Yuma Energy 10-K 30 Mar 15 2014 FY Annual report Financial data

Document_and_Entity_Informatio

Document and Entity Information (USD $)	12 Months Ended
	Dec. 31, 2014	Mar. 26, 2015	Jun. 30, 2014
Document And Entity Information
Entity Registrant Name	Yuma Energy, Inc.
Entity Central Index Key	81318
Document Type	10-K
Document Period End Date	31-Dec-14
Amendment Flag	FALSE
Current Fiscal Year End Date	-19
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			$15,171,528
Entity Common Stock, Shares Outstanding		69,125,624
Document Fiscal Period Focus	FY
Document Fiscal Year Focus	2014

CONSOLIDATED_BALANCE_SHEETS

CONSOLIDATED BALANCE SHEETS (USD $)	Dec. 31, 2014	Dec. 31, 2013
CURRENT ASSETS:
Cash and cash equivalents	$11,558,322	$4,194,511
Short-term investments	1,170,868	0
Trade Accounts receivable, net of allowance for doubtful accounts:	9,739,737	10,837,211
Officers and employees Accounts receivable:	316,077	155,080
Other Accounts receivable:	697,991	417,850
Commodity derivative instruments	3,338,537	0
Prepayments	782,234	433,991
Deferred taxes	245,922	146,964
Other deferred charges	342,798	162,416
Total current assets	28,192,486	16,348,023
OIL AND GAS PROPERTIES (full cost method):
Not subject to amortization	25,707,052	24,051,278
Subject to amortization	186,530,863	152,863,988
Subtotal	212,237,915	176,915,266
Less: accumulated depreciation, depletion and amortization	-103,929,493	-84,438,840
Net oil and gas properties	108,308,422	92,476,426
OTHER PROPERTY AND EQUIPMENT:
Land, buildings and improvements	2,795,000	0
Other property and equipment	3,439,688	2,066,760
Total	6,234,688	2,066,760
Less: accumulated depreciation and amortization	-1,909,352	-1,822,925
Net other property and equipment	4,325,336	243,835
OTHER ASSETS AND DEFERRED CHARGES:
Commodity derivative instruments	1,403,109	818,637
Deposits	264,064	7,300
Receivables from affiliate	0	95,634
Goodwill	5,349,988	0
Other noncurrent assets	262,200	1,642,113
Total other assets and deferred charges	7,279,361	2,563,684
Total assets	148,105,605	111,631,968
CURRENT LIABILITIES:
Current maturities of debt	282,843	178,027
Accounts payable, principally trade	25,004,364	15,116,560
Commodity derivative instruments	0	677,132
Asset retirement obligations	0	1,755,650
Deferred taxes	471,995	0
Other accrued liabilities	1,419,565	1,127,283
TOTAL CURRENT LIABILITIES	27,178,767	18,854,652
LONG-TERM DEBT:
Bank debt	22,900,000	31,215,000
OTHER NONCURRENT LIABILITIES:
Preferred stock derivative liability, Series A and B	0	51,290,414
Asset retirement obligations	12,487,770	8,942,029
Commodity derivative instruments	0	218,649
Deferred taxes	14,388,662	13,160,205
Restricted stock units	71,569	102,532
Other	22,451	69,998
Total other noncurrent liabilities	26,970,452	73,783,827
PREFERRED STOCK:
Series A and B, subject to mandatory redemption	0	35,666,342
EQUITY:
Common stock, no par value (300 million shares authorized, 69,139,869 and 41,074,950 issued)	137,469,772	2,669,465
Preferred stock	9,958,217	0
Accumulated other comprehensive income	38,801	38,770
Accumulated earnings (deficit)	-76,410,404	-50,596,088
Total equity	71,056,386	-47,887,853
Total liabilities and equity	$148,105,605	$111,631,968

CONSOLIDATED_BALANCE_SHEETS_Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) (USD $)	Dec. 31, 2014	Dec. 31, 2013
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	69,139,869	41,074,950

CONSOLIDATED_STATEMENTS_OF_OPE

CONSOLIDATED STATEMENTS OF OPERATIONS (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
REVENUES:
Sales of natural gas and crude oil	$42,057,910	$28,075,603	$21,282,115
Other revenue	1,278,217	1,066,969	601,794
Total revenues	43,336,127	29,142,572	21,883,909
EXPENSES:
Marketing cost of sales	1,045,177	1,234,308	891,118
Lease operating	12,816,725	9,316,364	5,098,868
Re-engineering and workovers	3,084,972	2,521,707	433,599
General and administrative - stock-based compensation	3,388,321	452,058	0
General and administrative - other	9,434,294	5,603,475	4,339,362
Depreciation, depletion and amortization	19,664,991	12,077,368	5,074,070
Asset retirement obligation accretion expense	604,511	668,497	265,323
Other	98,476	171,774	151,240
Total expenses	50,137,467	32,045,551	16,253,580
INCOME (LOSS) FROM OPERATIONS	-6,801,340	-2,902,979	5,630,329
OTHER INCOME (EXPENSE):
Change in fair value of preferred stock derivative liability - Series A and Series B	-15,676,842	-26,258,559	-17,098,504
Interest expense	-326,200	-567,676	-210,083
Other, net	25,378	-240,617	7,099
Total other income (expense)	-15,977,664	-27,066,852	-17,301,488
NET LOSS BEFORE INCOME TAXES	-22,779,004	-29,969,831	-11,671,159
Income tax expense (benefit)	-2,553,854	3,080,272	3,098,309
NET LOSS	-20,225,150	-33,050,103	-14,769,468
PREFERRED STOCK:
Dividends paid in cash, Series A perpetual preferred	224,098	0	0
Accretion (Series A and Series B)	786,536	1,101,972	963,900
Dividends paid in cash (Series A and Series B)	445,152	145,900	1,362,437
Dividends paid in kind (Series A and Series B)	4,133,380	5,412,281	0
NET LOSS ATTRIBUTABLE TO COMMON STOCKHOLDERS	($25,814,316)	($39,710,256)	($17,095,805)
LOSS PER COMMON SHARE:
Basic	($0.52)	($0.97)	($0.42)
Diluted	($0.52)	($0.97)	($0.42)
WEIGHTED AVERAGE NUMBER OF COMMON SHARES OUTSTANDING:
Basic	49,678,444	41,074,953	40,896,222
Diluted	49,678,444	41,074,953	40,896,222

CONSOLIDATED_STATEMENTS_OF_COM

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Consolidated Statements Of Comprehensive Income
NET LOSS	($20,225,150)	($33,050,103)	($14,769,468)
OTHER COMPREHENSIVE INCOME (LOSS):
Change in fair value of open commodity derivatives	0	0	1,075,885
Less income taxes	0	0	414,217
Change in fair value of open commodity derivatives, net of income taxes	0	0	661,668
Reclassification of (gain) loss on settled commodity derivatives	50	-374,099	-527,117
Less income taxes	19	-144,028	-202,941
Reclassification of (gain) loss on settled commodity derivatives, net of income taxes	31	-230,071	-324,176
OTHER COMPREHENSIVE INCOME (LOSS)	31	-230,071	337,492
COMPREHENSIVE LOSS	($20,225,119)	($33,280,174)	($14,431,976)

CONSOLIDATED_STATEMENTS_OF_CHA

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY (USD $)	COMMON STOCK	CAPITAL IN EXCESS OF PAR VALUE OF COMMON STOCK	PERPETUAL PREFERRED STOCK	ACCUMULATED OTHER COMPREHENSIVE INCOME	ACCUMULATED EARNINGS (DEFICIT)	Total
Beginning Balance, Amount at Dec. 31, 2012	$540	$2,182,293		$268,841	($10,885,832)
Beginning Balance, Shares at Dec. 31, 2012	40,808,370
Retroactive effect of change to no par value upon merger closing on September 10, 2014	2,182,293	-2,182,293
Retroactive effect of retirement of 54,000 Yuma Energy, Inc. shares of common stock outstanding before merger closing on September 10, 2014
Retroactive effect of 40,896,221 shares issued for merger closing on September 10, 2014
Convert Series A preferred stock to 15,112,295 shares of common stock on September 10, 2014
Convert Series B preferred stock to 7,771,192 shares of common stock on September 10, 2014
Pyramid Oil Company 4,788,085 shares outstanding last day of trading on September 10, 2014
Fair value of Pyramid Oil Company stock options
Employee restricted stock awards (178,729 shares, vested April 1, 2013, issued September 11, 2014)	486,632
Employee restricted stock awards (107,291 shares, vested and issued September 11, 2014)
Employee restricted stock awards forfeited September 8, 2014 (87,851 shares vested April 1, 2013)
Stock awards (100,000 shares) to employees, directors and consultants of Pyramid Oil Company vested upon the change in control and issued September 11, 2014
Employee restricted stock awards (1,952,671 shares, not fully vested, amortized to equity from merger closing until vesting dates)
Employee restricted stock unit awards (273,907 shares, vested December 31, 2014; 254,973 to be issued April 1, 2015 and 18,934 to be issued May 20, 2015)
Issuance of 9.25% Series A cumulative redeemable preferred stock, no par value
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	2,669,465			38,770	-50,596,088	-47,887,853
Ending Balance, Shares at Dec. 31, 2013	41,074,950
Retroactive effect of change to no par value upon merger closing on September 10, 2014
Retroactive effect of retirement of 54,000 Yuma Energy, Inc. shares of common stock outstanding before merger closing on September 10, 2014
Retroactive effect of 40,896,221 shares issued for merger closing on September 10, 2014
Convert Series A preferred stock to 15,112,295 shares of common stock on September 10, 2014	71,028,086
Convert Series B preferred stock to 7,771,192 shares of common stock on September 10, 2014	36,524,852
Pyramid Oil Company 4,788,085 shares outstanding last day of trading on September 10, 2014	22,504,000
Fair value of Pyramid Oil Company stock options	100,500
Employee restricted stock awards (178,729 shares, vested April 1, 2013, issued September 11, 2014)
Employee restricted stock awards (107,291 shares, vested and issued September 11, 2014)	488,615
Employee restricted stock awards forfeited September 8, 2014 (87,851 shares vested April 1, 2013)
Stock awards (100,000 shares) to employees, directors and consultants of Pyramid Oil Company vested upon the change in control and issued September 11, 2014	501,000
Employee restricted stock awards (1,952,671 shares, not fully vested, amortized to equity from merger closing until vesting dates)	2,784,023
Employee restricted stock unit awards (273,907 shares, vested December 31, 2014; 254,973 to be issued April 1, 2015 and 18,934 to be issued May 20, 2015)	869,231
Issuance of 9.25% Series A cumulative redeemable preferred stock, no par value			9,958,217
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	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	$137,469,772		$9,958,217	$38,801	($76,410,404)	$71,056,386
Ending Balance, Shares at Dec. 31, 2014	69,139,869

CONSOLIDATED_STATEMENTS_OF_CAS

CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Reconciliation of net loss to net cash provided by operating activities
Net loss	($20,225,150)	($33,050,103)	($14,769,468)
Increase in fair value of preferred stock derivative liability	15,676,842	26,258,559	17,098,504
Depreciation, depletion and amortization of property and equipment	19,664,991	12,077,368	5,074,070
Accretion of asset retirement obligation	604,511	668,497	265,323
Stock-based compensation net of capitalized cost	3,388,321	452,058	0
Amortization of other assets and liabilities	188,669	166,608	86,421
Deferred tax expense (benefit)	-2,553,854	3,080,272	3,098,309
Bad debt expense	97,068	193,601	210,187
Write off deferred offering costs	1,257,160	0	0
Write off credit financing costs	0	313,652	30,000
Amortization of benefit from commodity derivatives (sold) and purchased, net	-93,750	-72,600	-112,508
Net commodity derivatives mark-to-market (gain) loss	-4,724,985	231,886	-1,256,918
Other	5,448	-21,328	-55,463
Changes in current operating assets and liabilities:
Accounts receivable	976,093	-5,589,741	403,516
Other current assets	-267,386	869,550	-689,537
Restricted cash	0	0	341,474
Accounts payable	10,690,790	9,115,792	-6,420,733
Other current liabilities	-170,921	148,834	-56,514
Other	-47,547	69,998	0
NET CASH PROVIDED BY OPERATING ACTIVITIES	24,466,300	14,912,903	3,246,663
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures on property and equipment	-25,526,887	-28,152,714	-30,146,557
Proceeds from sale of property	667,267	902,166	1,386,649
Cash received from merger	4,550,082	0	0
Short-term investments retired	2,125,541	0	0
Decrease (increase) in noncurrent receivable from affiliate	95,634	-2,493	-2,486
NET CASH USED IN INVESTING ACTIVITIES	-18,088,363	-27,253,041	-28,762,394
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowing	901,257	872,754	606,238
Payments on borrowings	-796,441	-878,328	-659,101
Change in borrowing on line of credit	-8,315,000	13,340,000	14,900,000
Line of credit financing costs	-92,909	-681,739	-280,166
Net proceeds from issuance of preferred stock	9,958,217	0	0
Deferred offering costs	0	-1,257,160	17,183,705
Cash dividends to preferred stockholders	-669,250	-145,900	-1,362,437
Buy-out Yuma Production 1985, Ltd. minority interest partners	0	0	-245,422
Derivative instruments purchased	0	0	-16,004
Decrease in noncurrent payable to affiliate	0	0	-247,092
NET CASH PROVIDED BY FINANCING ACTIVITIES	985,874	11,249,627	29,879,721
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	7,363,811	-1,090,511	4,363,990
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD	4,194,511	5,285,022	921,032
CASH AND CASH EQUIVALENTS AT END OF PERIOD	11,558,322	4,194,511	5,285,022
Supplemental disclosure of cash flow information:
Interest payments (net of interest capitalized)	175,009	22,210	160,720
Interest capitalized	1,059,350	1,031,816	681,090
Supplemental disclosure of significant non-cash activity:
Preferred dividends paid in kind (Series A and Series B)	4,133,380	5,412,281	0
Change in capital expenditures financed by accounts payable	$1,310,037	$1,904,581	($1,650,073)

ORGANIZATION_CONSOLIDATION_AND

ORGANIZATION, CONSOLIDATION AND NATURE OF BUSINESS	12 Months Ended
	Dec. 31, 2014
Organization, Consolidation and Presentation of Financial Statements [Abstract]
ORGANIZATION, CONSOLIDATION AND NATURE OF BUSINESS	Yuma Energy, Inc., a California corporation (“YEI” and collectively with its subsidiaries, the “Company”) (formerly Pyramid Oil Company (“Pyramid”)), is a U.S.-based oil and gas company focused on the exploration for, and development of, conventional and unconventional oil and gas properties, primarily through the use of 3-D seismic surveys, in the U.S. Gulf Coast and California.
	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 we refer 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 M – 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	1/16/92
	Yuma Petroleum Company	“Petroleum”	Delaware	12/19/91
	Texas Southeastern Gas Marketing Company	“TSM”	Texas	9/12/96
	Pyramid Oil LLC	“POL”	California	8/8/14
	Pyramid Delaware Merger Subsidiary, Inc.	“PDMS”	Delaware	2/4/14
	YCI and PDMS are wholly owned subsidiaries of YEI, and YCI is the parent corporation of Exploration, Petroleum, TSM and 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. This approach is bolstered by strategic producing property acquisitions. 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, with the Company having interests in approximately 300 wells.
	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.
	POL and PDMS were inactive during 2014 (see Note W – Subsequent Events).

SUMMARY_OF_SIGNIFICANT_ACCOUNT

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	12 Months Ended
	Dec. 31, 2014
Accounting Policies [Abstract]
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES		1	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.
	The companies maintain their accounts on the accrual method of accounting in accordance with United States Generally Accepted Accounting Principles (“GAAP”). Each of the Companies has a fiscal year ending December 31.
		2	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.
		3	Reclassifications
	When required for comparability, reclassifications are made to the prior period financial statements to conform to the current year presentation.
		4	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 (exit price). 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 G – Fair Value Measurements).
	The carrying amount of cash and cash equivalents, accounts receivable and accounts payable reported on the balance sheet approximates fair value.
	Nonfinancial assets and liabilities initially measured at fair value include asset retirement obligations and exit or disposal costs.
	Level 3 Valuation Techniques – Financial assets are considered Level 3 when their fair values are determined using pricing models, discounted cash flow methodologies or similar techniques and at least one significant model assumption or input is unobservable. Level 3 financial liabilities consist of the Series A Preferred Stock issued July 1, 2011, and the Series B Preferred Stock issued July and August of 2012, for which there was no current market for these securities and such that the determination of fair value required significant judgment or estimation. The Company has historically valued certain possible financial scenarios relating to its preferred and common stock securities prior to being publicly traded using a Monte Carlo simulation model with the assistance of an independent valuation consultant. Prior to being publicly traded, the Company’s preferred stock securities had certain provisions, including automatic conditional conversion, re-pricing/down-round, change of control, default and follow-on offering that necessitated financial modeling. These models incorporated transaction details such as the stock price of comparable companies in the same industry, contractual terms, maturity, and risk free interest rates, as well as assumptions about future financings, volatility, and holder behavior as of issuance, and each quarter thereafter (see Note I – Preferred Stock).
		5	Statement of Cash Flow
	Cash on hand, deposits in banks and short-term investments with original maturities of three months or less are considered cash and cash equivalents. The cash flow of a derivative instrument of an identifiable transaction is classified in the same category as the cash flow from the item being hedged.
		6	Short-term Investments
	Short-term investments consist of commercial bank certificates of deposit maturing in May 2015 and are valued at cost.
		7	Trade Receivables
	Accounts receivable are stated net of allowance for doubtful accounts of $138,960 and $55,000 at December 31, 2014 and 2013, respectively.
	Management evaluates accounts receivable quarterly on an individual account basis, making individual assessments of collectability, and reserves those amounts it deems potentially uncollectible.
		8	Natural Gas Imbalances
	Pipeline gas imbalances represent the differences in measured volumes between gas receipts from suppliers and/or transporters and gas deliveries to end users, transporters and/or other purchasers. Most imbalances are settled monthly through cash-out mechanisms provided for in sales and transportation contracts. Other imbalances are carried forward until over or under deliveries in succeeding months can offset them. Gas imbalances are valued at cost utilizing the weighted average method.
	Exploration utilizes the sales method to account for natural gas production volume imbalances. Under this method, income is recorded based on Exploration’s net revenue interest in production taken for delivery. At December 31, 2014, Exploration had a net payable of approximately 23,248 Mcf under various natural gas balancing agreements, as compared to a 23,669 Mcf net payable at December 31, 2013.
		9	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.
		10	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 currently in earnings, unless the derivative instrument was designated as a cash flow hedge. 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. 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 settle. 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.
	For cash flow hedge accounting, a company must formally document, designate and assess the effectiveness of transactions that receive hedge accounting. Only derivative instruments that are expected to be highly effective in offsetting anticipated gains or losses on the hedged cash flows and that are subsequently documented to have been highly effective can qualify for hedge accounting. Effectiveness must be assessed both at inception of the hedge and on an ongoing basis. Any ineffectiveness in derivative instruments whereby gains or losses do not exactly offset anticipated gains or losses of hedged cash flows is measured and recognized in earnings in the period in which it occurs. When using hedge accounting, hedge effectiveness is assessed quarterly based on total changes in the derivative instrument’s fair value by performing regression analysis. A hedge is considered effective if certain statistical tests are met. The Company recorded hedge ineffectiveness in “Sales of natural gas and crude oil” in the Consolidated Statements of Operations.
		11	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 of 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 – The capitalized cost of oil and natural gas properties, excluding unevaluated properties, is amortized using the unit-of-production method (equivalent physical units of 6 Mcf of natural gas to each barrel of oil equivalent, or “Boe”) using estimates of proved reserve quantities. Investments in unproved properties are not amortized until proved reserves associated with the projects can be determined or until impairment occurs. If the results of the assessment indicate that the properties are impaired, the amount of impairment is added to the proved oil and gas property costs to be amortized. The amortizable base includes future development, abandonment and restoration costs. The rate for depreciation, depletion and amortization (“DD&A” or “depletion”) per Boe for the Company was $24.92, $23.87 and $19.84 for fiscal years 2014, 2013 and 2012, respectively. DD&A expense for oil and natural gas properties was $19,490,653, $11,927,872 and $4,956,196 for fiscal years 2014, 2013 and 2012, respectively.
	Impairments – Total capitalized costs of oil and gas properties are subject to a limit, or so-called “ceiling test.” The ceiling test limits total capitalized costs less related accumulated DD&A and deferred income taxes to a value not to exceed the sum of (i) the present value, discounted at a ten percent annual interest rate, of future net revenue from estimated production of proved oil and gas reserves, including the impact of cash flow hedges, based on current economic and operating conditions less future development costs (excluding retirement costs); plus (ii) the cost of properties not subject to amortization; less (iii) income tax effects related to differences in the book and tax basis of oil and gas properties. If unamortized capitalized costs less related deferred income taxes exceed this limit, the excess is charged to DD&A in the quarter the assessment is made. An expense recorded in one period may not be reversed in a subsequent period even though higher oil and gas prices may have increased the ceiling applicable to the subsequent period. These net unamortized costs, tested each calendar quarter, have not exceeded the cost center ceiling for fiscal years 2014, 2013 and 2012.
	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, 2014, and the year in which those costs were incurred.
		Year of acquisition
		2014		2013	2012	Prior	Total
	Leasehold acquisition cost	$154,194		$1,704,190	$15,349,192	$3,897,844	$21,105,420
	Exploration and development cost	891,610		1,059,262	111,910	71,455	2,134,237
	Capitalized interest	609,970		829,456	670,190	357,779	2,467,395
	Total	$1,655,774		$3,592,908	$16,131,292	$4,327,078	$25,707,052
	Capitalized Interest – Capitalized interest is included as part of the cost of oil and natural gas properties. The Company capitalized $1,059,350, $1,031,816 and $681,090 of interest associated with the line of credit (see Note L – Debt and Change in Banking Line and Agent Bank) during fiscal years 2014, 2013 and 2012, respectively. The capitalization rates are based on the Company’s weighted average cost of borrowings used to finance prospect generation.
	Capitalized Internal Costs – Internal costs incurred that are directly identified with acquisition, exploration and development activities undertaken by the Company for its own account, and that are not related to production, general corporate overhead or similar activities, are also capitalized. The Company capitalized $3,442,095, $2,702,952 and $2,589,342 of allocated indirect costs, excluding interest, related to these activities during fiscal years 2014, 2013 and 2012, respectively.
	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-, $42,329 and $172,173 in fiscal years 2014, 2013 and 2012, respectively.
		12	Other Property and Equipment
	Other property and equipment is recorded at cost with Pyramid property acquired in the merger 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 are 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		2014	2013
	Land	n/a		$2,469,000	$ -
	Office business machines	5-Mar		1,361,149	1,350,568
	Drilling and operating equipment	14		982,010	-
	Furniture and fixtures	7		412,215	383,585
	Automotive	5		351,707	-
	Office leasehold improvements	5		332,607	332,607
Buildings and improvements	25-Mar		326,000	-
Total other property and equipment			6,234,688	2,066,760
Less:  Accumulated depreciation and
leasehold improvement amortization			-1,909,352	-1,822,925
Net book value			$4,325,336	$243,835
Depreciation and leasehold improvement amortization expense totaled $174,338, $149,496 and $117,874 for the years ended December 31, 2014, 2013 and 2012, respectively.
	13	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”) requires 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 relates to its acquisition of Pyramid. Refer to Note M– Merger with Pyramid Oil Company and Goodwill for more details regarding the merger. The Company performs its goodwill impairment test annually, using a measurement date of July 1, or more often if circumstances require.
	14	Accounts Payable
Accounts payable consist principally of trade payables and costs associated with oil and natural gas exploration.
	15	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.
	16	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.
	17	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 O – Income Taxes).
	18	Other Taxes
Taxes incurred, other than income taxes, are as follows:
	December 31,
	2014		2013	2012
Production and severance tax	$2,693,396		$2,403,263	$2,002,397
Ad valorem tax	1,046,134		732,302	114,261
Sales tax	62,864		180,498	40,146
State franchise taxes	40,740		41,072	2,390
Total	$3,843,134		$3,357,135	$2,159,194
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.
	19	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 M – 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. The carrying amount of long-term debt as of December 31, 2014 and 2013 approximates fair value because the interest rate on this obligation is variable. The fair value of the oil and natural gas derivative instruments is included below in Note H – Commodity Derivative Instruments. The embedded derivative associated with each of the Series A and Series B Preferred Stock (eliminated in the merger) was bifurcated and carried at fair value as further described in Note I – Preferred Stock.
	20	Accumulated Other Comprehensive Income
AOCI includes changes in equity that are excluded from the Consolidated Statements of Operations and were 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. AOCI is now comprised of the balance as of December 31, 2012 for the derivative instruments that qualified for hedge accounting at that time less those contracts that have subsequently expired. AOCI will continue to be adjusted for the contracts as they settle.
	21	General and Administrative Expenses – Stock-Based Compensation
This includes payments to employees in the form of restricted stock awards, restricted stock units 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 N – Stockholders’ Equity). The Company adopted an Annual Incentive Plan for fiscal years 2014 and 2013 (see Note Q – 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 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 equity-classified share-based compensation awards, expense is recognized based on the grant-date fair value. 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 J – Stock-Based Compensation.
	22	General and Administrative Expenses - Other
G&A expenses are reported net of amounts capitalized pursuant to the full cost method of accounting.
Reimbursements of G&A expenses, if received from working interest owners of producing oil and natural gas properties operated by the Company (COPAS, or Council of Petroleum Accountants Societies, overhead), are reported as a reduction to G&A expense. Reimbursements of G&A expenses, if received from joint venture participants in 3-D seismic acquisition surveys, are initially reported as a reduction of capitalized G&A expenses on the Consolidated Balance Sheets in the full cost pool caption “Not subject to amortization”.
	23	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.
	24	Other Noncurrent Assets
Included in the 2013 noncurrent assets are deferred offering costs. During 2013, the Company explored several options to go public, including a possible listing on the Australian Stock Exchange. To accomplish this, the Company engaged legal, accounting, and reserve engineering specialists to assist in this process. These costs were charged to G&A during the first quarter of 2014.
	25	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 options, restricted stock awards, restricted stock units, and performance-based stock awards, if the inclusion of these items is dilutive. See Note N – Stockholders’ Equity.
	26	Changes in Accounting Principles
Not Yet Adopted
The Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2014-09, Revenue from Contracts with Customers. This ASU supersedes the revenue recognition requirements in Topic 605, Revenue Recognition, and industry-specific guidance in Subtopic 932-605, Extractive Activities – Oil and Gas – Revenue Recognition, and requires an entity to recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration the entity expects to be entitled to in exchange for those goods or services. This ASU is effective for annual and interim periods beginning in 2017 and is required to be adopted using one of two retrospective application methods, with no early adoption permitted. The Company is currently evaluating the impact of the adoption of this ASU on its consolidated financial statements.
ASU 2014-08, Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity, changes the criteria for reporting discontinued operations and requires additional disclosures, both for discontinued operations and for individually significant dispositions and assets classified as held for sale not qualifying as discontinued operations. This ASU is effective beginning in 2015, with early adoption permitted for disposals or for assets classified as held for sale not reported in previously issued financial statements. Management does not believe that the adoption of this ASU will have a significant impact on the Company’s consolidated results of operations, financial position or cash flows.
Recently adopted
In June 2013, FASB ratified the Emerging Issues Task Force consensus which requires that an unrecognized tax benefit (or a portion thereof) be presented as a reduction to a deferred tax asset for an available net operating loss carryforward, a similar tax loss or tax credit carryforward. This accounting standards update was effective for the Company beginning with the first quarter of 2014 and was applied prospectively to unrecognized tax benefits that existed as of the effective date. Adoption of this accounting standards update did not have a significant impact on the Company’s consolidated results of operations, financial position or cash flows.
In February 2013, an ASU was issued to provide guidance for the recognition, measurement, and disclosure of obligations resulting from joint and several liability arrangements for which the total amount of the obligation is fixed at the reporting date, which are separately addressed within GAAP. An entity is required to measure obligations resulting from joint and several liability arrangements for which the total amount of the obligation is fixed at the reporting date as the sum of 1) the amount the entity agreed to pay on the basis of its arrangement among its co-obligors and 2) any amount the entity expects to pay on behalf of its co-obligors. Disclosure of the nature of the obligation, including how the liability arose, the relationship with other co-obligors and the terms and conditions of the arrangement is required. In addition, the total outstanding amount under the arrangement, not reduced by the effect of any amounts that may be recoverable from other entities, plus the carrying amount of any liability or receivable recognized must be disclosed. This ASU was effective for the Company beginning in the first quarter of 2014 and was applied retrospectively for those in-scope obligations resulting from joint and several liability arrangements that existed at the beginning of 2014. Adoption of this ASU did not have a significant impact on the Company’s consolidated results of operations, financial position or cash flows.

ADDISON_ACQUISITION

ADDISON ACQUISITION	12 Months Ended
	Dec. 31, 2014
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.

ASSET_RETIREMENT_OBLIGATIONS

ASSET RETIREMENT OBLIGATIONS	12 Months Ended
	Dec. 31, 2014
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. For the purposes of calculating the ceiling test, the future cash outflows associated with settling the ARO liability are excluded from the computation of the discounted present value of estimated future net revenues.
	The net increase to ARO during 2013 from the Addison acquisition was $6,043,412. An initial Addison ARO estimate of $10,967,986 was recorded in the second quarter of 2013,but the lives and costs were reevaluated later that year with a resulting reduction of $4,924,574.
	Asset Retirement Obligations
		December 31,
		2014	2013
	Beginning of year balance	$10,697,679	$4,233,782
	Pyramid liabilities assumed in the merger	943,951	-
	Liabilities incurred during year	416,162	11,178,614
	Liabilities settled during year	-	-1,278,774
	Accretion expense	604,511	668,497
	Revisions in estimated cash flows	-174,533	-4,104,440
	End of year balance	$12,487,770	$10,697,679

RECEIVABLES_AND_PAYABLES_WITH_

RECEIVABLES AND PAYABLES WITH AFFILIATES, CHIEF EXECUTIVE OFFICER AND EMPLOYEES	12 Months Ended
	Dec. 31, 2014
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 for invoiced costs on prospects and wells (see Note F – Related Party Transactions).
		December 31,
		2014	2013
	Receivables from affiliates, CEO and employees:
	Current:
	Yuma CEO*	$174,720	$135,080
	Employees	141,357	20,000
		316,077	155,080
	Noncurrent:
	Yuma Gas Corporation	-	95,634
	Total	$316,077	$250,714
	*CEO paid balances outstanding at December 31, 2014; balance represents December 2014 charges billed subsequent to year-end under accrual accounting.

RELATED_PARTY_TRANSACTIONS

RELATED PARTY TRANSACTIONS	12 Months Ended
	Dec. 31, 2014
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 may 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 5% of the aggregate cost of the interest to be acquired.
	The purchase price for any working interests acquired from the Company is no better than the terms agreed to by unaffiliated third parties.
	Working interests acquired during fiscal years 2014 and 2013 under the WIIP are listed below:
				Working	Amount
	Year		Well, prospect or project	interest	paid
	2014		Anaconda Prospect	1.95%	$16,900
	2014		Gardner Island Well &	1.44%
			Main Pass 4 Facility	1.86%	$78,988
	2014		Austin Chalk (Additional W.I.)	1.00%	$16,000
	2013		Bell City East Prospect	0.71%	$5,330
	2013		Austin Chalk	1.00%	$9,412
	2013		Addison Acquisition	2.00%	$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, 2014
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 B – 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) – The carrying values of financial instruments, excluding commodity derivatives, comprising current assets and current liabilities approximate fair values due to the short-term maturities of these instruments.
	Derivatives – The fair values of the Company’s commodity derivatives are considered Level 2 as their fair values are based on third-party pricing models which utilize inputs that are either readily available in the public market, such as natural gas and oil forward curves and discount rates, or can be corroborated from active markets or broker quotes. These values are then compared to the values given by the Company’s counterparties for reasonableness. The Company is able to value the assets and liabilities based on observable market data for similar instruments, which results in the Company using market prices and implied volatility factors related to changes in the forward curves. Derivatives are also subject to the risk that counterparties will be unable to meet their obligations. Because the Company’s commodity derivative counterparty was Société Générale (“SocGen”) at December 31, 2014 (see Note H – Commodity Derivative Instruments), the Company has not considered non-performance risk in the valuation of its derivatives.
		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
	Liabilities:
	Commodity derivatives	$ -	$ -	$ -	$ -
	Preferred stock derivative	-	-	-	-
	Total liabilities	$ -	$ -	$ -	$ -
		Fair value measurements at December 31, 2013
			Significant
		Quoted prices	other	Significant
		in active	observable	unobservable
		markets	inputs	inputs
		(Level 1)	(Level 2)	(Level 3)	Total
	Assets:
	Commodity derivatives – oil	$ -	$818,637	$ -	$818,637
	Total assets	$ -	$818,637	$ -	$818,637
	Liabilities:
	Commodity derivatives – gas	$ -	$472,564	$ -	$472,564
	Commodity derivatives – oil	-	423,217	-	423,217
	Preferred stock derivative	-	-	51,290,414	51,290,414
	Total liabilities	$ -	$895,781	$51,290,414	$52,186,195
	Derivative instruments listed above include collars, swaps, and 3-way collars. For additional information on the Company’s derivative instruments and derivative liabilities, see Note H – Commodity Derivative Instruments, and Note I – Preferred Stock.
	At June 30, 2014 and as of the end of each of the prior quarters, level 3 inputs were used as inputs to a Monte Carlo option pricing model to calculate the value of Series A and Series B Preferred Stock and common stock.The June 30, 2014 calculation resulted in a value per share on a fully diluted and as-converted basis of $3,061. The actual simulation considered an approximate log-normal distribution for the market capital of the Company, and was estimated to evolve monthly over time (two steps per month) through February 28, 2015. At June 30, 2014, it was assumed that, in the event of a failed merger or other events, there was some modest probability that at the end of 2014 or early in 2015, the Company would either complete a Liquidity Event (as described in Note J – Stock-Based Compensation) or be sold. Each simulation considered and accounted for the probability of the completion of a Liquidity Event with some probability in each half-month time period in 2014. The volatility was assumed to be 39.45% and was derived from implied volatilities of a number of public companies (tickers: AXAS, CRK, CRZO, GDP, PQ, SFY, SGY and WRES) adjusted for the Company’s relatively lower amount of financial leverage at June 30, 2014.
	On September 10, 2014, the value of the preferred stock and associated derivative was marked to market. The preferred stock was converted to common stock as further described in Note M – Merger with Pyramid Oil Company and Goodwill. With the conversion of the shares of preferred stock to common stock, the value of the associated derivative liability was marked to market, then transferred to common stock equity.
	A summary of the value and the changes in the Company’s assets and liabilities classified as Level 3 measurements during 2014 and 2013 is presented below:
		Preferred Stock
		Derivative Liability
	31-Dec-14	$ -
	31-Dec-13	51,290,414
	Total change	($51,290,414)
	Debt – The Company’s debt is recorded at the carrying amount on its Consolidated Balance Sheets. For further discussion of the Company’s debt, see Note L – Debt and Change in Banking Line and Agent Bank. The carrying amount of floating-rate debt approximates fair value because the interest rates are variable and reflective of market rates.
	Asset Retirement Obligations (ARO’s) – The Company estimates the fair value of ARO’s based on discounted cash flow projections using numerous estimates, assumptions and judgments regarding such factors as the existence of a legal obligation for an ARO, amounts and timing of settlements, the credit-adjusted risk-free rate to be used and inflation rates. See Note D – Asset Retirement Obligations for a summary of changes in ARO’s.

COMMODITY_DERIVATIVE_INSTRUMEN

COMMODITY DERIVATIVE INSTRUMENTS	12 Months Ended
	Dec. 31, 2014
Derivative Instruments and Hedging Activities Disclosure [Abstract]
COMMODITY DERIVATIVE INSTRUMENTS	Objective and Strategies for Using Commodity Derivative Instruments – In order to mitigate the effect of commodity price uncertainty and enhance the predictability of cash flows relating to the marketing of the Company’s crude oil and natural gas, the Company enters into crude oil and natural gas price commodity derivative instruments with respect to a portion of the Company’s expected production. The commodity derivative instruments used include variable to fixed price commodity swaps, two-way and three-way collars.
	The fixed price swap and two-way collar contracts entitle the Company to receive settlement from the counterparty for each calculation period in amounts, if any, by which the settlement price for the scheduled trading days applicable for each calculation period is less than the fixed strike price or floor price. The Company would pay the counterparty if the settlement price for the scheduled trading days applicable for each calculation period is more than the fixed strike price or selling price, which would be the product of the notional quantity per calculation period and the excess of the floating price over the fixed or ceiling price with respect to each calculation period. The amount payable by the counterparty, if the floating price is below the fixed or floor price, is the product of the notional quantity per calculation period and the excess of the fixed or floor price over the floating price with respect to each calculation period.
	A three-way collar consists of a two-way collar contract combined with a put option contract sold by the Company with a strike price below the floor price of the two-way collar. The Company receives price protection at the purchased put option floor price of the two-way collar if commodity prices are above the sold put option strike price. If commodity prices fall below the sold put option strike price, the Company receives the cash market price plus the difference between the two put option strike prices. This type of instrument allows the Company to capture more value in a rising commodity price environment, but limits the benefits in a downward commodity price environment.
	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 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 will remain in AOCI until such time that the original hedged forecasted transaction occurs. The last of these contracts will expire in December 2016. Starting with year 2013, mark-to-market adjustments to the contracts that were in AOCI at year-end 2012 will not be made to AOCI, but instead are recognized in earnings, as are all other commodity derivative contracts going forward. As a result of discontinuing the application of hedge accounting, the Company’s earnings are potentially more volatile.See Note G – 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 – Commodity derivative instruments expose the Company to counterparty credit risk. The Company’s commodity derivative instruments are with SocGen which is rated “A” by Standard and Poor’s, “A2” by Moody’s, and “A” by Fitch. Commodity derivative contracts are executed under master agreements which allow the Company, in the event of default, to elect early termination of all contracts. If the Company chooses to elect early termination, all asset and liability positions would be netted and settled at the time of election.
	In conjunction with certain derivative hedging activity, the Company deferred the payment of $153,389 put premiums recorded in both current other deferred charges and current other accrued liabilities and is for production months January 2015 through December 2015. The put premium liabilities become payable monthly as the hedge production month becomes the prompt production month. The Company will begin amortizing the deferred put premium liabilities in January 2015.
	Commodity derivative instruments open as of December 31, 2014 are provided below. Natural gas prices are New York Mercantile Exchange (“NYMEX”) Henry Hub prices, and crude oil prices are NYMEX West Texas Intermediate, except for the oil swaps noted below that are based on Argus Light Louisiana Sweet.
		2015		2016
		Settlement		Settlement
	NATURAL GAS (MMBtu):
	3-way collars
	Volume	2,377,371		1,122,533
	Ceiling sold price (call) *	$4.47		$4.35
	Floor purchased price (put) *	$4.00		$4.10
	Floor sold price (short put) *	$3.25		$3.25
	Swaps
	Volume	458,622		-
	Price *	$4.08		-
	Reverse Swaps
	Volume	293,234		-
	Price *	$4.33		-
	CRUDE OIL (Bbls):
	3-way collars
	Volume	89,512		70,263
	Ceiling sold price (call) *	$104.36		$106.39
	Floor purchased price (put) *	$86.49		$92.38
	Floor sold price (short put) *	$65.82		$72.38
	Put Spread
	Volume	27,588		-
	Floor purchased price (put) *	$90.00	**	-
	Floor sold price (short put) *	$75.00	**	-
	* Prices are weighted averages
	** Contracts include a premium to be paid by the Company of $5.56 per barrel as the contracts mature ($153,389 total premium). The premium is not included in these prices.
	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,
		2014		2013
	Asset commodity derivatives:
	Current assets	$6,413,935		$1,109,403
	Noncurrent assets	3,163,891		2,861,225
		9,577,826		3,970,628
	Liability commodity derivatives:
	Current liabilities	-3,075,398		-1,786,535
	Noncurrent liabilities	-1,760,782		-2,261,237
		-4,836,180		-4,047,772
	Total commodity derivative instruments	$4,741,646		($77,144)
	Sales of natural gas and crude oil on the Consolidated Statements of Operations are comprised of the following:
		Years Ended December 31,
		2014		2013	2012
	Sales of natural gas and crude oil	$38,659,392		$28,235,413	$19,684,132
	Gains (losses) realized on settled contracts for
	commodity derivatives	-1,420,217		-524	228,557
	Gains (losses) on ineffectiveness of
	cash flow hedges	-		-	712,681
	Gains (losses) on market value of
	open contracts for commodity derivatives	4,724,985		-231,886	544,237
	Amortized gains from benefit of sold
	qualified gas options	93,750		72,600	128,512
	Amortized losses from cost of purchased
	non-qualified oil calls	-		-	-16,004
	Total sales of natural gas and crude oil	$42,057,910		$28,075,603	$21,282,115
	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,
		2014			2013		2012
	Before tax		After tax	Before tax	After tax	Before tax	After tax
Balance, beginning of period	$63,041		$38,770	$ 437,140	$268,841	($111,628)	($68,651)
Net change in fair value	-		-	-	-	1,075,885	661,668
Gains reclassified to income	-		-	-	-	-398,604	-245,141
Amortized gains from benefit of sold
qualified options realized in income	-93,755		-57,659	-72,600	-44,649	-128,513	-79,035
Other reclassifications due to expired
contracts previously subject to
hedge accounting rules	93,805		57,690	-301,499	-185,422	-	-
Balance, end of period	$63,091		$ 38,801	$63,041	$38,770	$437,140	$268,841

PREFERRED_STOCK

PREFERRED STOCK	12 Months Ended
	Dec. 31, 2014
PREFERRED STOCK:
PREFERRED STOCK	9.25% Series A Cumulative Redeemable Preferred Stock - On October 23, 2014, the Company held an initial closing of its public offering of 9.25% Series A Cumulative Redeemable Preferred Stock, no par value per share, with a liquidation preference of $25.00 per share (the “Series A Preferred Stock”). The Company issued 477,273 shares at a public offering price of $22.00 per share, for gross proceeds of $10,500,006. On October 24, 2014, the Company held an additional closing for 30,466 shares of Series A Preferred Stock at a public offering price of $22.00 per share for gross proceeds of $670,252. In total, the Company received $10,430,894 net of the underwriters’ discount and expenses. In addition to fees at the time of closing, the Company incurred estimated costs of $351,034 for the preferred stock issuance. The shares of Series A Preferred Stock trade on the NYSE MKT under the symbol “YUMAprA”. The Series A Preferred Stock cannot be converted into common stock (except upon a change in control and in the event the Company chooses to not redeem the Series A Preferred Stock), but may be redeemed by the Company, at the Company’s option, on or after October 23, 2017 (or in certain circumstances, prior to such date as a result of a change in control of the Company), at a redemption price of $25.00 per share plus any accrued and unpaid dividends. The Series A Preferred Stock has no stated maturity, is not subject to any sinking fund or mandatory redemption, and will remain outstanding indefinitely unless repurchased, redeemed or converted into common stock in connection with a change in control. Holders of the Series A Preferred Stock are entitled to receive, when, as and if declared by the Board of Directors, cumulative dividends at the rate of 9.25% per annum (the dividend rate) based on the liquidation price of $25.00 per share of the Series A Preferred Stock, payable monthly in arrears on each dividend payment date, with the first payment date of December 1, 2014. The Series A Preferred Stock is presented in the permanent equity section of the financial statements.
	Series A and Series B Preferred Stock of Yuma Co. – Prior to the closing of the merger on September 10, 2014, Yuma Co. had two classes of preferred stock outstanding, the Series A and Series B. Immediately prior to the closing of the merger, these shares of preferred stock were converted to common stock of Yuma Co. At the closing of the merger, the common stock of Yuma Co. was converted into common stock of the Company.
	During July 2011, Yuma Co. issued 14,605 shares of Series A Preferred Stock in connection with a private placement, realizing gross proceeds of $14,605,000 offset by offering expenses of $1,271,396 resulting in net proceeds of $13,333,604. The stated value and issue price of the Series A Preferred Stock was $1,000.00 per share and each share was convertible into one share of Yuma Co.’s common stock. The Series A Preferred Stock paid a cumulative dividend on a semi-annual basis of $30.00 per share out of funds legally available (subject to appropriate adjustment in the event of any stock dividend, stock split, combination or other similarrecapitalization with respect to the Series A Preferred Stock and subject to increase as further described below) as declared by the board of directors of Yuma Co.. These dividends were cumulative from the date of issuance, whether or not such dividends were declared, and were payable semi-annually, when and as declared by the board of directors of Yuma Co., on June 30 and December 31 in each year. At the election of the board of directors of Yuma Co., the dividends on the Series A Preferred Stock could be paid in additional shares of Series A Preferred Stock. Since the Required Event, as defined below, had not occurred by September 30, 2013, the semi-annual dividend rate on the Series A Preferred Stock increased, commencing on October 1, 2013, to a semi-annual rate of $60.00. Further, since the Required Event had not occurred by December 31, 2012, March 31, 2013 or June 30, 2013, then on each date the Series A Conversion Price then in effect decreased by an amount such that the Series A Preferred Stockholders increased their aggregate ownership in the Company by one percent. The “Required Event”, or “Liquidity Event”, referred to the conversion of the Series A Preferred Stock to common stock and registration of these shares under the Securities Act of 1933, as amended (the “Securities Act”), and the listing on a national securities exchange, quoted on the OTC Bulletin Board or quoted on the Pink Sheets. At December 31, 2012, Yuma Co. had not met the requirements of the Required Event and, as a result, the conversion rate to common stock for shares of Series A Preferred Stock changed from one to one to a conversion rate of one share of Series A Preferred Stock to 1.067579 shares of common stock, effectively providing a one percent increase in equity ownership in Yuma Co. to the Series A Preferred Stock stockholders. During 2013, Yuma Co. did not meet the requirements of the Required Event and, as a result of the required adjustments in the conversion rate at March 31, 2013 and June 30 2013, the conversion rate of one share of Series A Preferred Stock increased to 1.207101257 shares of common stock.
	During July and August 2012, Yuma Co. issued 18,590 shares of Series B Preferred Stock in a private placement, realizing gross proceeds of $18,590,000 offset by offering expenses of $1,406,295, resulting in net proceeds of $17,183,705. The stated value and issue price of the Series B Preferred Stock was $1,000.00 per share, and each share was convertible into 0.508185 shares of common stock. The Series B Preferred Stock paid a cumulative dividend on a semi-annual basis of $30.00 per share out of funds legally available(subject to appropriate adjustment in the event of any stock dividend, stock split, combination or other similar recapitalization). Such dividend was cumulative from the date of issuance of the Series B Preferred Stock, whether or not such dividends were declared, and were payable semi-annually, when and as declared by the board of directors of Yuma Co., on June 30 and December 31 in each year. At the election of the board of directors of Yuma Co., the dividends on the Series B Preferred Stock could be paid in additional shares of Series B Preferred Stock.
	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.
	Yuma Co. issued Series A and Series B Preferred Stock with certain embedded anti-dilution provisions (embodied weighted average ratchet or reset provisions) which provided for conversion price adjustments (“down-round protection”) had additional shares of common or preferred stock been issued by Yuma Co. at a lower valuation than the valuation used at the time the Series A or Series B Preferred Stock was issued. In addition, the Series A and Series B Preferred Stock provided that Yuma Co.was obligated to repurchase these shares should the Required Event not occur by the trigger date of June 20, 2016 in the case of the Series A Preferred Stock and June 30, 2017 in the case of the Series B Preferred Stock. The down-round provision and the ability to “put” the stock back to Yuma Co.had the features of an option or derivative. The provisions of ASC 815, Derivatives and Hedging, requiredYuma Co. to bifurcate the embedded derivative from the carrying value of the Series A and Series B Preferred Stock and record it on Yuma Co.’s balance sheet as a derivative liability, at fair value. Accordingly, at each reporting date, Yuma Co. marked the derivative liability to estimated fair value, with the resulting changes recognized in earnings. Since Yuma Co. was not public at the time, management elected to determine the fair value of this derivative using a Monte Carlo option pricing model with Level 3 inputs (see the Fair Value section of Note B – Summary of Significant Accounting Policies for Level 3 Valuation Techniques). The assumptions used were reviewed on a quarterly basis and were subject to change based primarily on management’s assessment of the probability of various events. After the initial valuation, changes in fair value were made with the increase or decrease flowing to the Consolidated Statements of Operations as “Change in fair value of preferred stock derivative liability”. Upon issuance of the Series A Preferred Stock in July 2011, the fair value of the associated derivative was $89.86 per share of Series A Preferred Stock, or an aggregate of $1,312,405. The December 31, 2013 fair value of the Series A derivative was $2,581.00 per share of Series A Preferred Stock, or an aggregate of $40,361,678. Upon issuance of the Series B Preferred Stock in July and August 2012, the fair value of the associated derivative was $55.00 for July and $52.79 for August per share of Series B Preferred Stock, or an aggregate of $1,016,715. The December 31, 2013 fair value of the Series B derivative was $556.00 per share of Series B Preferred Stock, or an aggregate of $10,928,736.
	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:
		30-Jun-13		31-Dec-13		30-Jun-14
		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 G – 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:
		31-Dec-14		31-Dec-13
		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	757.337439	15,112,295
	Series B Preferred Stock	20,192	0.508185	757.337439	7,771,192

STOCKBASED_COMPENSATION

STOCK-BASED COMPENSATION	12 Months Ended
	Dec. 31, 2014
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
STOCK-BASED COMPENSATION	The YumaCo. 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.
	Restricted Stock – The Company granted restricted stock awards (“RSAs”) under the Yuma Co. Plan in 2013. These restricted stock awards granted to officers,directors and employees generally vest in one-third increments over a three-year period, and are contingent on the recipient’s continued employment. Prior to vesting, all restricted stock recipients have the right to vote such stock and receive dividends thereon. The non-vested shares are not transferable and are held by our transfer agent.
	A summary of the status of the RSAs and changes for the year to date ended December 31, 2014 is presented below.
		Number of		Weighted
		unvested		average
		RSA		grant-date
		shares		fair value
	Unvested shares as of January 1, 2014	1,895,620		$3.22 per share
	Granted on March 6, 2014	196,151		$3.89 per share
	Granted on April 1, 2014	33,322		$3.89 per share
	Granted on May 20, 2014	341,559		$3.96 per share
	Vested	-107,291		$2.98 per share
	Forfeited	-406,690		$3.42 per share
	Unvested shares as of December 31, 2014	1,952,671		$3.40 per share
	Stock Options – Pyramid issued stock options as compensation to non-employee directors under the Pyramid Oil Company 2006 Equity Incentive Plan (the “Pyramid Plan”). The options vested immediately, are exercisable for a five-year period from the date of the grant.
	The following is a summary of the Company’s stock option activity.
						Weighted-
					Weighted-	average
					average	remaining	Aggregate
					exercise	contractual	intrinsic
		Options			price	life (years)	value
	Outstanding at December 31, 2013	105,000			$5.17	4.66	$ -
	Granted	-			-	-	-
	Exercised	-			-	-	-
	Forfeited	-			-	-	-
	Outstanding at December 31, 2014	105,000			$5.17	3.66	$ -
	Vested and expected to vest at
	31-Dec-14	105,000			$5.17	3.66	$ -
	Exercisable at December 31, 2014	105,000			$5.17	3.66	$ -
	As of December 31, 2014, 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, 2014.
			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		1.42	$5.40	5,000	$5.40
	$5.16		100,000		3.78	$5.16	100,000	$5.16
			105,000				105,000
	Restricted Stock Units – On April 1, 2013, the Company granted 163 Restricted Stock Units (for Yuma Co. shares) or “RSUs” to employees. Based on the exchange ratio of the merger, the RSUs converted into 123,446 RSUs. Each RSU represents a contingent right to receive one share of the Company’s common stock upon vesting. In order to vest, an employee must have continuous service with the Company from time of the grant through April 1, 2016, the vesting date. The RSUs may be settled in cash and do not require the eventual issuance of common stock (although it is an election available to the Company, management intends to settle in cash); consequently, the awards are liability-based and the booked valuation will change as the market value for common stock changes. The Company utilized a Monte Carlo simulation option pricing model prepared by an outside consulting firm to value the RSUs from inception through June 30, 2014, and utilized a Black Scholes option pricing model prepared by an outside consulting firm at September 30, 2014. At December 31, 2014, the RSU’s were valued at the common stock closing price of the Company on that date. Compensation expense is recognized over the three-year vesting period.
	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. The vesting of the units was subject to employee’s continued employment with the Company through December 31, 2014 and compliance with the other provisions of the Separation Agreement.
	A summary of the status of the unvested RSUs and changes during the year ended December 31, 2014 is presented below.
				Weighted
		Number of		average
		unvested		grant-date
		RSUs		fair value
	Unvested RSUs as of January 1, 2014	119,659		$2.72 per share
	Granted on December 25, 2014	273,907		$1.80 per share
	Vested	-273,907		$3.17 per share
	Forfeited	-24,235		$2.72 per share
	Unvested RSUs as of December 31, 2014	95,424		$2.72 per share

EARNINGS_PER_COMMON_SHARE

EARNINGS PER COMMON SHARE	12 Months Ended
	Dec. 31, 2014
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
		2014	2013	2012
	Series A Preferred Stock	10,031,104	12,964,860	11,063,185
	Series B Preferred Stock	5,263,585	7,259,079	3,067,217
	Restricted Stock Awards	2,256,264	1,334,452	-
	Restricted Stock Units	105,643	91,762	-
		17,656,596	21,650,153	14,130,402
	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, 2014, 2013 and 2012, adjusted earnings were losses, therefore common stock equivalents were excluded from the calculation of diluted net loss per share of commonstock, as their effect was anti-dilutive.

DEBT_AND_CHANGE_IN_BANKING_LIN

DEBT AND CHANGE IN BANKING LINE AND AGENT BANK	12 Months Ended
	Dec. 31, 2014
Debt Disclosure [Abstract]
DEBT AND CHANGE IN BANKING LINE AND AGENT BANK		December 31,
		2014		2013
	Variable rate revolving credit facility payable to Société Générale,
	OneWest Bank, FSB, and View Point Bank, N.A., maturing
	May 20, 2017, secured by oil and natural gas properties held by
	Yuma Exploration and Production Company, Inc. and guaranteed
	by The Yuma Companies, Inc.	$22,900,000		$31,215,000
	Installment loan due February 28, 2015, originating from the
	financing of insurance premiums at 3.65% interest rate.	282,843		178,027
		23,182,843		31,393,027
	Less:  current portion	-282,843		-178,027
	Total long-term debt	$22,900,000		$31,215,000
	On August 10, 2011, Exploration entered into a $125 million syndicated credit agreement with Amegy Bank National Association (“Amegy”) as Administrative Agent, or Agent Bank. 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”).
	The prime and LIBOR base rates were increased by the following margins:
					LIBOR
	Borrowing base utilization		Prime margin		margin
	Utilization > 75%		1.25%		3.50%
	50% < utilization < 75%		1.00%		3.25%
	25% < utilization < 50%		0.75%		3.00%
	Utilization < 25%		0.50%		2.75%
	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, has remained the Company’s bank for regular operational banking functions. The amendment changed the interest rate margins as follows:
					LIBOR
	Borrowing base utilization		Prime margin		margin
	Utilization > 90%		2.00%		3.00%
	75% < utilization < 90%		1.75%		2.75%
	50% < utilization < 75%		1.50%		2.50%
	Utilization < 50%		1.25%		2.25%
	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 (although still remaining the Company’s bank for treasury operations). 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:
					LIBOR
	Borrowing base utilization		Prime margin		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 OneWest Bank, FSB (“OneWest”) to replace Union with the new participation for SocGen and OneWest equal at 50/50. With the third amendment, the credit agreement maturity date was changed toMay 20, 2017.
	On September 27, 2013, the Borrowing Base Redetermination Agreement and Assignment added View Point Bank, N.A. (“View Point”) as a third lender in the credit agreement. Participating percentages at September 27, 2013 became 37.5% for SocGen, 37.5% for OneWest and 25% for View Point.
	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 million. A loan redetermination fee of $20,250 was paid but the expense is being amortized over the remaining loan life.
	Costs paid to SocGen to bring it into the syndicate include a $150,000 arrangement fee, an $88,000 upfront fee, and $87,598 in attorneys’ fees. Costs paid to replace Union with OneWest were a $50,000 arrangement fee, a $216,000 upfront fee and $37,061 in attorneys’ fees. On September 27, 2013, the Company paid SocGen a $24,000 redetermination fee whereby the borrowing base was increased by $4.0 million to $40.0 million. Attorneys’ fees for the redetermination were $4,080. All these costs are being amortized over the life of the loan. SocGen, as Agent Bank,is also paid an annual administrative fee of $25,000 amortized over the year. The unamortized Amegy and Union costs of $123,925 and $189,727 were written off immediately upon their exit from the syndicate. The Agent Bank also required all commodity hedges be moved from British Petroleum Corporation to SocGen and charged a fee of $175,000 for the novation. This fee was fully expensed.
	The following summarizes interest expense for the years ended December 31, 2014, 2013 and 2012.
		Years Ended December 31,
		2014		2013		2012
	Credit facility	$1,109,153		$1,010,539		$714,826
	Credit facility commitment fees	70,813		56,092		48,836
	Amortization and write offs of credit facility loan costs	188,669		480,261		113,057
	Insurance installment loan	13,640		16,161		10,587
	Louisiana Mineral Board	-		32,383		-
	Other interest charges	3,275		4,056		3,867
	Capitalized interest	-1,059,350		-1,031,816		-681,090
	Total interest expense	$326,200		$567,676		$210,083
	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 in compliance with the loan covenants as of December 31, 2014.
	Aggregate principal payments based on the Company’s current borrowings as of December 31, 2014 for the next five years are shown below:
	2015	$282,843
	2016	-
	2017	22,900,000
	2018	-
	2019	-

MERGER_WITH_PYRAMID_OIL_COMPAN

MERGER WITH PYRAMID OIL COMPANY AND GOODWILL	12 Months Ended
	Dec. 31, 2014
Business Combinations [Abstract]
MERGER WITH PYRAMID OIL COMPANY AND GOODWILL	On September 10, 2014, a whollyowned 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 805Business 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,	Measurement	September 10,
		2014	Period	2014
		(as initially	Adjustment(i)	(as adjusted)
		reported)
	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) Under the terms of the merger agreement, Pyramid shareholders own 7% of the Company. The total purchase price is based upon the closing price of $4.70 per share of Pyramid common stock on September 10, 2014 and 4,788,085 shares of Pyramid common stock outstanding at the effective time of the merger. The difference between the purchase price plus the liabilities of Pyramid assumed in the merger less the estimated fair value of the Pyramid assets acquired is shown as goodwill.
	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 is now 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) To adjust for the outstanding stock options to purchase common stock that were assumed by the Companywith the merger. The $100,500 fair value of the assumed options was calculated using the BlackScholes valuation model with assumptions for the following variables: common stock price, risk-free interest rates, and the Company’s stock volatility.
	(iii) The Company received a carryover tax basis in Pyramid’s assets and liabilities because the merger was not a taxable transaction under the Code. Based upon the preliminary purchase price allocation, a step-up in financial reporting carrying value related to the property acquired from Pyramid, net of the existing Pyramid deferred tax asset of $0.5 million, is expected to result in a combined deferred tax liability of approximately $16.2 million, an increase of approximately $5.4 million to the Company’s and Pyramid’s existing $10.8 million net deferred tax liability.
	(iv) Weighted average commodity prices utilized in the determination of the fair value of oil and natural gasproperties was based on the NYMEX price forecasts as of August 29, 2014 for oil and September 2, 2014 for natural gas, adjusted for differentials calculated from the 2013 historic Pyramid oil and gas prices versus the NYMEX oil (WTI) and gas average monthly prices, after adjustment for transportation fees.
	Due to the significant decline in oil commodity prices in the fourth quarter 2014, goodwill was considered for possible impairment at year end. The assumptions the Company used in calculating its reporting unit fair value (the Company has a single reporting unit) included its market capitalization and discounted future cash flows based on estimated reserves and production, future costs and future oil and natural gas prices. Both year-end estimates of fair value exceeded book value. However, material adverse changes to any of these factors could lead to an impairment of all or a portion of the Company’s goodwill in future periods.
	The following unaudited pro forma combined results of operations are provided for the years ended December 31, 2014, 2013 and 2012 as though the merger had been completed as of the beginning of the earliest period presented, or January 1, 2012. 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	2012
		(Unaudited)
	Revenues	$46,238,208	$33,534,396	$26,879,236
	Net income (loss)	($3,388,094)	($7,834,907)	$2,426,418
	Net income (loss) per share:
	Basic	($0.07)	($0.19)	$0.06
	Diluted	($0.07)	($0.19)	$0.04
	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, 2014
EQUITY:
STOCKHOLDERS' EQUITY		1	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 F – 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.
		2	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, stock appreciation rights (“SARs”), restricted stock awards (“RSAs”) or restricted stock units (“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 2,472,200 shares of common stock that were subject to outstanding restricted stock awards and restricted stock unit awards 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.
		3	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, restricted stock awards, restricted stock units, stock appreciation rights, 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, restricted stock awards, restricted stock units, stock appreciations rights, 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 stock appreciation rights 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 restricted stock awards, restricted stock unit awards, 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, 2014
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, 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 30, 2015.
	The Company did not incur any income tax deficiencies during fiscal years 2012, 2013, and 2014, and therefore had no interest or penalties assessed during the years ended December 31, 2012, 2013, and 2014.
	The tax years of the Company that remain subject to examination by the Internal Revenue Service and other tax authorities are fiscal years 2011, 2012, 2013, and 2014.
	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, 2014, 2013 and 2012:
		Years Ended December 31,
		2014		2013		2012
	Current income taxes:
	Federal	$ -		$              -		$ -
	State	-		-		-
	Total	-		-		-
	Deferred income taxes (benefit):
	Federal	-2,377,192		2,705,688		2,744,068
	State	-176,662		374,584		354,241
	Total	-2,553,854		3,080,272		3,098,309
	Total taxes (benefit) on income	($2,553,854)		$ 3,080,272		$3,098,309
	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,
		2014		2013
	Current:
	Deferred tax asset (stock-based compensation)	($1,196,378)		($146,964)
	Deferred tax asset (other asset)	-396,668		-
	Deferred tax liability (hedges)	1,819,119		-
	Total current deferred tax asset and liability	$226,073		($146,964)
	Noncurrent:
	Deferred tax liability (hedges)	$24,290		$24,262
	Deferred tax liability from excess of book basis over tax basis
	of certain assets including property, plant and equipment	30,081,222		23,116,582
		30,105,512		23,140,844
	Stock-based compensation	-9,344		-27,079
	Alternative minimum tax credit carryforwards	-121,686		-121,686
	Net operating loss (“NOL”) carryforwards	-15,585,820		-9,831,874
	Deferred tax asset	-15,716,850		-9,980,639
	Net deferred tax liability	$14,388,662		$13,160,205
	The deferred tax assets at December 31, 2014 and 2013 of $15,837,149 and $9,980,639, 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
	2014		$11,759,312		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		$43,761,818
	The tax provisions differ from the amounts that would be calculated by using federal statutory rates 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,
		2014		2013		2012
	Amount computed using the statutory rate	($7,972,651)		($10,489,441)		($4,084,907)
	Increase (reduction) in taxes resulting from:
	Non-deductible change in value of preferred
	stock derivative liability	5,486,895		9,190,496		5,984,476
	State taxes	-210,021		254,645		236,045
	Other	141,923		4,124,572		962,695
	Income tax expense (benefit)	($2,553,854)		$3,080,272		$3,098,309
	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, 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 2014 and 2013.

CONTINGENCIES

CONTINGENCIES	12 Months Ended
	Dec. 31, 2014
Commitments and Contingencies Disclosure [Abstract]
CONTINGENCIES		1	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. Management believes that the Company has adequate insurance to meet this potential claim.
		2	Environmental Remediation Contingencies
	As of September 30, 2014, 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 Stated 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.
	As of December 31, 2014, the Companyhad tendered its defense to its liability insurance carriers who are responding.At December 31, 2014, the Company could not predict the outcome of this case or, in management’s opinion, assess any potential liability; therefore no liability has been recorded on the Company’s books.

EMPLOYEE_BENEFIT_PLANS

EMPLOYEE BENEFIT PLANS	12 Months Ended
	Dec. 31, 2014
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 $38,827 and $33,412 under the Plan for the years ended December 31, 2014 and 2013, respectively.
	The Company provides medical, dental, and life insurance coverage for both employees and dependents, along with long-term 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 $166,660 and $123,406 for the years ended December 31, 2014 and 2013, respectively.
	The Company maintains employment contracts with members of its exploration staff and with certain key employees of the Company. As of December 31, 2014, future employment contract salary commitments were $3,160,373, 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 N – Stockholders’ Equity. Note J – 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 will meet during 2015 to evaluate the management team and determine any awards that may be due for 2014. 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, 2014
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		1	Off-Balance Sheet Risk
	The Company does not consider itself to have any material financial instruments with off-balance sheet risks.
		2	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.
		3	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, 2014
Other Disclosures
OTHER DISCLOSURES		1	Other Income (Expense)
		December 31,
		2014		2013	2012
	Bank-mandated derivative instruments novation cost	$ -		($175,000)	$ -
	Louisiana sales tax settlement	-		-44,149	-
	Louisiana Mineral Board audit	-		-23,686	-
	Other	25,378		2,218	7,099
	Total	$25,378		($240,617)	$7,099
		2	Other Receivables
		December 31,
		2014		2013
	December 2014 settled oil derivative instruments	$407,003		$ -
	Debit balances for trade payables	187,031		163,802
	Refund from PPI for duplicate charges	89,544		89,544
	D&O insurance premium adjustment	16,356		-
	Blowout insurance premium adjustment	-		162,075
	Other	(1,943)		2,429
	Total	$697,991		$417,850
		3	Prepayments
		December 31,
		2014		2013
	Insurance	$536,410		$209,415
	Exploration and drilling costs	71,893		187,145
	Property taxes	56,992		-
	Software licenses	44,172		8,593
	Taxes and fees	21,882		-
	Software maintenance agreements	19,105		14,099
	Geological well database subscription	19,055		-
	Other subscriptions	6,355		13,560
	Services	4,530		-
	Other	1,840		1,179
	Total	$782,234		$433,991
		4	Other Current Deferred Charges
		December 31,
		2014		2013
	Loan fees	$189,409		$162,416
	Deferred premium on 2015 oil derivative instruments	153,389		-
	Total	$342,798		$162,416
		5	Other Noncurrent Assets
		December 31,
		2014		2013
	Loan fees	$262,200		$384,953
	Deferred offering costs	-		1,257,160
	Total	$262,200		$1,642,113
		6	Other Accrued Liabilities
		December 31,
		2014		2013
	Salaries and bonuses	$479,537		$184,072
	Ad valorem taxes	172,444		-
	Vacation	166,660		123,406
	Severance taxes	164,374		170,531
	Commodity hedge settlement	153,389		21,463
	Insurance	119,121		-
	Sales and use tax	81,661		98,818
	Accounting and audit	22,964		158,368
	Interest expense	9,327		46,946
	Pre-initial public offering expenses	-		259,223
	Fees for commodity hedging advisor	-		62,631
	Other	50,088		1,825
	Total	$1,419,565		$1,127,283

SALES_TO_MAJOR_CUSTOMERS

SALES TO MAJOR CUSTOMERS	12 Months Ended
	Dec. 31, 2014
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. Four customers accounted for approximately 74 percent, 78 percent, and 79 percent of unaffiliated oil and natural gas sales in the years ended December 31, 2014, 2013 and 2012, respectively.

LEASES

LEASES	12 Months Ended
	Dec. 31, 2014
Leases [Abstract]
LEASES	The Company leases its primary office space of 15,180 square feet for $22,770 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 2014, 2013 and 2012 was $531,127, $534,275 and $378,192, respectively. As of December 31, 2014, future minimum rentals under all noncancellable operating leases are as follows:
	2015	$567,480
	2016	575,868
	2017	561,106
	2018	2,264
	2019	-

AT_MARKET_SECURITY_SALES

AT MARKET SECURITY SALES	12 Months Ended
	Dec. 31, 2014
Marketable Securities [Abstract]
AT MARKET SECURITY SALES	The Company entered into an At Market Sales Issuance 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. Under the Sales Agreement, the Company may offer and sell up to $18,829,742 in the aggregate of common stock and Series A Preferred Stock from time to time through the Agent. 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. As of December 31, 2014, no shares had been issued under the Sales Agreement (see Note W – Subsequent Events).

SUBSEQUENT_EVENTS

SUBSEQUENT EVENTS	12 Months Ended
	Dec. 31, 2014
Subsequent Events [Abstract]
SUBSEQUENT EVENTS	The Company has evaluated subsequent events through March 30, 2015, 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.
		1	Sixth Amendment to Credit Agreement
	On January 23, 2015, Exploration, entered into the Sixth Amendment (the “Amendment”) to that certain credit agreement dated August 10, 2011 with SocGen as Administrative Agent and Issuing Bank, and each of the lenders and guarantors.
	Pursuant to the Amendment, (i) the borrowing base under the credit agreement remained at $40.0 million until the next borrowing base redetermination date scheduled for February 1, 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 may issue additional series of preferred stock subject to certain restrictions, (iii) the definition of “Change of Control” has been amended and restated; (iv) the Company has pledged the stock of Exploration; (v) Exploration has pledged its interest in POL, and (vi) the 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. The borrowing base for the Company is currently being redetermined. The Company expects the new borrowing base to be set somewhat lower, but cannot estimate the ultimate amount at this time.
		2	Orleans Levee Board
	Exploration was named as one of 97 defendants in a lawsuit filed by the Levee Board of Orleans as described in Note P – Contingencies. 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. 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.
		3	Hedges
	On February 18, 2015, the Company cleared 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 clearing of the Company’s option positions and during thefollowing 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.
		4	Sales of Securities
	The Company has entered into a Sales Agreement with an investment banking firm as described in Note V – At Market Security Sales. The Company initiated the sales of securities under the Sales Agreement on February 18, 2015, and as of March 25, 2015, the Company has sold the following securities for the net proceeds listed below.
		Shares		Net Proceeds
	Common Stock	221,159		$328,008
	Series A Preferred Stock	37,769		$746,345
	Totals			$1,074,353

SUPPLEMENTARY_INFORMATION_ON_O

SUPPLEMENTARY INFORMATION ON OIL AND NATURAL GAS EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES (UNAUDITED)	12 Months Ended
	Dec. 31, 2014
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
SUPPLEMENTARY INFORMATION ON OIL AND NATURAL GAS EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES (UNAUDITED)		1	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,
		2014		2013	2012
	Property acquisition costs - unproved	$1,105,782		$3,865,932	$17,025,756
	Property acquisition costs - proved	3,349,473		8,539,134	1,800,385
	Sales proceeds - unproved	-359,667		-679,266	-1,386,649
	Sales proceeds - proved	-307,600		-718,000	-
	Exploration costs	426,909		2,504,087	4,931,623
	Development costs	20,139,409		11,910,179	7,699,903
	Capitalized asset retirements costs	241,629		5,795,400	173,432
	Total costs incurred	$24,595,935		$31,217,466	$30,244,450
	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 $28,616, $50,346 and $234,105 for fiscal years 2014, 2013 and 2012, respectively.
		2	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,
		2014		2013
	Oil and gas properties, full cost method:
	Not subject to amortization:
	Prospect inventory	$14,913,126		$14,587,986
	Property acquisition costs - unproved	8,623,344		8,202,369
	Well development costs - unproved	2,170,582		1,249,718
	Subject to amortization:
	Property acquisition costs - proved	50,744,401		36,999,813
	Well development costs - proved	74,440,227		56,460,276
	Capitalized costs - unsuccessful	52,539,407		50,849,905
	Capitalized asset retirement costs	8,806,828		8,565,199
	Total capitalized costs	212,237,915		176,915,266
	Less accumulated depreciation, depletion and amortization	-103,929,493		-84,438,840
	Net capitalized costs	$108,308,422		$92,476,426
		3	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 our natural gas and oil reserves is presented in accordance with regulations prescribed be 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.
		2014		2013	2012
	Barrels of oil and condensate:
	Proved developed and undeveloped reserves:
	Beginning of year	14,381,960		7,739,964	1,839,425
	Revisions of previous estimates	-565,143		-1,142,654	(132,352)
	Purchases of oil and gas properties	472,132		7,959,600	5,976,234
	Extensions and discoveries	51,993		92,152	225,063
	Sale of oil and gas properties	-		-	-
	Production	-329,599		(267,102)	(168,406)
	End of year	14,011,343		14,381,960	7,739,964
	Proved developed reserves - January 1,	2,099,701		1,474,015	1,236,002
	Proved developed reserves - December 31,	2,347,482		2,099,701	1,474,015
	Proved undeveloped reserves - January 1,	12,282,259		6,265,949	603,423
	Proved undeveloped reserves - December 31,	11,663,861		12,282,259	6,265,949
		2014		2013	2012
	Thousands of cubic feet of natural gas:
	Proved developed and undeveloped reserves:
	Beginning of year	38,372,369		31,071,137	17,020,496
	Revisions of previous estimates	-479,438		(8,281,139)	(463,712)
	Purchases of oil and gas properties	81,177		16,495,803	12,931,203
	Extensions and discoveries	-		362,806	2,163,825
	Sale of oil and gas properties	-		-	-
	Production	-2,714,586		(1,276,238)	(580,675)
	End of year	35,259,522		38,372,369	31,071,137
	Proved developed reserves - January 1,	10,316,516		10,156,754	5,287,966
	Proved developed reserves - December 31,	7,786,537		10,316,516	10,156,754
	Proved undeveloped reserves - January 1,	28,055,853		20,914,383	11,732,530
	Proved undeveloped reserves - December 31,	27,472,985		28,055,853	20,914,383
	Revisions to previously estimated reserves for both natural gas and crude oil were primarily caused by (i) commodity price reductions in 2014 causing wells to reach their economic limits sooner thus producing fewer reserves and causing some proved undeveloped locations to become uneconomic; (ii) downward revisions to the Masters Creek Crosby 14-1 well after the well was drilled and completed.
	4	Internal Controls Over Reserve and Future Net Revenue Estimation
The Company’s principal engineer, who is primarily responsible for overseeing the preparation of proved reserve estimates and future net revenues, has over 14 years of experience in the oil and gas industry. His experience includes detailed evaluation of reserves and future net reserves 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 Texas A&M University, M.S. in Finance from University of Houston, and MBA from Rice University. He is a member of the Society of Petroleum Engineers (the “SPE”). The procedures and methods used by the principal engineer in preparing internal estimates of proved reserves and future net cash flows are approved by the SPE’s Petroleum Resource Management System (“PMRS”) with no risks applied.
At December 31, 2012, Pressler Petroleum Consultants (“Pressler”) performed an independent engineering evaluation using the same guidelines established by PMRS to obtain an independent estimate of the proved reserves and future net revenues. During 2013, the Company changed outside engineering firms for the evaluation of its reserves. The Company hired Netherland, Sewell & Associates, Inc. (“NSAI”) to evaluate its reserve portfolio, replacing Pressler Petroleum Consultants. At December 31, 2014 and 2013, NSAI performed an independent engineering evaluation in accordance with the definitions and regulations of the SEC to obtain an independent estimate of the Company’s proved reserves and future net revenues.
	5	Third Party Procedures and Methods Review
The review consisted of 33 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, 2014, 2013, and 2012. The principal engineer 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.
	6	Standardized Measure of Discounted Future Net Cash Flows Relating toProved 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 2014, 2013 and 2012.
	December 31,
	2014		2013	2012
Future cash inflows	$1,339,372,300		$1,450,469,000	$823,280,251
Future oil and natural gas operating expenses	-322,298,300		-334,883,800	-151,140,007
Future development costs	-405,900,900		-424,256,900	-209,618,885
Future income tax expenses	(133,467,940)		-163,704,120	-111,946,653
Future net cash flows	477,705,160		527,624,180	350,574,706
10% annual discount for estimating timing of
cash flows	-183,249,968		-202,270,201	-139,021,820
Standardized measure of discounted future
net cash flows	$294,455,192		$325,353,979	$211,552,886
Estimates of future net cash flows from proved reserves of gas, oil, and condensate for fiscal years 2014, 2013 and 2012 are computed using the average first-day-of-the-month price during the 12-month period including the impact of cash flow hedges for 2012 and 2011 only. Since the Company discontinued cash flow hedge accounting as of January 1, 2013, the impact of cash flow hedges are excluded as of that date. Prices used in computing year-end future cash flows were $91.48, $96.94 and $94.04 for crude oil and $4.35, $3.67 and $2.93 for natural gas for fiscal years 2014, 2013 and 2012, 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.
	7	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:
	2014		2013	2012
Changes due to current year operation:
Sales of oil and natural gas, net of oil and
natural gas operating expenses	($25,270,455)		($17,255,824)	($13,250,556)
Extensions and discoveries	2,743,800		37,750,617	40,013,415
Purchases of oil and gas properties	12,827,533		215,427,459	177,412,984
Development costs incurred during the period
that reduced future development costs	9,178,400		100,500	5,432,652
Changes due to revisions in standardized variables:
Prices and operating expenses	-42,125,763		-30,773,529	-37,028,314
Income taxes	19,303,313		-38,340,467	-40,922,146
Estimated future development costs	7,218,529		32,430,504	-5,173,677
Quantity estimates	-21,028,476		-107,070,514	-12,905,019
Sale of reserves in place	-		-	-
Accretion of discount	43,124,820		27,910,664	11,055,659
Production rates, timing and other1	-36,870,488		-6,378,317	1,834,021
Net change	-30,898,787		113,801,093	126,469,019
Beginning of year	325,353,979		211,552,886	85,083,867
End of year	$294,455,192		$325,353,979	$211,552,886
1 For 2014, the approximate effect of timing changes is $28.5 million, leaving the remaining value as other differences of approximately $8.4 million.
Sales of oil and natural gas, net of oil and natural gas operating expenses, are based on historical pretax 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 pretax discounted basis.

SUMMARY_OF_SIGNIFICANT_ACCOUNT1

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)	12 Months Ended
	Dec. 31, 2014
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.
	The companies maintain their accounts on the accrual method of accounting in accordance with United States Generally Accepted Accounting Principles (“GAAP”). Each of the Companies has a fiscal year ending December 31.
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 (exit price). 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 G – Fair Value Measurements).
	The carrying amount of cash and cash equivalents, accounts receivable and accounts payable reported on the balance sheet approximates fair value.
	Nonfinancial assets and liabilities initially measured at fair value include asset retirement obligations and exit or disposal costs.
	Level 3 Valuation Techniques – Financial assets are considered Level 3 when their fair values are determined using pricing models, discounted cash flow methodologies or similar techniques and at least one significant model assumption or input is unobservable. Level 3 financial liabilities consist of the Series A Preferred Stock issued July 1, 2011, and the Series B Preferred Stock issued July and August of 2012, for which there was no current market for these securities and such that the determination of fair value required significant judgment or estimation. The Company has historically valued certain possible financial scenarios relating to its preferred and common stock securities prior to being publicly traded using a Monte Carlo simulation model with the assistance of an independent valuation consultant. Prior to being publicly traded, the Company’s preferred stock securities had certain provisions, including automatic conditional conversion, re-pricing/down-round, change of control, default and follow-on offering that necessitated financial modeling. These models incorporated transaction details such as the stock price of comparable companies in the same industry, contractual terms, maturity, and risk free interest rates, as well as assumptions about future financings, volatility, and holder behavior as of issuance, and each quarter thereafter (see Note I – Preferred Stock).
Statement of Cash Flow	Statement of Cash Flow
	Cash on hand, deposits in banks and short-term investments with original maturities of three months or less are considered cash and cash equivalents. The cash flow of a derivative instrument of an identifiable transaction is classified in the same category as the cash flow from the item being hedged.
Short-term Investments	Short-term Investments
	Short-term investments consist of commercial bank certificates of deposit maturing in May 2015 and are valued at cost.
Trade Receivables	Trade Receivables
	Accounts receivable are stated net of allowance for doubtful accounts of $138,960 and $55,000 at December 31, 2014 and 2013, respectively.
	Management evaluates accounts receivable quarterly on an individual account basis, making individual assessments of collectability, and reserves those amounts it deems potentially uncollectible.
Natural Gas Imbalances	Natural Gas Imbalances
	Pipeline gas imbalances represent the differences in measured volumes between gas receipts from suppliers and/or transporters and gas deliveries to end users, transporters and/or other purchasers. Most imbalances are settled monthly through cash-out mechanisms provided for in sales and transportation contracts. Other imbalances are carried forward until over or under deliveries in succeeding months can offset them. Gas imbalances are valued at cost utilizing the weighted average method.
	Exploration utilizes the sales method to account for natural gas production volume imbalances. Under this method, income is recorded based on Exploration’s net revenue interest in production taken for delivery. At December 31, 2014, Exploration had a net payable of approximately 23,248 Mcf under various natural gas balancing agreements, as compared to a 23,669 Mcf net payable at December 31, 2013.
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 currently in earnings, unless the derivative instrument was designated as a cash flow hedge. 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. 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 settle. 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.
	For cash flow hedge accounting, a company must formally document, designate and assess the effectiveness of transactions that receive hedge accounting. Only derivative instruments that are expected to be highly effective in offsetting anticipated gains or losses on the hedged cash flows and that are subsequently documented to have been highly effective can qualify for hedge accounting. Effectiveness must be assessed both at inception of the hedge and on an ongoing basis. Any ineffectiveness in derivative instruments whereby gains or losses do not exactly offset anticipated gains or losses of hedged cash flows is measured and recognized in earnings in the period in which it occurs. When using hedge accounting, hedge effectiveness is assessed quarterly based on total changes in the derivative instrument’s fair value by performing regression analysis. A hedge is considered effective if certain statistical tests are met. The Company recorded hedge ineffectiveness in “Sales of natural gas and crude oil” in the Consolidated Statements of Operations.
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 of 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 – The capitalized cost of oil and natural gas properties, excluding unevaluated properties, is amortized using the unit-of-production method (equivalent physical units of 6 Mcf of natural gas to each barrel of oil equivalent, or “Boe”) using estimates of proved reserve quantities. Investments in unproved properties are not amortized until proved reserves associated with the projects can be determined or until impairment occurs. If the results of the assessment indicate that the properties are impaired, the amount of impairment is added to the proved oil and gas property costs to be amortized. The amortizable base includes future development, abandonment and restoration costs. The rate for depreciation, depletion and amortization (“DD&A” or “depletion”) per Boe for the Company was $24.92, $23.87 and $19.84 for fiscal years 2014, 2013 and 2012, respectively. DD&A expense for oil and natural gas properties was $19,490,653, $11,927,872 and $4,956,196 for fiscal years 2014, 2013 and 2012, respectively.
	Impairments – Total capitalized costs of oil and gas properties are subject to a limit, or so-called “ceiling test.” The ceiling test limits total capitalized costs less related accumulated DD&A and deferred income taxes to a value not to exceed the sum of (i) the present value, discounted at a ten percent annual interest rate, of future net revenue from estimated production of proved oil and gas reserves, including the impact of cash flow hedges, based on current economic and operating conditions less future development costs (excluding retirement costs); plus (ii) the cost of properties not subject to amortization; less (iii) income tax effects related to differences in the book and tax basis of oil and gas properties. If unamortized capitalized costs less related deferred income taxes exceed this limit, the excess is charged to DD&A in the quarter the assessment is made. An expense recorded in one period may not be reversed in a subsequent period even though higher oil and gas prices may have increased the ceiling applicable to the subsequent period. These net unamortized costs, tested each calendar quarter, have not exceeded the cost center ceiling for fiscal years 2014, 2013 and 2012.
	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, 2014, and the year in which those costs were incurred.
		Year of acquisition
		2014	2013	2012	Prior	Total
	Leasehold acquisition cost	$154,194	$1,704,190	$15,349,192	$3,897,844	$21,105,420
	Exploration and development cost	891,610	1,059,262	111,910	71,455	2,134,237
	Capitalized interest	609,970	829,456	670,190	357,779	2,467,395
	Total	$1,655,774	$3,592,908	$16,131,292	$4,327,078	$25,707,052
	Capitalized Interest – Capitalized interest is included as part of the cost of oil and natural gas properties. The Company capitalized $1,059,350, $1,031,816 and $681,090 of interest associated with the line of credit (see Note L – Debt and Change in Banking Line and Agent Bank) during fiscal years 2014, 2013 and 2012, respectively. The capitalization rates are based on the Company’s weighted average cost of borrowings used to finance prospect generation.
	Capitalized Internal Costs – Internal costs incurred that are directly identified with acquisition, exploration and development activities undertaken by the Company for its own account, and that are not related to production, general corporate overhead or similar activities, are also capitalized. The Company capitalized $3,442,095, $2,702,952 and $2,589,342 of allocated indirect costs, excluding interest, related to these activities during fiscal years 2014, 2013 and 2012, respectively.
	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-, $42,329 and $172,173 in fiscal years 2014, 2013 and 2012, respectively.
Other Property and Equipment	Other Property and Equipment
	Other property and equipment is recorded at cost with Pyramid property acquired in the merger 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 are 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	2014	2013
	Land	n/a	$2,469,000	$ -
	Office business machines	5-Mar	1,361,149	1,350,568
	Drilling and operating equipment	14	982,010	-
	Furniture and fixtures	7	412,215	383,585
	Automotive	5	351,707	-
	Office leasehold improvements	5	332,607	332,607
	Buildings and improvements	25-Mar	326,000	-
	Total other property and equipment		6,234,688	2,066,760
	Less:  Accumulated depreciation and
	leasehold improvement amortization		-1,909,352	-1,822,925
	Net book value		$4,325,336	$243,835
	Depreciation and leasehold improvement amortization expense totaled $174,338, $149,496 and $117,874 for the years ended December 31, 2014, 2013 and 2012, 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”) requires 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 relates to its acquisition of Pyramid. Refer to Note M– Merger with Pyramid Oil Company and Goodwill for more details regarding the merger. The Company performs its goodwill impairment test annually, using a measurement date of July 1, or more often if circumstances require.
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 O – Income Taxes).
Other Taxes	Other Taxes
	Taxes incurred, other than income taxes, are as follows:
		December 31,
		2014	2013	2012
	Production and severance tax	$2,693,396	$2,403,263	$2,002,397
	Ad valorem tax	1,046,134	732,302	114,261
	Sales tax	62,864	180,498	40,146
	State franchise taxes	40,740	41,072	2,390
	Total	$3,843,134	$3,357,135	$2,159,194
	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 M – 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. The carrying amount of long-term debt as of December 31, 2014 and 2013 approximates fair value because the interest rate on this obligation is variable. The fair value of the oil and natural gas derivative instruments is included below in Note H – Commodity Derivative Instruments. The embedded derivative associated with each of the Series A and Series B Preferred Stock (eliminated in the merger) was bifurcated and carried at fair value as further described in Note I – Preferred Stock.
Accumulated Other Comprehensive Income	Accumulated Other Comprehensive Income
	AOCI includes changes in equity that are excluded from the Consolidated Statements of Operations and were 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. AOCI is now comprised of the balance as of December 31, 2012 for the derivative instruments that qualified for hedge accounting at that time less those contracts that have subsequently expired. AOCI will continue to be adjusted for the contracts as they settle.
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 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 N – Stockholders’ Equity).The Company adopted an Annual Incentive Plan for fiscal years 2014 and 2013 (see Note Q – 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 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 equity-classified share-based compensation awards, expense is recognized based on the grant-date fair value. 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 J – 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.
	Reimbursements of G&A expenses, if received from working interest owners of producing oil and natural gas properties operated by the Company (COPAS, or Council of Petroleum Accountants Societies, overhead), are reported as a reduction to G&A expense. Reimbursements of G&A expenses, if received from joint venture participants in 3-D seismic acquisition surveys, are initially reported as a reduction of capitalized G&A expenses on the Consolidated Balance Sheets in the full cost pool caption “Not subject to amortization”.
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
	Included in the 2013 noncurrent assets are deferred offering costs. During 2013, the Company explored several options to go public, including a possible listing on the Australian Stock Exchange. To accomplish this, the Company engaged legal, accounting, and reserve engineering specialists to assist in this process. These costs were charged to G&A during the first quarter of 2014.
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 options, restricted stock awards, restricted stock units, and performance-based stock awards, if the inclusion of these items is dilutive. See Note N – Stockholders’ Equity.
Changes in Accounting Principles	Changes in Accounting Principles
	Not Yet Adopted
	The Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2014-09, Revenue from Contracts with Customers. This ASU supersedes the revenue recognition requirements in Topic 605, Revenue Recognition, and industry-specific guidance in Subtopic 932-605, Extractive Activities – Oil and Gas – Revenue Recognition, and requires an entity to recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration the entity expects to be entitled to in exchange for those goods or services. This ASU is effective for annual and interim periods beginning in 2017 and is required to be adopted using one of two retrospective application methods, with no early adoption permitted. The Company is currently evaluating the impact of the adoption of this ASU on its consolidated financial statements.
	ASU 2014-08, Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity, changes the criteria for reporting discontinued operations and requires additional disclosures, both for discontinued operations and for individually significant dispositions and assets classified as held for sale not qualifying as discontinued operations. This ASU is effective beginning in 2015, with early adoption permitted for disposals or for assets classified as held for sale not reported in previously issued financial statements. Management does not believe that the adoption of this ASU will have a significant impact on the Company’s consolidated results of operations, financial position or cash flows.
	Recently adopted
	In June 2013, FASB ratified the Emerging Issues Task Force consensus which requires that an unrecognized tax benefit (or a portion thereof) be presented as a reduction to a deferred tax asset for an available net operating loss carryforward, a similar tax loss or tax credit carryforward. This accounting standards update was effective for the Company beginning with the first quarter of 2014 and was applied prospectively to unrecognized tax benefits that existed as of the effective date. Adoption of this accounting standards update did not have a significant impact on the Company’s consolidated results of operations, financial position or cash flows.
	In February 2013, an ASU was issued to provide guidance for the recognition, measurement, and disclosure of obligations resulting from joint and several liability arrangements for which the total amount of the obligation is fixed at the reporting date, which are separately addressed within GAAP. An entity is required to measure obligations resulting from joint and several liability arrangements for which the total amount of the obligation is fixed at the reporting date as the sum of 1) the amount the entity agreed to pay on the basis of its arrangement among its co-obligors and 2) any amount the entity expects to pay on behalf of its co-obligors. Disclosure of the nature of the obligation, including how the liability arose, the relationship with other co-obligors and the terms and conditions of the arrangement is required. In addition, the total outstanding amount under the arrangement, not reduced by the effect of any amounts that may be recoverable from other entities, plus the carrying amount of any liability or receivable recognized must be disclosed. This ASU was effective for the Company beginning in the first quarter of 2014 and was applied retrospectively for those in-scope obligations resulting from joint and several liability arrangements that existed at the beginning of 2014. Adoption of this ASU did not have a significant impact on the Company’s consolidated results of operations, financial position or cash flows.

ORGANIZATION_CONSOLIDATION_AND1

ORGANIZATION, CONSOLIDATION AND NATURE OF BUSINESS (Tables)	12 Months Ended
	Dec. 31, 2014
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	1/16/92
	Yuma Petroleum Company	“Petroleum”	Delaware	12/19/91
	Texas Southeastern Gas Marketing Company	“TSM”	Texas	9/12/96
	Pyramid Oil LLC	“POL”	California	8/8/14
	Pyramid Delaware Merger Subsidiary, Inc.	“PDMS”	Delaware	2/4/14

SUMMARY_OF_SIGNIFICANT_ACCOUNT2

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Tables)	12 Months Ended
	Dec. 31, 2014
Summary Of Significant Accounting Policies Tables
Cost of unproved properties		Year of acquisition
		2014	2013	2012	Prior	Total
	Leasehold acquisition cost	$154,194	$1,704,190	$15,349,192	$3,897,844	$21,105,420
	Exploration and development cost	891,610	1,059,262	111,910	71,455	2,134,237
	Capitalized interest	609,970	829,456	670,190	357,779	2,467,395
	Total	$1,655,774	$3,592,908	$16,131,292	$4,327,078	$25,707,052
Other Property and Equipment		Estimated
		useful	December 31,
		life in years	2014	2013
	Land	n/a	$2,469,000	$ -
	Office business machines	5-Mar	1,361,149	1,350,568
	Drilling and operating equipment	14	982,010	-
	Furniture and fixtures	7	412,215	383,585
	Automotive	5	351,707	-
	Office leasehold improvements	5	332,607	332,607
	Buildings and improvements	25-Mar	326,000	-
	Total other property and equipment		6,234,688	2,066,760
	Less:  Accumulated depreciation and
	leasehold improvement amortization		-1,909,352	-1,822,925
	Net book value		$4,325,336	$243,835
Other Taxes		December 31,
		2014	2013	2012
	Production and severance tax	$2,693,396	$2,403,263	$2,002,397
	Ad valorem tax	1,046,134	732,302	114,261
	Sales tax	62,864	180,498	40,146
	State franchise taxes	40,740	41,072	2,390
	Total	$3,843,134	$3,357,135	$2,159,194

ASSET_RETIREMENT_OBLIGATIONS_T

ASSET RETIREMENT OBLIGATIONS (Tables)	12 Months Ended
	Dec. 31, 2014
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligations		December 31,
		2014	2013
	Beginning of year balance	$10,697,679	$4,233,782
	Pyramid liabilities assumed in the merger	943,951	-
	Liabilities incurred during year	416,162	11,178,614
	Liabilities settled during year	-	-1,278,774
	Accretion expense	604,511	668,497
	Revisions in estimated cash flows	-174,533	-4,104,440
	End of year balance	$12,487,770	$10,697,679

RECEIVABLES_AND_PAYABLES_WITH_1

RECEIVABLES AND PAYABLES WITH AFFILIATES, CHIEF EXECUTIVE OFFICER AND EMPLOYEES (Tables)	12 Months Ended
	Dec. 31, 2014
Receivables And Payables With Affiliates Chief Executive Officer And Employees
Information with respect to related party transactions with affiliates		December 31,
		2014	2013
	Receivables from affiliates, CEO and employees:
	Current:
	Yuma CEO*	$174,720	$135,080
	Employees	141,357	20,000
		316,077	155,080
	Noncurrent:
	Yuma Gas Corporation	-	95,634
	Total	$316,077	$250,714

RELATED_PARTY_TRANSACTIONS_Tab

RELATED PARTY TRANSACTIONS (Tables)	12 Months Ended
	Dec. 31, 2014
Related Party Transactions [Abstract]
Working interests acquired			Working	Amount
	Year	Well, prospect or project	interest	paid
	2014	Anaconda Prospect	1.95%	$16,900
	2014	Gardner Island Well &	1.44%
		Main Pass 4 Facility	1.86%	$78,988
	2014	Austin Chalk (Additional W.I.)	1.00%	$16,000
	2013	Bell City East Prospect	0.71%	$5,330
	2013	Austin Chalk	1.00%	$9,412
	2013	Addison Acquisition	2.00%	$150,000

FAIR_VALUE_MEASUREMENTS_Tables

FAIR VALUE MEASUREMENTS (Tables)	12 Months Ended
	Dec. 31, 2014
Fair Value Disclosures [Abstract]
Fair value measurements by hierarchy		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
	Liabilities:
	Commodity derivatives	$ -	$ -	$ -	$ -
	Preferred stock derivative	-	-	-	-
	Total liabilities	$ -	$ -	$ -	$ -
		Fair value measurements at December 31, 2013
			Significant
		Quoted prices	other	Significant
		in active	observable	unobservable
		markets	inputs	inputs
		(Level 1)	(Level 2)	(Level 3)	Total
	Assets:
	Commodity derivatives – oil	$ -	$818,637	$ -	$818,637
	Total assets	$ -	$818,637	$ -	$818,637
	Liabilities:
	Commodity derivatives – gas	$ -	$472,564	$ -	$472,564
	Commodity derivatives – oil	-	423,217	-	423,217
	Preferred stock derivative	-	-	51,290,414	51,290,414
	Total liabilities	$ -	$895,781	$51,290,414	$52,186,195
Summary of value and the changes in the Company's assets and liabilities classified as Level 3		Preferred Stock
		Derivative Liability
	31-Dec-14	$ -
	31-Dec-13	51,290,414
	Total change	($51,290,414)

COMMODITY_DERIVATIVE_INSTRUMEN1

COMMODITY DERIVATIVE INSTRUMENTS (Tables)	12 Months Ended
	Dec. 31, 2014
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Commodity derivative instruments		2015		2016
		Settlement		Settlement
	NATURAL GAS (MMBtu):
	3-way collars
	Volume	2,377,371		1,122,533
	Ceiling sold price (call) *	$4.47		$4.35
	Floor purchased price (put) *	$4.00		$4.10
	Floor sold price (short put) *	$3.25		$3.25
	Swaps
	Volume	458,622		-
	Price *	$4.08		-
	Reverse Swaps
	Volume	293,234		-
	Price *	$4.33		-
	CRUDE OIL (Bbls):
	3-way collars
	Volume	89,512		70,263
	Ceiling sold price (call) *	$104.36		$106.39
	Floor purchased price (put) *	$86.49		$92.38
	Floor sold price (short put) *	$65.82		$72.38
	Put Spread
	Volume	27,588		-
	Floor purchased price (put) *	$90.00	**	-
	Floor sold price (short put) *	$75.00	**	-
Fair value and balance sheet location of each classification of commodity derivative contracts		Fair value as of December 31,
		2014		2013
	Asset commodity derivatives:
	Current assets	$6,413,935		$1,109,403
	Noncurrent assets	3,163,891		2,861,225
		9,577,826		3,970,628
	Liability commodity derivatives:
	Current liabilities	-3,075,398		-1,786,535
	Noncurrent liabilities	-1,760,782		-2,261,237
		-4,836,180		-4,047,772
	Total commodity derivative instruments	$4,741,646		($77,144)
Sales of natural gas and crude oil		Years Ended December 31,
		2014		2013	2012
	Sales of natural gas and crude oil	$38,659,392		$28,235,413	$19,684,132
	Gains (losses) realized on settled contracts for
	commodity derivatives	-1,420,217		-524	228,557
	Gains (losses) on ineffectiveness of
	cash flow hedges	-		-	712,681
	Gains (losses) on market value of
	open contracts for commodity derivatives	4,724,985		-231,886	544,237
	Amortized gains from benefit of sold
	qualified gas options	93,750		72,600	128,512
	Amortized losses from cost of purchased
	non-qualified oil calls	-		-	-16,004
	Total sales of natural gas and crude oil	$42,057,910		$28,075,603	$21,282,115
Reconciliation of the components of accumulated other comprehensive income (loss)		Years Ended December 31,
		2014			2013		2012
		Before tax		After tax	Before tax	After tax	Before tax	After tax
	Balance, beginning of period	$63,041		$38,770	$ 437,140	$268,841	($111,628)	($68,651)
	Net change in fair value	-		-	-	-	1,075,885	661,668
	Gains reclassified to income	-		-	-	-	-398,604	-245,141
	Amortized gains from benefit of sold
	qualified options realized in income	-93,755		-57,659	-72,600	-44,649	-128,513	-79,035
	Other reclassifications due to expired
	contracts previously subject to
	hedge accounting rules	93,805		57,690	-301,499	-185,422	-	-
	Balance, end of period	$63,091		$ 38,801	$63,041	$38,770	$437,140	$268,841

PREFERRED_STOCK_Tables

PREFERRED STOCK (Tables)	12 Months Ended
	Dec. 31, 2014
PREFERRED STOCK:
Shares and cash payments were issued to the existing preferred stockholders		30-Jun-13		31-Dec-13		30-Jun-14
		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		31-Dec-14		31-Dec-13
		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	757.337439	15,112,295
	Series B Preferred Stock	20,192	0.508185	757.337439	7,771,192

STOCKBASED_COMPENSATION_Tables

STOCK-BASED COMPENSATION (Tables)	12 Months Ended
	Dec. 31, 2014
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Summary of the Company's stock option activity, RSUs		Number of		Weighted
		unvested		average
		RSA		grant-date
		shares		fair value
	Unvested shares as of January 1, 2014	1,895,620		$3.22 per share
	Granted on March 6, 2014	196,151		$3.89 per share
	Granted on April 1, 2014	33,322		$3.89 per share
	Granted on May 20, 2014	341,559		$3.96 per share
	Vested	-107,291		$2.98 per share
	Forfeited	-406,690		$3.42 per share
	Unvested shares as of December 31, 2014	1,952,671		$3.40 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, 2013	105,000			$5.17	4.66	$ -
	Granted	-			-	-	-
	Exercised	-			-	-	-
	Forfeited	-			-	-	-
	Outstanding at December 31, 2014	105,000			$5.17	3.66	$ -
	Vested and expected to vest at
	31-Dec-14	105,000			$5.17	3.66	$ -
	Exercisable at December 31, 2014	105,000			$5.17	3.66	$ -
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		1.42	$5.40	5,000	$5.40
	$5.16		100,000		3.78	$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 RSUs as of January 1, 2014	119,659		$2.72 per share
	Granted on December 25, 2014	273,907		$1.80 per share
	Vested	-273,907		$3.17 per share
	Forfeited	-24,235		$2.72 per share
	Unvested RSUs as of December 31, 2014	95,424		$2.72 per share

EARNINGS_PER_COMMON_SHARE_Tabl

EARNINGS PER COMMON SHARE (Tables)	12 Months Ended
	Dec. 31, 2014
LOSS PER COMMON SHARE:
Potentially dilutive securities for the computation of diluted weighted average number of shares		Years Ended December 31, 2014
		2014	2013	2012
	Series A Preferred Stock	10,031,104	12,964,860	11,063,185
	Series B Preferred Stock	5,263,585	7,259,079	3,067,217
	Restricted Stock Awards	2,256,264	1,334,452	-
	Restricted Stock Units	105,643	91,762	-
		17,656,596	21,650,153	14,130,402

DEBT_AND_CHANGE_IN_BANKING_LIN1

DEBT AND CHANGE IN BANKING LINE AND AGENT BANK (Tables)	12 Months Ended
	Dec. 31, 2014
Debt And Change In Banking Line And Agent Bank Tables
Long term Debt		December 31,
		2014		2013
	Variable rate revolving credit facility payable to Société Générale,
	OneWest Bank, FSB, and View Point Bank, N.A., maturing
	May 20, 2017, secured by oil and natural gas properties held by
	Yuma Exploration and Production Company, Inc. and guaranteed
	by The Yuma Companies, Inc.	$22,900,000		$31,215,000
	Installment loan due February 28, 2015, originating from the
	financing of insurance premiums at 3.65% interest rate.	282,843		178,027
		23,182,843		31,393,027
	Less:  current portion	-282,843		-178,027
	Total long-term debt	$22,900,000		$31,215,000
Prime and LIBOR base rates	The prime and LIBOR base rates were increased by the following margins:
					LIBOR
	Borrowing base utilization		Prime margin		margin
	Utilization > 75%		1.25%		3.50%
	50% < utilization < 75%		1.00%		3.25%
	25% < utilization < 50%		0.75%		3.00%
	Utilization < 25%		0.50%		2.75%
	The amendment changed the interest rate margins as follows:
					LIBOR
	Borrowing base utilization		Prime margin		margin
	Utilization > 90%		2.00%		3.00%
	75% < utilization < 90%		1.75%		2.75%
	50% < utilization < 75%		1.50%		2.50%
	Utilization < 50%		1.25%		2.25%
	The new interest rate margins effective February 13, 2013 are as follows:
					LIBOR
	Borrowing base utilization		Prime margin		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,
		2014		2013		2012
	Credit facility	$1,109,153		$1,010,539		$714,826
	Credit facility commitment fees	70,813		56,092		48,836
	Amortization and write offs of credit facility loan costs	188,669		480,261		113,057
	Insurance installment loan	13,640		16,161		10,587
	Louisiana Mineral Board	-		32,383		-
	Other interest charges	3,275		4,056		3,867
	Capitalized interest	-1,059,350		-1,031,816		-681,090
	Total interest expense	$326,200		$567,676		$210,083
Aggregate principal payments	2015	$282,843
	2016	-
	2017	22,900,000
	2018	-
	2019	-

MERGER_WITH_PYRAMID_OIL_COMPAN1

MERGER WITH PYRAMID OIL COMPANY AND GOODWILL (Tables)	12 Months Ended
	Dec. 31, 2014
Business Combinations [Abstract]
Purchase price allocation		September 10,	Measurement	September 10,
		2014	Period	2014
		(as initially	Adjustment(i)	(as adjusted)
		reported)
	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	2012
		(Unaudited)
	Revenues	$46,238,208	$33,534,396	$26,879,236
	Net income (loss)	($3,388,094)	($7,834,907)	$2,426,418
	Net income (loss) per share:
	Basic	($0.07)	($0.19)	$0.06
	Diluted	($0.07)	($0.19)	$0.04

INCOME_TAXES_Tables

INCOME TAXES (Tables)	12 Months Ended
	Dec. 31, 2014
Income Tax Disclosure [Abstract]
Provisions for income taxes		Years Ended December 31,
		2014		2013		2012
	Current income taxes:
	Federal	$ -		$              -		$ -
	State	-		-		-
	Total	-		-		-
	Deferred income taxes (benefit):
	Federal	-2,377,192		2,705,688		2,744,068
	State	-176,662		374,584		354,241
	Total	-2,553,854		3,080,272		3,098,309
	Total taxes (benefit) on income	($2,553,854)		$ 3,080,272		$3,098,309
Deferred tax liabilities (assets)		Years Ended December 31,
		2014		2013
	Current:
	Deferred tax asset (stock-based compensation)	($1,196,378)		($146,964)
	Deferred tax asset (other asset)	-396,668		-
	Deferred tax liability (hedges)	1,819,119		-
	Total current deferred tax asset and liability	$226,073		($146,964)
	Noncurrent:
	Deferred tax liability (hedges)	$24,290		$24,262
	Deferred tax liability from excess of book basis over tax basis
	of certain assets including property, plant and equipment	30,081,222		23,116,582
		30,105,512		23,140,844
	Stock-based compensation	-9,344		-27,079
	Alternative minimum tax credit carryforwards	-121,686		-121,686
	Net operating loss (“NOL”) carryforwards	-15,585,820		-9,831,874
	Deferred tax asset	-15,716,850		-9,980,639
	Net deferred tax liability	$14,388,662		$13,160,205
Tax credit carryforwards and stock based compensation generated by the consolidated group	Year NOL		NOL		Year of
	generated		remaining		expiration
	2014		$11,759,312		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		$43,761,818
Income taxes		Years Ended December 31,
		2014		2013		2012
	Amount computed using the statutory rate	($7,972,651)		($10,489,441)		($4,084,907)
	Increase (reduction) in taxes resulting from:
	Non-deductible change in value of preferred
	stock derivative liability	5,486,895		9,190,496		5,984,476
	State taxes	-210,021		254,645		236,045
	Other	141,923		4,124,572		962,695
	Income tax expense (benefit)	($2,553,854)		$3,080,272		$3,098,309

OTHER_DISCLOSURES_Tables

OTHER DISCLOSURES (Tables)	12 Months Ended
	Dec. 31, 2014
Other Disclosures
Other Income (Expense)		December 31,
		2014	2013	2012
	Bank-mandated derivative instruments novation cost	$ -	($175,000)	$ -
	Louisiana sales tax settlement	-	-44,149	-
	Louisiana Mineral Board audit	-	-23,686	-
	Other	25,378	2,218	7,099
	Total	$25,378	($240,617)	$7,099
Other Receivables		December 31,
		2014	2013
	December 2014 settled oil derivative instruments	$407,003	$ -
	Debit balances for trade payables	187,031	163,802
	Refund from PPI for duplicate charges	89,544	89,544
	D&O insurance premium adjustment	16,356	-
	Blowout insurance premium adjustment	-	162,075
	Other	(1,943)	2,429
	Total	$697,991	$417,850
Prepayments		December 31,
		2014	2013
	Insurance	$536,410	$209,415
	Exploration and drilling costs	71,893	187,145
	Property taxes	56,992	-
	Software licenses	44,172	8,593
	Taxes and fees	21,882	-
	Software maintenance agreements	19,105	14,099
	Geological well database subscription	19,055	-
	Other subscriptions	6,355	13,560
	Services	4,530	-
	Other	1,840	1,179
	Total	$782,234	$433,991
Other Current Deferred Charges		December 31,
		2014	2013
	Loan fees	$189,409	$162,416
	Deferred premium on 2015 oil derivative instruments	153,389	-
	Total	$342,798	$162,416
Other Noncurrent Assets		December 31,
		2014	2013
	Loan fees	$262,200	$384,953
	Deferred offering costs	-	1,257,160
	Total	$262,200	$1,642,113
Other Accrued Liabilities		December 31,
		2014	2013
	Salaries and bonuses	$479,537	$184,072
	Ad valorem taxes	172,444	-
	Vacation	166,660	123,406
	Severance taxes	164,374	170,531
	Commodity hedge settlement	153,389	21,463
	Insurance	119,121	-
	Sales and use tax	81,661	98,818
	Accounting and audit	22,964	158,368
	Interest expense	9,327	46,946
	Pre-initial public offering expenses	-	259,223
	Fees for commodity hedging advisor	-	62,631
	Other	50,088	1,825
	Total	$1,419,565	$1,127,283

LEASES_Tables

LEASES (Tables)	12 Months Ended
	Dec. 31, 2014
Leases [Abstract]
Future minimum rentals under all noncancellable	2015	$567,480
	2016	575,868
	2017	561,106
	2018	2,264
	2019	-

SUBSEQUENT_EVENTS_Tables

SUBSEQUENT EVENTS (Tables)	12 Months Ended
	Dec. 31, 2014
Subsequent Events [Abstract]
Sales of Securities		Shares	Net Proceeds
	Common Stock	221,159	$328,008
	Series A Preferred Stock	37,769	$746,345
	Totals		$1,074,353

SUPPLEMENTARY_INFORMATION_ON_O1

SUPPLEMENTARY INFORMATION ON OIL AND NATURAL GAS EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES (UNAUDITED) (Tables)	12 Months Ended
	Dec. 31, 2014
Costs Incurred		December 31,
		2014	2013	2012
	Property acquisition costs - unproved	$1,105,782	$3,865,932	$17,025,756
	Property acquisition costs - proved	3,349,473	8,539,134	1,800,385
	Sales proceeds - unproved	-359,667	-679,266	-1,386,649
	Sales proceeds - proved	-307,600	-718,000	-
	Exploration costs	426,909	2,504,087	4,931,623
	Development costs	20,139,409	11,910,179	7,699,903
	Capitalized asset retirements costs	241,629	5,795,400	173,432
	Total costs incurred	$24,595,935	$31,217,466	$30,244,450
Capitalized Costs Relating to Oil and Gas Producing Activities		December 31,
		2014	2013
	Oil and gas properties, full cost method:
	Not subject to amortization:
	Prospect inventory	$14,913,126	$14,587,986
	Property acquisition costs - unproved	8,623,344	8,202,369
	Well development costs - unproved	2,170,582	1,249,718
	Subject to amortization:
	Property acquisition costs - proved	50,744,401	36,999,813
	Well development costs - proved	74,440,227	56,460,276
	Capitalized costs - unsuccessful	52,539,407	50,849,905
	Capitalized asset retirement costs	8,806,828	8,565,199
	Total capitalized costs	212,237,915	176,915,266
	Less accumulated depreciation, depletion and amortization	-103,929,493	-84,438,840
	Net capitalized costs	$108,308,422	$92,476,426
Discounted future net cash flows		December 31,
		2014	2013	2012
	Future cash inflows	$1,339,372,300	$1,450,469,000	$823,280,251
	Future oil and natural gas operating expenses	-322,298,300	-334,883,800	-151,140,007
	Future development costs	-405,900,900	-424,256,900	-209,618,885
	Future income tax expenses	(133,467,940)	-163,704,120	-111,946,653
	Future net cash flows	477,705,160	527,624,180	350,574,706
	10% annual discount for estimating timing of
	cash flows	-183,249,968	-202,270,201	-139,021,820
	Standardized measure of discounted future
	net cash flows	$294,455,192	$325,353,979	$211,552,886
Change in Standardized Measure		2014	2013	2012
	Changes due to current year operation:
	Sales of oil and natural gas, net of oil and
	natural gas operating expenses	($25,270,455)	($17,255,824)	($13,250,556)
	Extensions and discoveries	2,743,800	37,750,617	40,013,415
	Purchases of oil and gas properties	12,827,533	215,427,459	177,412,984
	Development costs incurred during the period
	that reduced future development costs	9,178,400	100,500	5,432,652
	Changes due to revisions in standardized variables:
	Prices and operating expenses	-42,125,763	-30,773,529	-37,028,314
	Income taxes	19,303,313	-38,340,467	-40,922,146
	Estimated future development costs	7,218,529	32,430,504	-5,173,677
	Quantity estimates	-21,028,476	-107,070,514	-12,905,019
	Sale of reserves in place	-	-	-
	Accretion of discount	43,124,820	27,910,664	11,055,659
	Production rates, timing and other1	-36,870,488	-6,378,317	1,834,021
	Net change	-30,898,787	113,801,093	126,469,019
	Beginning of year	325,353,979	211,552,886	85,083,867
	End of year	$294,455,192	$325,353,979	$211,552,886
Barrels of oil and condensate [Member]
Reserve		2014	2013	2012
	Barrels of oil and condensate:
	Proved developed and undeveloped reserves:
	Beginning of year	14,381,960	7,739,964	1,839,425
	Revisions of previous estimates	-565,143	-1,142,654	(132,352)
	Purchases of oil and gas properties	472,132	7,959,600	5,976,234
	Extensions and discoveries	51,993	92,152	225,063
	Sale of oil and gas properties	-	-	-
	Production	-329,599	(267,102)	(168,406)
	End of year	14,011,343	14,381,960	7,739,964
	Proved developed reserves - January 1,	2,099,701	1,474,015	1,236,002
	Proved developed reserves - December 31,	2,347,482	2,099,701	1,474,015
	Proved undeveloped reserves - January 1,	12,282,259	6,265,949	603,423
	Proved undeveloped reserves - December 31,	11,663,861	12,282,259	6,265,949
Thousands of cubic feet of natural gas [Member]
Reserve		2014	2013	2012
	Thousands of cubic feet of natural gas:
	Proved developed and undeveloped reserves:
	Beginning of year	38,372,369	31,071,137	17,020,496
	Revisions of previous estimates	-479,438	(8,281,139)	(463,712)
	Purchases of oil and gas properties	81,177	16,495,803	12,931,203
	Extensions and discoveries	-	362,806	2,163,825
	Sale of oil and gas properties	-	-	-
	Production	-2,714,586	(1,276,238)	(580,675)
	End of year	35,259,522	38,372,369	31,071,137
	Proved developed reserves - January 1,	10,316,516	10,156,754	5,287,966
	Proved developed reserves - December 31,	7,786,537	10,316,516	10,156,754
	Proved undeveloped reserves - January 1,	28,055,853	20,914,383	11,732,530
	Proved undeveloped reserves - December 31,	27,472,985	28,055,853	20,914,383

ORGANIZATION_CONSOLIDATION_AND2

ORGANIZATION, CONSOLIDATION AND NATURE OF BUSINESS (Details)	12 Months Ended
	Dec. 31, 2014
The Yuma Companies, Inc. [Member]
Company name	The Yuma Companies, Inc.
Reference	BYCIB
State of incorporation	Delaware
Date of incorporation	30-Oct-96
Yuma Exploration and Production Company, Inc. [Member]
Company name	Yuma Exploration and Production Company, Inc.
Reference	BExplorationB
State of incorporation	Delaware
Date of incorporation	16-Jan-92
Yuma Petroleum Company [Member]
Company name	Yuma Petroleum Company
Reference	BPetroleumB
State of incorporation	Delaware
Date of incorporation	19-Dec-91
Texas Southeastern Gas Marketing Company [Member]
Company name	Texas Southeastern Gas Marketing Company
Reference	BTSMB
State of incorporation	Texas
Date of incorporation	12-Sep-96
Pyramid Oil LLC [Member]
Company name	Pyramid Oil LLC
Reference	BPOLB
State of incorporation	California
Date of incorporation	8-Aug-14
Pyramid Delaware Merger Subsidiary, Inc. [Member]
Company name	Pyramid Delaware Merger Subsidiary, Inc.
Reference	BPDMSB
State of incorporation	Delaware
Date of incorporation	4-Feb-14

SUMMARY_OF_SIGNIFICANT_ACCOUNT3

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details) (USD $)	12 Months Ended
	Dec. 31, 2014
Leasehold acquisition cost	$21,105,420
Exploration and development cost	2,134,237
Capitalized interest	2,467,395
Total	25,707,052
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
2012 [Member]
Leasehold acquisition cost	15,349,192
Exploration and development cost	111,910
Capitalized interest	670,190
Total	16,131,292
Prior Year [Member]
Leasehold acquisition cost	3,897,844
Exploration and development cost	71,455
Capitalized interest	357,779
Total	$4,327,078

SUMMARY_OF_SIGNIFICANT_ACCOUNT4

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details 1) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Land	2,469,000	$0
Office business machines	1,361,149	1,350,568
Drilling and operating equipment	982,010	0
Furniture and fixtures	412,215	383,585
Automotive	351,707	0
Office leasehold improvements	332,607	332,607
Buildings and improvements	326,000	0
Total other property and equipment	6,234,688	2,066,760
Less: Accumulated depreciation and leasehold improvement amortization	-1,909,352	-1,822,925
Net other property and equipment	4,325,336	$243,835
Land [Member]
Estimated useful life in years	0 years
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_ACCOUNT5

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details 2) (USD $)	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Accounting Policies [Abstract]
Production and severance tax	$2,693,396	$2,403,263	$2,002,397
Ad valorem tax	1,046,134	732,302	114,261
Sales tax	62,864	180,498	40,146
State franchise taxes	40,740	41,072	2,390
Total	$3,843,134	$3,357,135	$2,159,194

SUMMARY_OF_SIGNIFICANT_ACCOUNT6

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details Textual) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Summary Of Significant Accounting Policies Details Textual
Allowance for doubtful accounts	$138,960	$55,000
Depreciation, depletion and amortization rate per boe	24.92	23.87	19.84
Depreciation, depletion and amortization expense for oil and natural gas properties	19,490,653	11,927,872	4,956,196
Capitalized interest associated with line of credit	1,059,350	1,031,816	681,090
Capitalized internal costs	3,442,095	2,702,952	2,589,342
General and administrative expense reimbursements	0	42,329	172,173
Depreciation and leasehold improvement amortization expense	$174,338	$149,496	$117,874

ASSET_RETIREMENT_OBLIGATIONS_D

ASSET RETIREMENT OBLIGATIONS (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Asset Retirement Obligation Disclosure [Abstract]
Beginning of year balance	$10,697,679	$4,233,782
Pyramid liabilities assumed in the merger	943,951	0
Liabilities incurred during year	416,162	11,178,614
Liabilities settled during year	0	-1,278,774
Accretion expense	604,511	668,497	265,323
Revisions in estimated cash flows	-174,533	-4,104,440
End of year balance	$12,487,770	$10,697,679	$4,233,782

ASSET_RETIREMENT_OBLIGATIONS_D1

ASSET RETIREMENT OBLIGATIONS (Details Narrative) (USD $)	12 Months Ended
	Dec. 31, 2013
Asset Retirement Obligation Disclosure [Abstract]
Addison acquisition	$6,043,412
Addison ARO estimate	10,967,986
Costs reevaluated	$4,924,574

RECEIVABLES_AND_PAYABLES_WITH_2

RECEIVABLES AND PAYABLES WITH AFFILIATES, CHIEF EXECUTIVE OFFICER AND EMPLOYEES (Details) (USD $)	Dec. 31, 2014		Dec. 31, 2013
Current:	$316,077		$155,080
Noncurrent:	316,077		250,714
Yuma CEO [Member]
Current:	174,720	[1]	135,080
Employee [Member]
Current:	141,357		20,000
Yuma Gas Corporation [Member]
Noncurrent:	$0		$95,634
[1]	CEO paid balances outstanding at December 31, 2014; balance represents December 2014 charges billed subsequent to year-end under accrual accounting.

RELATED_PARTY_TRANSACTIONS_Det

RELATED PARTY TRANSACTIONS (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Anaconda Prospect [Member]
Working interest	1.95%
Amount paid	$16,900
Gardner Island Well [Member]
Working interest	1.44%
Main Pass 4 Facility [Member]
Working interest	1.86%
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		0.71%
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, 2014	Dec. 31, 2013
Total assets	$4,741,646	$818,637
Derivative liability	0	51,290,414
Total Liabilities	0	52,186,195
Commodity derivatives oil
Commodity derivatives	2,858,387	818,637
Derivative liability		423,217
Commodity derivatives gas
Commodity derivatives	1,883,259
Derivative liability		472,564
Preferred stock derivative liability
Derivative liability	0	51,290,414
Commodity derivatives
Derivative liability	0
Level 1
Total assets	0
Total Liabilities	0
Level 1 | Commodity derivatives oil
Commodity derivatives
Derivative liability
Level 1 | Commodity derivatives gas
Commodity derivatives
Derivative liability
Level 1 | Preferred stock derivative liability
Derivative liability	0
Level 1 | Commodity derivatives
Derivative liability	0
Level 2
Total assets	4,741,646	818,637
Total Liabilities	0	895,781
Level 2 | Commodity derivatives oil
Commodity derivatives	2,858,387	818,637
Derivative liability		423,217
Level 2 | Commodity derivatives gas
Commodity derivatives	1,883,259
Derivative liability		472,564
Level 2 | Preferred stock derivative liability
Derivative liability	0
Level 2 | Commodity derivatives
Derivative liability	0
Level 3
Total assets	0
Total Liabilities	0	51,290,414
Level 3 | Commodity derivatives oil
Commodity derivatives
Derivative liability
Level 3 | Commodity derivatives gas
Commodity derivatives
Derivative liability
Level 3 | Preferred stock derivative liability
Derivative liability	0	51,290,414
Level 3 | Commodity derivatives
Derivative liability	$0

FAIR_VALUE_MEASUREMENTS_Detail1

FAIR VALUE MEASUREMENTS (Details 1) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Fair Value Measurements Details 1
Preferred Stock Derivative Liability	$0	$51,290,414
Total change	($51,290,414)

COMMODITY_DERIVATIVE_INSTRUMEN2

COMMODITY DERIVATIVE INSTRUMENTS (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
Asset commodity derivatives:
Current assets	$6,413,935	$1,109,403
Noncurrent assets	3,163,891	2,861,225
Total	9,577,826	3,970,628
Liability commodity derivatives:
Current liabilities	-3,075,398	-1,786,535
Noncurrent liabilities	-1,760,782	-2,261,237
Total	-4,836,180	-4,047,772
Total commodity derivative instruments	$4,741,646	($77,144)

COMMODITY_DERIVATIVE_INSTRUMEN3

COMMODITY DERIVATIVE INSTRUMENTS (Details 1) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
C. Commodity Derivative Instruments Details 1
Sales of natural gas and crude oil	$38,659,392	$28,235,413	$19,684,132
Gains (losses) realized on settled contracts for commodity derivatives	-1,420,217	-524	228,557
Gains (losses) on ineffectiveness of cash flow hedges	0	0	712,681
Gains (losses) on market value of open contracts for commodity derivatives	4,724,985	-231,886	544,237
Amortized gains from benefit of sold qualified gas options	93,750	72,600	128,512
Amortized losses from cost of purchased non-qualified oil calls	0	0	-16,004
Total sales of natural gas and crude oil	$42,057,910	$28,075,603	$21,282,115

COMMODITY_DERIVATIVE_INSTRUMEN4

COMMODITY DERIVATIVE INSTRUMENTS (Details 2) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Balance, beginning of period, before tax	$63,041	$437,140	($111,628)
Balance, beginning of period, after tax	38,770	268,841	-68,651
Net change in fair value, before tax	0	0	1,075,885
Net change in fair value, after tax	0	0	661,668
Gains reclassified to income, befor tax	0	0	-398,604
Gains reclassified to income, after tax	0	0	-245,141
Amortized gains from benefit of sold qualified options realized in income, before tax	-93,755	-72,600	-128,513
Amortized gains from benefit of sold qualified options realized in income, after tax	-57,659	-44,649	-79,035
Other reclassifications due to expired contracts previously subject to hedge accounting rules, before tax	93,805	-301,499	0
Other reclassifications due to expired contracts previously subject to hedge accounting rules, after tax	57,690	-185,422	0
Balance, end of period, before tax	63,091	63,041	437,140
Balance, end of period, after tax	$38,801	$38,770	$268,841

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) (USD $)	0 Months Ended
	Sep. 15, 2014
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			0 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Sep. 15, 2014
Dividends paid in kind (Series A and Series B)	$4,133,380	$5,412,281	$0
Series A Preferred Stock [Member]
Additional preferred shares		1,033		893
Dividends paid in kind (Series A and Series B)		3,779,521		3,299,603
Series B Preferred Stock [Member]
Additional preferred shares		1,066		536
Dividends paid in kind (Series A and Series B)		$1,632,760		$833,777

PREFERRED_STOCK_Details_3

PREFERRED STOCK (Details 3)	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	0	19,656

PREFERRED_STOCK_Details_4

PREFERRED STOCK (Details 4)	0 Months Ended
	Sep. 15, 2014	Dec. 31, 2014
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	757.337439
Number of shares		15,112,295
Series B Preferred Stock [Member]
Number of preferred shares		20,192
Conversion ratio to Yuma Co. common stock	0.508185
Conversion ratio to Company common stock	757.337439
Number of shares		7,771,192

PREFERRED_STOCK_Details_Narrat

PREFERRED STOCK (Details Narrative) (USD $)	Dec. 31, 2013
Series A derivative [Member]
Fair value of derivative, per share	$2,581
Fair value of derivative	$40,361,678
Series B derivative [Member]
Fair value of derivative, per share	$556
Fair value of derivative	$10,928,736

STOCKBASED_COMPENSATION_Detail

STOCK-BASED COMPENSATION (Details) (RSA, USD $)	12 Months Ended
	Dec. 31, 2014
RSA
Unvested shares as of January 1, 2014	1,895,620
Granted on March 6, 2014	196,151
Granted on April 1, 2014	33,322
Granted on May 20, 2014	341,559
Vested	-107,291
Forfeited	-406,690
Unvested shares as of December 31, 2014	1,952,671
Weighted Average Grant-Date Fair Value
Beginning of period	$3.22
Granted on March 6, 2014	$3.89
Granted on April 1, 2014	$3.89
Granted on May 20, 2014	$3.96
Vested	$2.98
Forfeited	$3.42
End of period	$3.40

STOCKBASED_COMPENSATION_Detail1

STOCK-BASED COMPENSATION (Details 1) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Number of Options Outstanding, Beginning	105,000
Number of Options Granted
Number of Options Exercised
Number of Options Forfeited
Number of Options Outstanding, Ending	105,000	105,000
Vested and expected to vest December 31, 2014	105,000
Number of shares Options Exercisable	105,000
Weighted Average Exercise Price Outstanding	$5.17
Weighted Average Exercise Price Granted
Weighted Average Exercise Price Exercised
Weighted Average Exercise Price Forfeited
Weighted Average Exercise Price Outstanding	$5.17	$5.17
Weighted Average Exercise Price Vested and expected to vest December 31, 2014	$5.17
Weighted Average Exercise Price Exercisable	$5.17
Weighted Average Remaining Contractual Life (in years) Outstanding	3 years 7 months 28 days	4 years 7 months 28 days
Weighted Average Remaining Contractual Life (in years) Vested and expected to vest at	3 years 7 months 28 days
Weighted Average Remaining Contractual Life (in years) Exercisable	3 years 7 months 28 days
Aggregate Intrinsic Value Outstanding, Beginning	$0
Aggregate Intrinsic Value Granted	$0
Aggregate Intrinsic Value Exercised	0
Aggregate Intrinsic Value Forfeited	$0
Aggregate Intrinsic Value Outstanding, Ending	0	0
Aggregate Intrinsic Value Vested and expected to vest at	0
Aggregate Intrinsic Value Exercisable at December 31, 2014	$0

STOCKBASED_COMPENSATION_Detail2

STOCK-BASED COMPENSATION (Details 2) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Number of Options Outstanding, Ending	105,000	105,000
Weighted average remaining life (years) Options Outstanding	3 years 7 months 28 days	4 years 7 months 28 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 year 5 months 1 day
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	3 years 9 months 11 days
Weighted Average Exercise Price Outstanding	$5.16
Number of shares Options Exercisable	100,000
Weighted Average Exercise Price Exercisable	$5.16

STOCKBASED_COMPENSATION_Detail3

STOCK-BASED COMPENSATION (Details 3) (RSUs, USD $)	12 Months Ended
	Dec. 31, 2014
RSUs
Unvested shares as of January 1, 2014	119,659
Granted on December 25, 2014	273,907
Vested	-273,907
Forfeited	-24,235
Unvested shares as of December 31, 2014	95,424
Beginning of period	$2.72
Granted on December 25, 2014	$1.80
Vested	$3.17
Forfeited	$2.72
End of period	$2.72

EARNINGS_PER_COMMON_SHARE_Deta

EARNINGS PER COMMON SHARE (Details)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
LOSS PER COMMON SHARE:
Series A Preferred Stock	10,031,104	12,964,860	11,063,185
Series B Preferred Stock	5,263,585	7,259,079	3,067,217
Restricted Stock Awards	2,256,264	1,334,452	0
Restricted Stock Units	105,643	91,762	0
Total	17,656,596	21,650,153	14,130,402

DEBT_AND_CHANGE_IN_BANKING_LIN2

DEBT AND CHANGE IN BANKING LINE AND AGENT BANK (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
Total Debt	$23,182,843	$31,393,027
Less: current portion	-282,843	-178,027
Total long-term debt	22,900,000	31,215,000
Variable rate revolving credit facility payable [Member]
Total Debt	22,900,000	31,215,000
Installment loan due February 28, 2015 [Member]
Total Debt	$282,843	$178,027

DEBT_AND_CHANGE_IN_BANKING_LIN3

DEBT AND CHANGE IN BANKING LINE AND AGENT BANK (Details 1)	Aug. 10, 2011	Sep. 24, 2012	Feb. 13, 2013
Utilization 75 percent [Member]
Prime margin	1.25%
Libor margin	3.50%
Utilization 50 to 75 percent [Member]
Prime margin	1.00%
Libor margin	3.25%
Utilization 25 to 50 percent [Member]
Prime margin	0.75%
Libor margin	3.00%
Utilization 25 percent [Member]
Prime margin	0.50%
Libor margin	2.75%
Utilization 90 percent [Member]
Prime margin		2.00%
Libor margin		3.00%
Utilization 75 to 90 percent [Member]
Prime margin		1.75%
Libor margin		2.75%
Utilization 75 to 50 percent [Member]
Prime margin		1.50%
Libor margin		2.50%
Utilization 50 percent [Member]
Prime margin		1.25%
Libor margin		2.25%
Utilization 90 percent [Member]
Prime margin			2.25%
Libor margin			3.25%
75 percent utilization 90 percent [Member]
Prime margin			2.00%
Libor margin			3.00%
50 percent utilization 75 percent [Member]
Prime margin			1.75%
Libor margin			2.75%
25 percent utilization 50 percent [Member]
Prime margin			1.50%
Libor margin			2.50%
Utilization 25 percent [Member]
Prime margin			1.25%
Libor margin			2.25%

DEBT_AND_CHANGE_IN_BANKING_LIN4

DEBT AND CHANGE IN BANKING LINE AND AGENT BANK (Details 2) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Debt Disclosure [Abstract]
Credit facility	$1,109,153	$1,010,539	$714,826
Credit facility commitment fees	70,813	56,092	48,836
Amortization and write offs of credit facility loan costs	188,669	480,261	113,057
Insurance installment loan	13,640	16,161	10,587
Louisiana Mineral Board	0	32,383	0
Other interest charges	3,275	4,056	3,867
Capitalized interest	-1,059,350	-1,031,816	-681,090
Total interest expense	$326,200	$567,676	$210,083

DEBT_AND_CHANGE_IN_BANKING_LIN5

DEBT AND CHANGE IN BANKING LINE AND AGENT BANK (Details 3) (USD $)	Dec. 31, 2014
Debt And Change In Banking Line And Agent Bank Tables
2015	$282,843
2016	0
2017	22,900,000
2018	0
2019	$0

MERGER_WITH_PYRAMID_OIL_COMPAN2

MERGER WITH PYRAMID OIL COMPANY AND GOODWILL (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013	Sep. 10, 2014
Estimated Fair Value of Assets Acquired:
Goodwill(i)	$5,349,988	$0
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_COMPAN3

MERGER WITH PYRAMID OIL COMPANY AND GOODWILL (Details 1) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Business Combinations [Abstract]
Revenues	$46,238,208	$33,534,396	$26,879,236
Net income (loss)	($3,388,094)	($7,834,907)	$2,426,418
Net income (loss) per share:
Basic	($0.07)	($0.19)	$0.06
Diluted	($0.07)	($0.19)	$0.04

MERGER_WITH_PYRAMID_OIL_COMPAN4

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, 2014	Dec. 31, 2013	Dec. 31, 2012
Current income taxes:
Federal	$0	$0	$0
State	0	0	0
Total	0	0	0
Deferred income taxes (benefit):
Federal	-2,377,192	2,705,688	2,744,068
State	-176,662	374,584	354,241
Total	-2,553,854	3,080,272	3,098,309
Income tax expense (benefit)	($2,553,854)	$3,080,272	$3,098,309

INCOME_TAXES_Details_1

INCOME TAXES (Details 1) (USD $)	Dec. 31, 2014	Dec. 31, 2013
Current:
Deferred tax asset (stock-based compensation)	($1,196,378)	($146,964)
Deferred tax asset (other asset)	-396,668	0
Deferred tax liability (hedges)	1,819,119	0
Total current deferred tax asset and liability	226,073	-146,964
Noncurrent:
Deferred tax liability (hedges)	24,290	24,262
Deferred tax liability from excess of book basis over tax basis of certain assets including property, plant and equipment	30,081,222	23,116,582
Total non current deferred tax asset and liability	30,105,512	23,140,844
Stock based compensation	-9,344	-27,079
Alternative minimum tax credit carryforwards	-121,686	-121,686
Net operating loss ("NOL") carryforwards	-15,585,820	-9,831,874
Deferred tax asset	-15,716,850	-9,980,639
Net deferred tax liability	$14,388,662	$13,160,205

INCOME_TAXES_Details_2

INCOME TAXES (Details 2) (USD $)	12 Months Ended
	Dec. 31, 2014
NOL remaining	$43,761,818
Year NOL generated 2014 [Member]
NOL remaining	11,759,312
Year of expiration	31-Dec-34
Year NOL generated 2013 [Member]
NOL remaining	9,417,693
Year of expiration	31-Dec-33
Year NOL generated 2012 [Member]
NOL remaining	8,082,421
Year of expiration	31-Dec-32
Year NOL generated 2011 [Member]
NOL remaining	5,511,938
Year of expiration	31-Dec-31
Year NOL generated 2009 [Member]
NOL remaining	4,844,318
Year of expiration	31-Dec-29
Year NOL generated 2007 [Member]
NOL remaining	1,095,474
Year of expiration	31-Dec-27
Year NOL generated 2002 [Member]
NOL remaining	$3,050,662
Year of expiration	31-Dec-22

INCOME_TAXES_Details_3

INCOME TAXES (Details 3) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Income Taxes Details 3
Amount computed using the statutory rate	($7,972,651)	($10,489,441)	($4,084,907)
Increase (reduction) in taxes resulting from:
Non-deductible change in value of preferred stock derivative liability	5,486,895	9,190,496	5,984,476
State taxes	-210,021	254,645	236,045
Other	141,923	4,124,572	962,695
Income tax expense (benefit)	($2,553,854)	$3,080,272	$3,098,309

EMPLOYEE_BENEFIT_PLANS_Details

EMPLOYEE BENEFIT PLANS (Details Textual) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Compensation and Retirement Disclosure [Abstract]
Defined Contribution Plan, Employer Matching Contribution, Percent	4.00%
Defined Contribution Plan, Employer Contribution	$38,827	$33,412
Accrued liability for compensated absences	166,660	123,406
Future employment contract salary commitments	$3,160,373

OTHER_DISCLOSURES_Details

OTHER DISCLOSURES (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Other Income (Expense)	$25,378	($240,617)	$7,099
Bank-Mandated Derivative Instruments Novation Cost [Member]
Other Income (Expense)	0	-175,000	0
Louisiana Sales Tax Settlement [Member]
Other Income (Expense)	0	-44,149	0
Louisiana Mineral Board Audit [Member]
Other Income (Expense)	0	-23,686	0
Other [Member]
Other Income (Expense)	$25,378	$2,218	$7,099

OTHER_DISCLOSURES_Details_1

OTHER DISCLOSURES (Details 1) (USD $)	Dec. 31, 2014	Dec. 31, 2013
Other Receivables	$697,991	$417,850
December 2014 Settled Oil Derivative Instruments [Member]
Other Receivables	407,003	0
Debit Balances For Trade Payables [Member]
Other Receivables	187,031	163,802
Refund From PPI For Duplicate Charges [Member]
Other Receivables	89,544	89,544
D&O Insurance Premium Adjustment [Member]
Other Receivables	16,356	0
Blowout Insurance Premium Adjustment [Member]
Other Receivables	0	162,075
Other [Member]
Other Receivables	($1,943)	$2,429

OTHER_DISCLOSURES_Details_2

OTHER DISCLOSURES (Details 2) (USD $)	Dec. 31, 2014	Dec. 31, 2013
Prepayments	$782,234	$433,991
Insurance [Member]
Prepayments	536,410	209,415
Exploration And Drilling Costs [Member]
Prepayments	71,893	187,145
Property Taxes [Member]
Prepayments	56,992	0
Software Licenses [Member]
Prepayments	44,172	8,593
Taxes And Fees [Member]
Prepayments	21,882	0
Software Maintenance Agreements [Member]
Prepayments	19,105	14,099
Geological Well Database Subscription [Member]
Prepayments	19,055	0
Other Subscriptions [Member]
Prepayments	6,355	13,560
Services [Member]
Prepayments	4,530	0
Other [Member]
Prepayments	$1,840	$1,179

OTHER_DISCLOSURES_Details_3

OTHER DISCLOSURES (Details 3) (USD $)	Dec. 31, 2014	Dec. 31, 2013
Other Current Deferred Charges	$342,798	$162,416
Loan Fees [Member]
Other Current Deferred Charges	189,409	162,416
Deferred Premium On 2015 Oil Derivative Instruments [Member]
Other Current Deferred Charges	$153,389	$0

OTHER_DISCLOSURES_Details_4

OTHER DISCLOSURES (Details 4) (USD $)	Dec. 31, 2014	Dec. 31, 2013
Other Noncurrent Assets	$262,200	$1,642,113
Loan Fees [Member]
Other Noncurrent Assets	262,200	384,953
Deferred Offering Costs [Member]
Other Noncurrent Assets	$0	$1,257,160

OTHER_DISCLOSURES_Details_5

OTHER DISCLOSURES (Details 5) (USD $)	Dec. 31, 2014	Dec. 31, 2013
Other Accrued Liabilities	$1,419,565	$1,127,283
Salaries And Bonuses [Member]
Other Accrued Liabilities	479,537	184,072
Ad Valorem Taxes [Member]
Other Accrued Liabilities	172,444	0
Vacation [Member]
Other Accrued Liabilities	166,660	123,406
Severance Taxes [Member]
Other Accrued Liabilities	164,374	170,531
Commodity Hedge Settlement [Member]
Other Accrued Liabilities	153,389	21,463
Insurance [Member]
Other Accrued Liabilities	119,121	0
Sales And Use Tax [Member]
Other Accrued Liabilities	81,661	98,818
Accounting And Audit [Member]
Other Accrued Liabilities	22,964	158,368
Interest Expense [Member]
Other Accrued Liabilities	9,327	46,946
Pre-Initial Public Offering Expenses [Member]
Other Accrued Liabilities	0	259,223
Fees For Commodity Hedging Advisor [Member]
Other Accrued Liabilities	0	62,631
Other [Member]
Other Accrued Liabilities	$50,088	$1,825

SALES_TO_MAJOR_CUSTOMERS_Detai

SALES TO MAJOR CUSTOMERS (Details Textual))	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Sales To Major Customers Details Textual
Number of major customer	4
Oil and natural gas sales to major customers (percent)	74.00%	78.00%	79.00%

LEASES_Details

LEASES (Details) (USD $)	Dec. 31, 2014
Future minimum rentals under all noncancellable operating leases
2015	$567,480
2016	575,868
2017	561,106
2018	2,264
2019	$0

LEASES_Details_Textual

LEASES (Details Textual) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
	sqft
Leases Details Textual
Primary office space	15,180
Primary office space rent	$22,770
Parking space rent	50
Lease term expires	31-Dec-17
Aggregate rental expense	$531,127	$534,275	$378,192

SUBSEQUENT_EVENTS_Details

SUBSEQUENT EVENTS (Details) (Subsequent Event [Member], USD $)	1 Months Ended
	Mar. 23, 2015
Shares	0
Net Proceeds	$1,074,353
COMMON STOCK
Shares	221,159
Net Proceeds	328,008
Series A Preferred Stock [Member]
Shares	37,769
Net Proceeds	$746,345

SUPPLEMENTARY_INFORMATION_ON_O2

SUPPLEMENTARY INFORMATION ON OIL AND NATURAL GAS EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES (UNAUDITED) (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Property acquisition costs - unproved	$1,105,782	$3,865,932	$17,025,756
Property acquisition costs - proved	3,349,473	8,539,134	1,800,385
Sales proceeds - unproved	-359,667	-679,266	-1,386,649
Sales proceeds - proved	-307,600	-718,000	0
Exploration costs	426,909	2,504,087	4,931,623
Development costs	20,139,409	11,910,179	7,699,903
Capitalized asset retirements costs	241,629	5,795,400	173,432
Total costs incurred	$24,595,935	$31,217,466	$30,244,450

SUPPLEMENTARY_INFORMATION_ON_O3

SUPPLEMENTARY INFORMATION ON OIL AND NATURAL GAS EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES (UNAUDITED) (Details 1) (USD $)	Dec. 31, 2014	Dec. 31, 2013
Oil and gas properties, full cost method Not subject to amortization:
Prospect inventory	$14,913,126	$14,587,986
Property acquisition costs - unproved	8,623,344	8,202,369
Well development costs - unproved	2,170,582	1,249,718
Subject to amortization:
Property acquisition costs - proved	50,744,401	36,999,813
Well development costs - proved	74,440,227	56,460,276
Capitalized costs - unsuccessful	52,539,407	50,849,905
Capitalized asset retirement costs	8,806,828	8,565,199
Total capitalized costs	212,237,915	176,915,266
Less accumulated depreciation, depletion and amortization	-103,929,493	-84,438,840
Net capitalized costs	$108,308,422	$92,476,426

SUPPLEMENTARY_INFORMATION_ON_O4

SUPPLEMENTARY INFORMATION ON OIL AND NATURAL GAS EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES (UNAUDITED) (Details 2)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
	MBbls	MBbls	MBbls
Oil [Member]
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves, Beginning of year	14,381,960	7,739,964	1,839,425
Revisions of Previous Estimates	-565,143	-1,142,654	-132,352
Purchases of oil and gas properties	472,132	7,959,600	5,976,234
Extensions and discoveries	51,993	92,152	225,063
Sale of oil and gas properties	0	0	0
Production	-329,599	-267,102	-168,406
Proved developed and undeveloped reserves, End of year	14,011,343	14,381,960	7,739,964
Proved developed reserves, Beginning of the year	2,099,701	1,474,015	1,236,002
Proved developed reserves, End of year	2,347,482	2,099,701	1,474,015
Proved undeveloped reserves, Beginning of year	12,282,259	6,265,949	603,423
Proved undeveloped reserves, End of year	11,663,861	12,282,259	6,265,949
Natural Gas [Member]
Reserve Quantities [Line Items]
Proved developed and undeveloped reserves, Beginning of year	38,372,369	31,071,137	17,020,496
Revisions of Previous Estimates	-479,438	-8,281,139	-463,712
Purchases of oil and gas properties	81,177	16,495,803	12,931,203
Extensions and discoveries	0	362,806	2,163,825
Sale of oil and gas properties	0	0	0
Production	-2,714,586	-1,276,238	-580,675
Proved developed and undeveloped reserves, End of year	35,259,522	38,372,369	31,071,137
Proved developed reserves, Beginning of the year	10,316,516	10,156,754	5,287,966
Proved developed reserves, End of year	7,786,537	10,316,516	10,156,754
Proved undeveloped reserves, Beginning of year	28,055,853	20,914,383	11,732,530
Proved undeveloped reserves, End of year	27,472,985	28,055,853	20,914,383

SUPPLEMENTARY_INFORMATION_ON_O5

SUPPLEMENTARY INFORMATION ON OIL AND NATURAL GAS EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES (UNAUDITED) (Details 3) (USD $)	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Future cash inflows	$1,339,372,300	$1,450,469,000	$823,280,251
Future oil and natural gas operating expenses	-322,298,300	-334,883,800	-151,140,007
Future development costs	-405,900,900	-424,256,900	-209,618,885
Future income tax expenses	-133,467,940	-163,704,120	-111,946,653
Future net cash flows	477,705,160	527,624,180	350,574,706
10% annual discount for estimating timing of cash flows	-183,249,968	-202,270,201	-139,021,820
Standardized measure of discounted future net cash flows	$294,455,192	$325,353,979	$211,552,886	$85,083,867

SUPPLEMENTARY_INFORMATION_ON_O6

SUPPLEMENTARY INFORMATION ON OIL AND NATURAL GAS EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES (UNAUDITED) (Details 4) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Changes due to current year operation:
Sales of oil and natural gas, net of oil and natural gas operating expenses	($25,270,455)	($17,255,824)	($13,250,556)
Extensions and discoveries	2,743,800	37,750,617	40,013,415
Purchases of oil and gas properties	12,827,533	215,427,459	177,412,984
Development costs incurred during the period that reduced future development costs	9,178,400	100,500	5,432,652
Changes due to revisions in standardized variables:
Prices and operating expenses	-42,125,763	-30,773,529	-37,028,314
Income taxes	19,303,313	-38,340,467	-40,922,146
Estimated future development costs	7,218,529	32,430,504	-5,173,677
Quantity estimates	-21,028,476	-107,070,514	-12,905,019
Sale of reserves in place
Accretion of discount	43,124,820	27,910,664	11,055,659
Production rates, timing and other	-36,870,488	-6,378,317	1,834,021
Net change	-30,898,787	113,801,093	126,469,019
Beginning of year	325,353,979	211,552,886	85,083,867
End of year	$294,455,192	$325,353,979	$211,552,886

SUPPLEMENTARY_INFORMATION_ON_O7

SUPPLEMENTARY INFORMATION ON OIL AND NATURAL GAS EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES (Details Narrative) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Crude oil prices used in computing future cash flow	91.48	96.94	94.04
Natural gas prices used in computing future cash flow	4.35	3.67	2.93
Prospect profits related sales recorded	$28,616	$50,346	$234,105