash flows	159,381,414	477,705,160	527,624,180
10% annual discount for estimating timing of cash flows	(53,318,652)	(183,249,968)	(202,270,201)
Standardized measure of discounted future net cash flows	$ 106,062,762	$ 294,455,192	$ 325,353,979	$ 211,552,886

SUPPLEMENTARY INFORMATION ON105

SUPPLEMENTARY INFORMATION ON OIL AND NATURAL GAS EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES (UNAUDITED) (Details 4) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Changes due to current year operation:
Sales of oil and natural gas, net of oil and natural gas operating expenses	$ (7,069,544)	$ (25,270,455)	$ (17,255,824)
Extensions and discoveries	16,660	2,743,800	37,750,617
Purchases of oil and gas properties	2,268,907	12,827,533	215,427,459
Development costs incurred during the period that reduced future development costs	4,052,919	9,178,400	100,500
Changes due to revisions in standardized variables:
Prices and operating expenses	(373,506,778)	(42,125,763)	(30,773,529)
Income taxes	65,424,175	19,303,313	(38,340,467)
Estimated future development costs	245,056,050	7,218,529	32,430,504
Quantity estimates	(80,454,131)	(21,028,476)	(107,070,514)
Sale of reserves in place	0	0	0
Accretion of discount	37,672,481	43,124,820	27,910,664
Production rates, timing and other	(81,853,169)	(36,870,488)	(6,378,317)
Net change	(188,392,430)	(30,898,787)	113,801,093
Beginning of year	294,455,192	325,353,979	211,552,886
End of year	$ 106,062,762	$ 294,455,192	$ 325,353,979

SUPPLEMENTARY INFORMATION ON106

SUPPLEMENTARY INFORMATION ON OIL AND NATURAL GAS EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES (Details Narrative)	12 Months Ended
	Dec. 31, 2015USD ($)$ / Unit	Dec. 31, 2014USD ($)$ / Unit	Dec. 31, 2013USD ($)$ / Unit
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Prospect profits related sales recorded | $	$ 30,442	$ 28,616	$ 50,346
Crude oil prices used in computing future cash flow	50.28	91.48	96.94
Natural gas prices used in computing future cash flow	2.59	4.35	3.67