Yuma Energy (YUMAQ) 10-Q 11 May 18 2018 Q1 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	3 Months Ended
	Mar. 31, 2018	May 11, 2018
Document And Entity Information
Entity Registrant Name	Yuma Energy, Inc.
Entity Central Index Key	1,672,326
Document Type	10-Q
Document Period End Date	Mar. 31, 2018
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Is Entity a Well-known Seasoned Issuer?	No
Is Entity a Voluntary Filer?	No
Is Entity's Reporting Status Current?	Yes
Entity Filer Category	Smaller Reporting Company
Entity Common Stock, Shares Outstanding		23,230,169
Document Fiscal Period Focus	Q1
Document Fiscal Year Focus	2,018

CONSOLIDATED BALANCE SHEETS (Un

CONSOLIDATED BALANCE SHEETS (Unaudited) - USD ($)	Mar. 31, 2018	Dec. 31, 2017
CURRENT ASSETS:
Cash and cash equivalents	$ 101,850	$ 137,363
Accounts receivable, net of allowance for doubtful accounts:
Trade	3,569,760	4,496,316
Officers and employees	0	53,979
Other	536,243	1,004,479
Prepayments	837,877	976,462
Other deferred charges	406,881	347,490
Total current assets	5,452,611	7,016,089
OIL AND GAS PROPERTIES (full cost method):
Proved properties	494,700,559	494,216,531
Unproved properties - not subject to amortization	9,127,056	6,794,372
Subtotal	503,827,615	501,010,903
Less: accumulated depreciation, depletion and amortization	(423,342,487)	(421,165,400)
Net oil and gas properties	80,485,128	79,845,503
OTHER PROPERTY AND EQUIPMENT:
Land, buildings and improvements	1,600,000	1,600,000
Other property and equipment	2,845,459	2,845,459
Total	4,445,459	4,445,459
Less: accumulated depreciation and amortization	(1,449,769)	(1,409,535)
Net other property and equipment	2,995,690	3,035,924
OTHER ASSETS AND DEFERRED CHARGES:
Deposits	467,592	467,592
Other noncurrent assets	79,997	270,842
Total other assets and deferred charges	547,589	738,434
TOTAL ASSETS	89,481,018	90,635,950
CURRENT LIABILITIES:
Current maturities of debt	27,424,499	651,124
Accounts payable, principally trade	13,778,740	11,931,218
Commodity derivative instruments	1,476,071	903,003
Asset retirement obligations	88,721	277,355
Other accrued liabilities	1,765,817	2,295,438
Total current liabilities	44,533,848	16,058,138
LONG-TERM DEBT	0	27,700,000
OTHER NONCURRENT LIABILITIES:
Asset retirement obligations	10,352,150	10,189,058
Commodity derivative instruments	485,234	336,406
Deferred rent	281,852	290,566
Employee stock awards	239,095	191,110
Total other noncurrent liabilities	11,358,331	11,007,140
EQUITY:
Series D convertible preferred stock ($0.001 par value, 7,000,000 authorized, 1,937,262 issued and outstanding as of March 31, 2018, and 1,904,391 issued and outstanding as of December 31, 2017)	1,937	1,904
Common stock ($0.001 par value, 100 million shares authorized, 23,230,169 outstanding as of March 31, 2018 and 22,661,758 outstanding as of December 31, 2017)	23,230	22,662
Additional paid-in capital	56,728,467	55,064,685
Treasury stock at cost (369,238 shares as of March 31, 2018 and 13,343 shares as of December 31, 2017)	(434,557)	(25,278)
Accumulated earnings (deficit)	(22,730,238)	(19,193,301)
Total equity	33,588,839	35,870,672
TOTAL LIABILITIES AND EQUITY	$ 89,481,018	$ 90,635,950

CONSOLIDATED BALANCE SHEETS (U3

CONSOLIDATED BALANCE SHEETS (Unaudited) (Parenthetical) - $ / shares	Mar. 31, 2018	Dec. 31, 2017
Statement of Financial Position [Abstract]
Preferred Stock, Par Value	$ .001	$ .001
Preferred Stock, Authorized	7,000,000	7,000,000
Preferred Stock, Issued	1,937,262	1,904,391
Preferred Stock, Outstanding	1,937,262	1,904,391
Common Stock, Par Value	$ .001	$ 0.001
Common stock, Authorized	100,000,000	100,000,000
Common Stock, Outstanding	23,230,169	22,661,758
Treasury stock	369,238	13,343

CONSOLIDATED STATEMENTS OF OPER

CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited) - USD ($)	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
REVENUES:
Sales of natural gas and crude oil	$ 5,645,536	$ 7,144,424
EXPENSES:
Lease operating and production costs	2,625,768	2,661,264
General and administrative - stock-based compensation	296,293	51,735
General and administrative - other	1,749,237	2,176,002
Depreciation, depletion and amortization	2,217,321	3,140,940
Asset retirement obligation accretion expense	142,940	138,569
Bad debt expense	65,808	0
Total expenses	7,097,367	8,168,510
LOSS FROM OPERATIONS	(1,451,831)	(1,024,086)
OTHER INCOME (EXPENSE):
Net gains (losses) from commodity derivatives	(1,251,260)	3,556,783
Interest expense	(466,292)	(496,091)
Gain on other property and equipment	0	555,642
Other, net	(3,537)	36,408
Total other income (expense)	(1,721,089)	3,652,742
INCOME (LOSS) BEFORE INCOME TAXES	(3,172,920)	2,628,656
Income tax expense	0	26,531
NET INCOME (LOSS)	(3,172,920)	2,602,125
PREFERRED STOCK:
Dividends paid in kind	364,017	339,610
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCKHOLDERS	$ (3,536,937)	$ 2,262,515
INCOME (LOSS) PER COMMON SHARE:
Basic	$ (0.16)	$ 0.19
Diluted	$ (0.16)	$ 0.16
WEIGHTED AVERAGE NUMBER OF COMMON SHARES OUTSTANDING:
Basic	22,813,130	12,211,256
Diluted	22,813,130	14,056,170

CONSOLIDATED STATEMENTS OF CHAN

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY (Unaudited) - 3 months ended Mar. 31, 2018 - USD ($)	PREFERRED STOCK	COMMON STOCK	PAID-IN-CAPITAL	TREASURY STOCK	ACCUMULATED DEFICIT	Total
Beginning Balance, Shares at Dec. 31, 2017	1,904,391	22,661,758
Beginning Balance, Amount at Dec. 31, 2017	$ 1,904	$ 22,662	$ 55,064,685	$ (25,278)	$ (19,193,301)	$ 35,870,672
Net loss					(3,172,920)	(3,172,920)
Payment of Series D dividends in kind, Shares	32,871
Payment of Series D dividends in kind, Amount	$ 33		363,984		(364,017)	0
Stock awards vested, Shares		930,916
Stock awards vested, Amount		$ 931	(931)			0
Restricted stock awards forfeited, Shares		(6,610)
Restricted stock awards forfeited, Amount		$ (7)	7			0
Restricted stock awards repurchased, Shares		(355,895)
Restricted stock awards repurchased, Amount		$ (356)	356			0
Amortization of stock-based compensation			1,300,366			1,300,366
Treasury stock - surrendered to settle employee tax liabilities				(409,279)		(409,279)
Ending Balance, Shares at Mar. 31, 2018	1,937,262	23,230,169
Ending Balance, Amount at Mar. 31, 2018	$ 1,937	$ 23,230	$ 56,728,467	$ (434,557)	$ (22,730,238)	$ 33,588,839

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) - USD ($)	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Reconciliation of net income (loss) to net cash provided by (used in) operating activities:
Net income (loss)	$ (3,172,920)	$ 2,602,125
Depreciation, depletion and amortization of property and equipment	2,217,321	3,140,940
Amortization of debt issuance costs	184,733	81,843
Deferred rent liability, net	33,117	0
Stock-based compensation expense	296,293	51,735
Settlement of asset retirement obligations	(147,122)	0
Accretion of asset retirement obligation	142,940	138,569
Bad debt expense	65,808	0
Net (gains) losses from commodity derivatives	1,251,260	(3,556,783)
Gain on sales of fixed assets	0	(555,642)
Loss on write-off of liabilities net of assets	3,631	0
Changes in assets and liabilities:
(Increase) decrease in accounts receivable	879,333	(795,740)
Decrease in prepaids, deposits and other assets	138,585	306,021
(Decrease) increase in accounts payable and other current and non-current liabilities	2,507,831	(461,542)
NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES	4,400,810	951,526
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures for oil and gas properties	(3,507,005)	(2,053,826)
Proceeds from sale of oil and gas properties	1,000,000	641,056
Derivative settlements	(529,364)	98,700
NET CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES	(3,036,369)	(1,314,070)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings on senior credit facility	6,350,000	0
Repayment of borrowings on senior credit facility	(7,000,000)	0
Repayments of borrowings - insurance financing	(276,625)	(255,026)
Debt issuance costs	0	(76,452)
Shelf registration costs	(64,050)	0
Treasury stock repurchases	(409,279)	(4,170)
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES	(1,399,954)	(335,648)
NET DECREASE IN CASH AND CASH EQUIVALENTS	(35,513)	(698,192)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD	137,363	3,625,686
CASH AND CASH EQUIVALENTS AT END OF PERIOD	101,850	2,927,494
Supplemental disclosure of cash flow information:
Interest payments (net of interest capitalized)	145,871	264,542
Interest capitalized	115,541	44,550
Supplemental disclosure of significant non-cash activity:
(Increase) decrease in capital expenditures financed by accounts payable	$ 168,934	$ (1,434,132)

1. ORGANIZATION AND BASIS OF PR

1. ORGANIZATION AND BASIS OF PRESENTATION	3 Months Ended
	Mar. 31, 2018
Accounting Policies [Abstract]
ORGANIZATION AND BASIS OF PRESENTATION	Organization Yuma Energy, Inc., a Delaware corporation (“Yuma” and collectively with its subsidiaries, the “Company”), is an independent Houston-based exploration and production company focused on acquiring, developing and exploring for conventional and unconventional oil and natural gas resources. Historically, the Company’s operations have focused on onshore properties located in central and southern Louisiana and southeastern Texas where it has a long history of drilling, developing and producing both oil and natural gas assets. More recently, it has begun acquiring acreage in Yoakum County, Texas, with plans to explore and develop additional oil and natural gas assets in the Permian Basin of West Texas. Finally, the Company has operated positions in Kern County, California, and non-operated positions in the East Texas Woodbine and the Bakken Shale in North Dakota. Basis of Presentation The accompanying unaudited consolidated financial statements of the Company and its wholly owned subsidiaries have been prepared in accordance with Article 8-03 of Regulation S-X for interim financial statements required to be filed with the Securities and Exchange Commission (“SEC”). The information furnished herein reflects all adjustments that are, in the opinion of management, necessary for the fair presentation of the Company’s Consolidated Balance Sheet as of March 31, 2018; the Consolidated Statements of Operations for the three months ended March 31, 2018 and 2017; the Consolidated Statement of Changes in Equity for the three months ended March 31, 2018; and the Consolidated Statements of Cash Flows for the three months ended March 31, 2018 and 2017. The Company’s Consolidated Balance Sheet at December 31, 2017 is derived from the audited consolidated financial statements of the Company at that date. The preparation of financial statements in conformity with the generally accepted accounting principles of the United States of America (“GAAP”) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. For further information, see Note 2 in the Notes to Consolidated Financial Statements contained in the Company’s Annual Report on Form 10-K for the year ended December 31, 2017. Interim period results are not necessarily indicative of results of operations or cash flows for the full year and accordingly, certain information normally included in financial statements and the accompanying notes prepared in accordance with GAAP has been condensed or omitted. These financial statements should be read in conjunction with the Company’s Annual Report on Form 10-K for the year ended December 31, 2017. The Company has evaluated events or transactions through the date of issuance of these unaudited consolidated financial statements. When required for comparability, reclassifications are made to the prior period financial statements to conform to the current year presentation. Recently Issued Accounting Pronouncements The accounting standard-setting organizations frequently issue new or revised accounting rules. The Company regularly reviews new pronouncements to determine their impact, if any, on the financial statements. In February 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2016-02, “Leases,” a new lease standard requiring lessees to recognize lease assets and lease liabilities for most leases classified as operating leases under previous GAAP. The guidance is effective for fiscal years beginning after December 15, 2018 with early adoption permitted. The Company will be required to use a modified retrospective approach for leases that exist or are entered into after the beginning of the earliest comparative period in the financial statements. The Company is currently evaluating the impact of the adoption of this standard on its consolidated financial statements, and plans to adopt it no later than January 1, 2019. In August 2016, the FASB issued ASU 2016-15, “Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments,” which provides clarification on how certain cash receipts and cash payments are presented and classified on the statement of cash flows. This ASU is effective for annual and interim periods beginning after December 15, 2017 and is required to be adopted using a retrospective approach if practicable, with early adoption permitted. The Company adopted this ASU in the first quarter of 2018, and the adoption did not have a material impact on its consolidated financial statements. In January 2017, the FASB issued ASU 2017-01, “Business Combinations (Topic 805): Clarifying the Definition of a Business,” which assists in determining whether a transaction should be accounted for as an acquisition or disposal of assets or as a business. This ASU is effective for annual and interim periods beginning in 2018 and is required to be adopted using a prospective approach, with early adoption permitted for transactions not previously reported in issued financial statements. The Company adopted this ASU on January 1, 2017, and expects that the adoption of this ASU could have a material impact on future consolidated financial statements, as future oil and gas asset acquisitions may not be considered businesses. In March 2016, the FASB issued ASU 2016-09, “Compensation—Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting,” In May 2014, the FASB issued ASU 2014-09, “Revenue from Contracts with Customers,” which will supersede most of the existing revenue recognition requirements in GAAP and will require entities to recognize revenue at an amount that reflects the consideration to which it expects to be entitled in exchange for transferring goods or services to a customer. The new standard also requires disclosures that are sufficient to enable users to understand an entity’s nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. In March 2016, the FASB issued ASU 2016-08, Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations (Reporting Revenue Gross versus Net). This update provides clarifications in the assessment of principal versus agent considerations in the new revenue standard. In May 2016, the FASB issued ASU 2016-12, Revenue from Contracts with Customers (Topic 606): Narrow Scope Improvements and Practical Expedients. The update reduces the potential for diversity in practice at initial application of Topic 606 and the cost and complexity of applying Topic 606. In December 2016, the FASB issued ASU 2016-20, Technical Corrections and Improvements to Topic 606, Revenue from Contracts with Customers. The update was issued to increase stakeholders’ awareness of the proposals for technical corrections and to expedite improvements. These ASUs are effective for annual and interim periods beginning after December 15, 2017. The Company adopted these standards effective January 1, 2018 using the full retrospective method. The Company finalized the detailed analysis of the impact of the standard on its contracts. The Company found that there was no significant impact on its financial position or results of operations. With the adoption of these standards, the Company was not required to record a cumulative effect adjustment due to the new standards not having a quantitative impact compared to existing GAAP (see Note 3 – Revenue Recognition – Adoption of ASC 606, “Revenue from Contracts with Customers”).

2. LIQUIDITY AND GOING CONCERN

2. LIQUIDITY AND GOING CONCERN	3 Months Ended
	Mar. 31, 2018
Liquidity And Going Concern
LIQUIDITY AND GOING CONCERN	The Company has borrowings under its credit facility which require, among other things, compliance with certain financial ratios. Due to operating losses the Company sustained during recent quarters, which were partially a result of several events outside the reasonable control of the Company, including the suspension of production from several wells for a period of time and other associated factors, at March 31, 2018 the Company was not in compliance with its fiscal period total debt to EBITDAX covenant (as defined in the Company’s credit agreement) for the trailing four quarter period under its credit facility. In addition, due to this non-compliance and the Company’s anticipated non-compliance at June 30, 2018, the Company classified its bank debt as a current liability in its financial statements as of and for the three months ended March 31, 2018. On May 8, 2018, the Company received a waiver from its lenders to its compliance with its total debt to EBITDAX covenant for the trailing four quarter period ended March 31, 2018, as long as it does not exceed 3.75 to 1.00. As of March 31, 2018, the Company had outstanding borrowings of $27.05 million under its credit facility, and its total borrowing base was $40.5 million, leaving $13.45 million of undrawn borrowing base. As of May 8, 2018, the total borrowing base under the credit facility was reduced to $35.0 million. Since March 31, 2018, the Company has borrowed an additional $7.2 million for working capital, leaving $750,000 of undrawn borrowing base as of the date of this filing. Due to the Company’s non-compliance with its total debt to EBITDAX financial ratio, as well as drilling activities and other factors, the Company had a working capital deficit of $39.08 million (inclusive of the Company's outstanding debt under its credit facility) and a loss from operations of $1.45 million as of and for the quarter ended March 31, 2018. See Note 11 – Debt and Interest Expense. A breach in the future of any of the terms and conditions of the Credit Agreement or a breach of the financial covenants thereunder could result in acceleration of the Company’s indebtedness, in which case the debt would become immediately due and payable. The Company currently anticipates non-compliance with various financial covenants at June 30, 2018. The Company has initiated several strategic alternatives to remedy its limited liquidity (defined as cash on hand and undrawn borrowing base), its debt covenant compliance issues, and to provide it with additional working capital to develop its existing assets. These may include, but are not limited to, reducing or eliminating capital expenditures previously planned for 2018; entering into commodity derivatives for a significant portion of the Company’s anticipated production for 2018; reducing general and administrative expenses; selling certain non-core assets; seeking merger and acquisition related opportunities; and potentially raising proceeds from capital markets transactions, including the sale of debt or equity securities. There can be no assurance that the exploration of strategic alternatives will result in a transaction. The significant risks and uncertainties described above raise substantial doubt about the Company's ability to continue as a going concern. The consolidated financial statements have been prepared on a going concern basis of accounting, which contemplates continuity of operations, realization of assets, and satisfaction of liabilities and commitments in the normal course of business. The consolidated financial statements do not include any adjustments that might result from the outcome of the going concern uncertainty.

3. REVENUE RECOGNITION - ADOPTI

3. REVENUE RECOGNITION - ADOPTION OF ASC 606, REVENUE FROM CONTRACTS WITH CUSTOMERS	3 Months Ended
	Mar. 31, 2018
Revenue Recognition - Adoption Of Asc 606 Revenue From Contracts With Customers
REVENUE RECOGNITION - ADOPTION OF ASC 606, REVENUE FROM CONTRACTS WITH CUSTOMERS	The Company recognizes revenues to depict the transfer of control of promised goods or services to its customers in an amount that reflects the consideration to which it expects to be entitled to in exchange for those goods or services. On January 1, 2018, the Company adopted Accounting Standards Codification (“ASC”) 606 using the full retrospective method applied to those contracts which were not completed as of December 31, 2016. As a result of electing the full retrospective adoption approach as described above, results for reporting periods beginning after December 31, 2016 are presented under ASC 606. There was no material impact upon the adoption of ASC 606, and the Company did not record any adjustments to opening retained earnings as of January 1, 2017, because its revenue is primarily products sales revenue accounted for at a point in time. Crude oil and condensate are sold through month-to-month evergreen contracts. The price for Louisiana production is tied to an index or a weighted monthly average of posted prices with certain adjustments for gravity, Basic Sediment and Water (“BS&W”) and transportation. Generally, the index or posting is based on customary industry spot prices. Pricing for the Company’s California properties is based on an average of specified posted prices, adjusted for gravity and transportation. The Company’s natural gas is sold under month-to-month contracts with pricing tied to either first of the month index or a monthly weighted average of purchaser prices received. Natural gas liquids are sold under month-to-month or year-to-year contracts usually tied to the related natural gas contract. Pricing is based on published prices for each product or a monthly weighted average of purchaser prices received. Sales of crude oil, condensates, natural gas and natural gas liquids (“NGLs”) are recognized at the point control of the product is transferred to the customer. Virtually all of the Company’s contracts’ pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality of the oil or natural gas, and prevailing supply and demand conditions. As a result, the price of the crude oil, condensate, natural gas, and NGLs fluctuates to remain competitive with other available crude oil, natural gas, and NGLs supplies. Revenue is measured based on consideration specified in the contract with the customer, and excludes any amounts collected on behalf of third parties. The Company recognizes revenue in the amount that reflects the consideration it expects to be entitled to in exchange for transferring control of those goods to the customer. The contract consideration in the Company’s variable price contracts is typically allocated to specific performance obligations in the contract according to the price stated in the contract. Amounts allocated in the Company’s fixed price contracts are based on the stand-alone selling price of those products in the context of long-term, fixed price contracts, which generally approximates the contract price. The Company records revenue in the month production is delivered to the purchaser. However, settlement statements for certain natural gas and NGL sales may not be received for 30 to 90 days after the date production is delivered, and as a result, the Company is required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. The Company records the differences between its estimates and the actual amounts received for product sales in the month that payment is received from the purchaser. Any identified differences between its revenue estimates and actual revenue received historically have not been significant. For the period from January 1, 2017 through December 31, 2017, revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material. Gain or loss on derivative instruments is outside the scope of ASC 606 and is not considered revenue from contracts with customers subject to ASC 606. The Company may use financial or physical contracts accounted for as derivatives as economic hedges to manage price risk associated with normal sales, or in limited cases may use them for contracts the Company intends to physically settle but do not meet all of the criteria to be treated as normal sales. Natural Gas and Natural Gas Liquids Sales Under the Company’s natural gas processing contracts, it delivers natural gas to a midstream processing entity at the wellhead or the inlet of the midstream processing entity’s system. The midstream processing entity gathers and processes the natural gas and remits proceeds to the Company for the resulting sales of NGLs and residue gas. In these scenarios, the Company evaluates whether it is the principal or the agent in the transaction. For those contracts where the Company has concluded it is the principal and the ultimate third party is its customer, the Company recognizes revenue on a gross basis, with transportation, gathering, processing and compression fees presented as an expense in its lease operating and production costs in the Consolidated Statements of Operations. In certain natural gas processing agreements, the Company may elect to take its residue gas and/or NGLs in-kind at the tailgate of the midstream entity’s processing plant and subsequently market the product. Through the marketing process, the Company delivers product to the ultimate third-party purchaser at a contractually agreed-upon delivery point and receives a specified index price from the purchaser. In this scenario, the Company recognizes revenue when control transfers to the purchaser at the delivery point based on the index price received from the purchaser. The gathering, processing and compression fees attributable to the gas processing contract, as well as any transportation fees incurred to deliver the product to the purchaser, are presented as lease operating and production costs in the Consolidated Statements of Operations. Crude Oil and Condensate sales The Company sells oil production at the wellhead and collects an agreed-upon index price, net of pricing differentials. In this scenario, revenue is recognized when control transfers to the purchaser at the wellhead at the net price received. The following table presents the Company’s revenues disaggregated by product source. Sales taxes are excluded from revenues. Three Months Ended March 31, 2018 2017 Sales of natural gas and crude oil: Crude oil and condensate $ 3,066,258 $ 3,815,932 Natural gas 1,791,251 2,553,443 Natural gas liquids 788,027 775,049 Total revenues $ 5,645,536 $ 7,144,424 Transaction price allocated to remaining performance obligations A significant number of the Company’s product sales are short-term in nature with a contract term of one year or less. For those contracts, the Company has utilized the practical expedient in ASC 606-10-50-14 exempting the Company from disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less. For the Company’s product sales that have a contract term greater than one year, it has utilized the practical expedient in ASC 606-10-50-14(a) which states that the Company is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under these sales contracts, each unit of product generally represents a separate performance obligation; therefore future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required. Contract Balances Receivables from contracts with customers are recorded when the right to consideration becomes unconditional, generally when control of the product has been transferred to the customer. Receivables from contracts with customers were $2,228,871 and $2,636,867 as of March 31, 2018 and December 31, 2017, respectively, and are reported in trade accounts receivable, net on the Consolidated Balance Sheets. The Company currently has no other assets or liabilities related to its revenue contracts, including no upfront or rights to deficiency payments. Practical Expedients The Company has made use of certain practical expedients in adopting the new revenue standard, including not disclosing the value of unsatisfied performance obligations for (i) contracts with an original expected length of one year or less, (ii) contracts for which the Company recognizes revenue at the amount to which the Company has the right to invoice, (iii) variable consideration which is allocated entirely to a wholly unsatisfied performance obligation and meets the variable allocation criteria in the standard and (iv) only contracts that are not completed at transition. The Company has not adjusted the promised amount of consideration for the effects of a significant financing component if the Company expects, at contract inception, that the period between when the Company transfers a promised good or service to the customer and when the customer pays for that good or service will be one year or less.

4. ASSET IMPAIRMENTS

4. ASSET IMPAIRMENTS	3 Months Ended
	Mar. 31, 2018
Asset Impairments
ASSET IMPAIRMENTS	The Company’s oil and natural gas properties are accounted for using the full cost method of accounting, under which all productive and nonproductive costs directly associated with property acquisition, exploration and development activities are capitalized. These capitalized costs (net of accumulated DD&A and deferred income taxes) of proved oil and natural gas properties are subject to a full cost ceiling limitation. The full cost ceiling limitation limits these costs to an amount equal to the present value, discounted at 10%, of estimated future net cash flows from estimated proved reserves less estimated future operating and development costs, abandonment costs (net of salvage value) and estimated related future income taxes. In accordance with SEC rules, prices used are the 12 month average prices, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12 month period prior to the end of the reporting period, unless prices are defined by contractual arrangements. Prices are adjusted for “basis” or location differentials. Prices are held constant over the life of the reserves. The Company’s first quarter of 2018 full cost ceiling calculation was prepared by the Company using (i) $53.49 per barrel for oil, and (ii) $2.995 per MMBTU for natural gas as of March 31, 2018. If unamortized costs capitalized within the cost pool exceed the ceiling, the excess is charged to expense and separately disclosed during the period in which the excess occurs. Amounts thus required to be written off are not reinstated for any subsequent increase in the cost center ceiling. During the three month periods ended March 31, 2018 and 2017, the Company did not record any full cost ceiling impairments.

5. ASSET RETIREMENT OBLIGATIONS

5. ASSET RETIREMENT OBLIGATIONS	3 Months Ended
	Mar. 31, 2018
Asset Retirement Obligation Disclosure [Abstract]
ASSET RETIREMENT OBLIGATIONS	The Company has asset retirement obligations (“AROs”) associated with the future plugging and abandonment of oil and natural gas properties and related facilities. The accretion of the ARO is included in the Consolidated Statements of Operations. Revisions to the liability typically occur due to changes in the estimated abandonment costs, well economic lives and the discount rate. The following table summarizes the Company’s ARO transactions recorded during the three months ended March 31, 2018 in accordance with the provisions of FASB ASC Topic 410, “Asset Retirement and Environmental Obligations” : Three Months Ended March 31, 2018 Asset retirement obligations at December 31, 2017 $ 10,466,413 Liabilities incurred 25,940 Liabilities settled (194,422 ) Accretion expense 142,940 Revisions in estimated cash flows - Asset retirement obligations at March 31, 2018 $ 10,440,871 Based on expected timing of settlements, $88,721 of the ARO is classified as current at March 31, 2018.

6. FAIR VALUE MEASUREMENTS

6. FAIR VALUE MEASUREMENTS	3 Months Ended
	Mar. 31, 2018
Fair Value Disclosures [Abstract]
FAIR VALUE MEASUREMENTS	Certain financial instruments are reported at fair value on the Consolidated Balance Sheets. Under fair value measurement accounting guidance, fair value is defined as the amount that would be received from the sale of an asset or paid for the transfer of a liability in an orderly transaction between market participants, i.e., an exit price. To estimate an exit price, a three-level hierarchy is used. The fair value hierarchy prioritizes the inputs, which refer broadly to assumptions market participants would use in pricing an asset or a liability, into three levels. 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 Instruments, see below) – Derivatives Fair value measurements at March 31, 2018 Significant Quoted prices other Significant in active observable unobservable markets inputs inputs (Level 1) (Level 2) (Level 3) Total Liabilities: Commodity derivatives – oil $ - $ 2,163,001 $ - $ 2,163,001 Commodity derivatives – gas - (201,696 ) - $ (201,696 ) Total liabilities $ - $ 1,961,305 $ - $ 1,961,305 Fair value measurements at December 31, 2017 Significant Quoted prices other Significant in active observable unobservable markets inputs inputs (Level 1) (Level 2) (Level 3) Total Liabilities: Commodity derivatives – oil $ - $ 1,517,410 $ - $ 1,517,410 Commodity derivatives – gas - (278,001 ) - $ (278,001 ) Total liabilities $ - $ 1,239,409 $ - $ 1,239,409 Derivative instruments listed above include swaps and three-way collars (see Note 7 – Commodity Derivative Instruments). Debt Asset Retirement Obligations

7. COMMODITY DERIVATIVE INSTRUM

7. COMMODITY DERIVATIVE INSTRUMENTS	3 Months Ended
	Mar. 31, 2018
Derivative Instruments and Hedging Activities Disclosure [Abstract]
COMMODITY DERIVATIVE INSTRUMENTS	Objective and Strategies for Using Commodity Derivative Instruments Futures contracts and commodity price swap agreements are used to fix the price of expected future oil and natural gas sales at major industry trading locations such as Henry Hub, Louisiana for natural gas and Cushing, Oklahoma for oil. Basis swaps are used to fix or float the price differential between product prices at one market location versus another. Options are used to establish a floor price, a ceiling price, or a floor and ceiling price (collar) for expected future oil and natural gas sales. A three-way collar is a combination of three options: a sold call, a purchased put, and a sold put. The sold call establishes the maximum price that the Company will receive for the contracted commodity volumes. The purchased put establishes the minimum price that the Company will receive for the contracted volumes unless the market price for the commodity falls below the sold put strike price, at which point the minimum price equals the reference price (e.g., NYMEX) plus the excess of the purchased put strike price over the sold put strike price. While these instruments mitigate the cash flow risk of future reductions in commodity prices, they may also curtail benefits from future increases in commodity prices. The Company does not apply hedge accounting to any of its derivative instruments. As a result, gains and losses associated with derivative instruments are recognized currently in earnings. Counterparty Credit Risk Commodity derivative instruments open as of March 31, 2018 are provided below. Natural gas prices are New York Mercantile Exchange (“NYMEX”) Henry Hub prices, and crude oil prices are NYMEX West Texas Intermediate (“WTI”). 2018 2019 Settlement Settlement (1) NATURAL GAS (MMBtu): Swaps Volume 1,245,893 373,906 Price $ 3.00 $ 3.00 CRUDE OIL (Bbls): Swaps Volume 140,818 156,320 Price $ 53.17 $ 53.77 (1) Represents volumes through March 2019. Derivatives for each commodity are netted on the Consolidated Balance Sheets. The following table presents the fair value and balance sheet location of each classification of commodity derivative contracts on a gross basis without regard to same-counterparty netting: Fair value as of March 31, 2018 December 31, 2017 Asset commodity derivatives: Current assets $ 201,696 $ 295,304 Noncurrent assets - 118 201,696 295,422 Liability commodity derivatives: Current liabilities (1,677,767 ) (1,198,307 ) Noncurrent liabilities (485,234 ) (336,524 ) (2,163,001 ) (1,534,831 ) Total commodity derivative instruments $ (1,961,305 ) $ (1,239,409 ) Net gains (losses) from commodity derivatives on the Consolidated Statements of Operations are comprised of the following: Three Months Ended March 31, 2018 2017 Derivative settlements $ (529,364 ) $ 98,700 Mark to market on commodity derivatives (721,896 ) 3,458,083 Net gains (losses) from commodity derivatives $ (1,251,260 ) $ 3,556,783

8. PREFERRED STOCK

8. PREFERRED STOCK	3 Months Ended
	Mar. 31, 2018
Preferred stock [Abstract]
PREFERRED STOCK	Each share of the Company’s Series D Convertible Preferred Stock, $0.001 par value per share (the “Series D Preferred Stock”), is convertible into a number of shares of common stock determined by dividing the original issue price, which was $11.0741176, by the conversion price, which is currently $6.5838109. The conversion price is subject to adjustment for stock splits, stock dividends, reclassification, and certain issuances of common stock for less than the conversion price. As of March 31, 2018, the Series D Preferred Stock had a liquidation preference of approximately $21.5 million. The Series D Preferred Stock provides for cumulative dividends of 7.0% per annum, payable in-kind. The Company issued 32,871 shares of Series D Preferred Stock during the three months ended March 31, 2018. The Company does not have any dividends in arrears at March 31, 2018.

9. STOCK-BASED COMPENSATION

9. STOCK-BASED COMPENSATION	3 Months Ended
	Mar. 31, 2018
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
STOCK-BASED COMPENSATION	2014 Long-Term Incentive Plan On October 26, 2016, Yuma assumed the Yuma Energy, Inc., a California corporation (“Yuma California”), 2014 Long-Term Incentive Plan (the “2014 Plan”), which was approved by the shareholders of Yuma California. The shareholders of Yuma California originally approved the 2014 Plan at the special meeting of shareholders on September 10, 2014 and the subsequent amendment to the 2014 Plan at the special meeting of shareholders on October 26, 2016. Under the 2014 Plan, Yuma may grant stock options, restricted stock awards (“RSAs”), restricted stock units (“RSUs”), stock appreciation rights (“SARs”), performance units, performance bonuses, stock awards and other incentive awards to employees of Yuma and its subsidiaries and affiliates. Yuma may also grant nonqualified stock options, RSAs, RSUs, SARs, performance units, stock awards and other incentive awards to any persons rendering consulting or advisory services and non-employee directors of Yuma and its subsidiaries, subject to the conditions set forth in the 2014 Plan. Generally, all classes of the Company’s employees are eligible to participate in the 2014 Plan. The 2014 Plan provides that a maximum of 2,495,000 shares of common stock may be issued in conjunction with awards granted under the 2014 Plan. As of the closing of Yuma’s merger with Yuma California (the “Reincorporation Merger”), there were awards for approximately 179,165 shares of common stock outstanding. Awards that are forfeited under the 2014 Plan will again be eligible for issuance as though the forfeited awards had never been issued. Similarly, awards settled in cash will not be counted against the shares authorized for issuance upon exercise of awards under the 2014 Plan. The 2014 Plan provides that a maximum of 1,000,000 shares of common stock may be issued in conjunction with incentive stock options granted under the 2014 Plan. The 2014 Plan also limits the aggregate number of shares of common stock that may be issued in conjunction with stock options and/or SARs to any eligible employee in any calendar year to 1,500,000 shares. The 2014 Plan also limits the aggregate number of shares of common stock that may be issued in conjunction with the grant of RSAs, RSUs, performance unit awards, stock awards and other incentive awards to any eligible employee in any calendar year to 700,000 shares. At March 31, 2018, 6,610 shares of the 2,495,000 shares of common stock originally authorized under active share-based compensation plans remained available for future issuance. Yuma generally issues new shares to satisfy awards under employee share-based payment plans. The number of shares available is reduced by awards granted. The Company accounts for stock-based compensation in accordance with FASB ASC Topic 718, “Compensation – Stock Compensation”. RSAs, SARs and Stock Options granted to officers and employees generally vest in one-third increments over a three-year period, or with three year cliff vesting, and are contingent on the recipient’s continued employment. RSAs granted to directors generally vest in quarterly increments over a one-year period. Equity Based Awards – Liability Based Awards – Total share-based compensation expenses recognized for the three months ended March 31, 2018 and 2017 were $296,293 (none capitalized) and $51,735 (none capitalized), respectively.

10. NET INCOME (LOSS) PER COMMO

10. NET INCOME (LOSS) PER COMMON SHARE	3 Months Ended
	Mar. 31, 2018
INCOME (LOSS) PER COMMON SHARE:
NET INCOME (LOSS) PER COMMON SHARE	Net Income (Loss) per common share – Basic is calculated by dividing net income (loss) attributable to common shareholders by the weighted average number of shares of common stock outstanding during the period. Net Income (Loss) per common share – Diluted assumes the conversion of all potentially dilutive securities, and is calculated by dividing net income (loss) attributable to common shareholders by the sum of the weighted average number of shares of common stock outstanding plus potentially dilutive securities. Net Income (Loss) per common share – Diluted considers the impact of potentially dilutive securities except in periods where their inclusion would have an anti-dilutive effect. A reconciliation of earnings (loss) per common share is as follows: Three Months Ended March 31, 2018 2017 Net income (loss) attributable to common stockholders $ (3,536,937 ) $ 2,262,515 Weighted average common shares outstanding Basic 22,813,130 12,211,256 Add potentially dilutive securities: Unvested restricted stock awards - 67,855 Stock appreciation rights - - Stock options - - Series D preferred stock - 1,777,059 Diluted weighted average common shares outstanding 22,813,130 14,056,170 Net income (loss) per common share: Basic $ (0.16 ) $ 0.19 Diluted $ (0.16 ) $ 0.16

11. DEBT AND INTEREST EXPENSE

11. DEBT AND INTEREST EXPENSE	3 Months Ended
	Mar. 31, 2018
Debt Disclosure [Abstract]
DEBT AND INTEREST EXPENSE	Long-term debt consisted of the following: March 31, December 31, 2018 2017 Senior credit facility $ 27,050,000 $ 27,700,000 Installment loan due 7/22/18 originating from the financing of insurance premiums at 5.14% interest rate 374,499 651,124 Total debt 27,424,499 28,351,124 Less: current maturities (27,424,499 ) (651,124 ) Total long-term debt $ - $ 27,700,000 Senior Credit Facility On October 26, 2016, Yuma and three of its subsidiaries, as the co-borrowers (collectively, the “Borrowers”), entered into a Credit Agreement providing for a $75.0 million three-year senior secured revolving credit facility (the “Credit Agreement”) with SocGen, as administrative agent, SG Americas Securities, LLC, as lead arranger and bookrunner, and the Lenders signatory thereto (collectively with SocGen, the “Lender”). As of March 31, 2018, the credit facility had a borrowing base of $40.5 million. On May 8, 2018, the Borrowers entered into the Limited Waiver and Second Amendment to Credit Agreement and Borrowing Base Redetermination (the “Second Amendment”) with the Lender. Pursuant to the Second Amendment, effective as of March 31, 2018, the Borrowers are required to enter into additional hedging arrangements with respect to a substantial portion of its reasonably anticipated projected production; the terms of the covenant related to the current ratio were revised to exclude the current portion of long-term indebtedness outstanding under the Credit Agreement from current liabilities; and Yuma is required to provide monthly production and lease operating expense statements to the Lender. Additionally, the Second Amendment provides a waiver of the financial covenant related to the maximum ratio of total debt to EBITDAX for the four fiscal quarter period ended March 31, 2018 so long as it does not exceed 3.75 to 1.00. The Second Amendment also provided that as of May 8, 2018, the borrowing base under the credit facility was reduced to $35.0 million. Since March 31, 2018, the Company borrowed an additional $7.2 million for working capital, leaving $750,000 of undrawn borrowing base as of the date of this filing (see Note 2 – Liquidity and Going Concern). The Credit Agreement governing the Company’s credit facility provides for interest-only payments until October 26, 2019, when the Credit Agreement matures and any outstanding borrowings are due. The borrowing base under the Credit Agreement is subject to redetermination on April 1st and October 1st of each year, as well as special redeterminations described in the Credit Agreement, in each case which may reduce the amount of the borrowing base. The Company’s obligations under the Credit Agreement are guaranteed by its subsidiaries and are secured by liens on substantially all of the Company’s assets, including a mortgage lien on oil and natural gas properties covering at least 95% of the PV10 value of the proved oil and gas properties included in the determination of the borrowing base. The amounts borrowed under the Credit Agreement bear annual interest rates at either (a) the London Interbank Offered Rate (“LIBOR”) plus 3.00% to 4.00% or (b) the prime lending rate of SocGen plus 2.00% to 3.00%, depending on the amount borrowed under the credit facility and whether the loan is drawn in U.S. dollars or Euro dollars. The interest rate for the credit facility at March 31, 2018 was 5.39% for LIBOR-based debt and 7.25% for prime-based debt. Principal amounts outstanding under the credit facility are due and payable in full at maturity on October 26, 2019. Additional payments due under the Credit Agreement include paying a commitment fee to the Lender in respect of the unutilized commitments thereunder. The commitment rate is 0.50% per year of the unutilized portion of the borrowing base in effect from time to time. The Company is also required to pay customary letter of credit fees. In addition, the Credit Agreement requires the Company to maintain the following financial covenants: a current ratio of not less than 1.0 to 1.0 on the last day of each quarter, a ratio of total debt to earnings before interest, taxes, depreciation, depletion, amortization and exploration expenses (“EBITDAX”) ratio of not greater than 3.5 to 1.0 for the four fiscal quarters ending on the last day of the fiscal quarter immediately preceding such date of determination, and a ratio of EBITDAX to interest expense of not less than 2.75 to 1.0 for the four fiscal quarters ending on the last day of the fiscal quarter immediately preceding such date of determination, and cash and cash equivalent investments together with borrowing availability under the Credit Agreement of at least $4.0 million. The Credit Agreement contains customary affirmative covenants and defines events of default for credit facilities of this type, including failure to pay principal or interest, breach of covenants, breach of representations and warranties, insolvency, judgment default, and a change of control. Upon the occurrence and continuance of an event of default, the Lender has the right to accelerate repayment of the loans and exercise its remedies with respect to the collateral. As of March 31, 2018, the Company was not in compliance with one of its financial covenants under the Credit Agreement and received a waiver from the lenders on May 8, 2018. The Company currently anticipates non-compliance with various financial covenants at June 30, 2018. See Note 2 – Liquidity and Going Concern. The Company incurred commitment fees of $14,335 and $5,625 during the three months ended March 31, 2018 and 2017, respectively.

12. STOCKHOLDERS' EQUITY

12. STOCKHOLDERS' EQUITY	3 Months Ended
	Mar. 31, 2018
EQUITY:
STOCKHOLDERS' EQUITY	Yuma is authorized to issue up to 100,000,000 shares of common stock, $0.001 par value per share, and 20,000,000 shares of preferred stock, $0.001 par value per share. The holders of common stock are entitled to one vote for each share of common stock, except as otherwise required by law. The Company has designated 7,000,000 shares of preferred stock as Series D Preferred Stock. See Note 9 – Stock-Based Compensation, which describes outstanding stock options, RSAs and SARs granted under the 2014 Plan.

13. INCOME TAXES

13. INCOME TAXES	3 Months Ended
	Mar. 31, 2018
Income Tax Disclosure [Abstract]
INCOME TAXES	The Company’s effective tax rate for the three months ended March 31, 2018 and 2017 was 0.00% and 1.01%, respectively. The difference between the statutory federal income taxes calculated using a U.S. Federal statutory corporate income tax rate of 21% and the Company’s effective tax rate of 0.00% for the three months ended March 31, 2018 was primarily related to the valuation allowance on the deferred tax assets and state income taxes. The difference between the statutory federal income taxes calculated using a U.S. Federal statutory corporate income tax rate of 35% and the Company’s effective tax rate of 1.01% for the three months ended March 31, 2017 was primarily related to the valuation allowance on the deferred tax assets and state income taxes. As of March 31, 2018, the Company had federal and state net operating loss carryforwards of approximately $173.8 million which expire between 2022 and 2038. Of this amount, approximately $59.5 million is subject to limitation under Section 382 of the Internal Revenue Code of 1986, as amended (the “Code”), which could result in some amounts expiring prior to being utilized. Realization of a deferred tax asset is dependent, in part, on generating sufficient taxable income prior to expiration of the loss carryforwards. The Company provides for deferred income taxes on the difference between the tax basis of an asset or liability and its carrying amount in the financial statements in accordance FASB ASC Topic 740, “Income Taxes”. This difference will result in taxable income or deductions in future years when the reported amount of the asset or liability is recovered or settled, respectively. In recording deferred tax assets, the Company considers whether it is more likely than not that some portion or all of the deferred income tax asset will be realized. The ultimate realization of deferred income tax assets, if any, is dependent upon the generation of future taxable income during the periods in which those deferred income tax assets would be deductible. Based on the available evidence, the Company has recorded a full valuation allowance against its net deferred tax assets.

14. OIL AND GAS ASSET SALES

14. OIL AND GAS ASSET SALES	3 Months Ended
	Mar. 31, 2018
Oil And Gas Asset Sales
OIL AND GAS ASSET SALES	In January 2018, the Company sold a 12.5% working interest in ten sections of the project in Yoakum County, Texas, known as Mario, for $500,000. Additionally, the December 2017 sale of a 12.5% working interest under the same terms was settled in January 2018 for $500,000, bringing the total sales proceeds received to $1,000,000.

15. COMMITMENTS AND CONTINGENCI

15. COMMITMENTS AND CONTINGENCIES	3 Months Ended
	Mar. 31, 2018
Commitments and Contingencies Disclosure [Abstract]
COMMITMENTS AND CONTINGENCIES	Joint Development Agreement On March 27, 2017, the Company entered into a Joint Development Agreement (“JDA”) with two privately held companies, both unaffiliated entities, covering an area of approximately 52 square miles (33,280 acres) in the Permian Basin of Yoakum County, Texas. In connection with the JDA, the Company held a 75% working interest in approximately 3,669 acres (2,752 net acres) as of December 31, 2017. As the operator of the property covered by the JDA, the Company was committed as of March 31, 2018 to spend an additional $394,814 by March 2020. Throughput Commitment Agreement On August 1, 2014, Crimson Energy Partners IV, LLC, as operator of the Company’s Chalktown properties, in which the Company has a working interest, entered into a throughput commitment (the “Commitment”) with ETC Texas Pipeline, Ltd. effective April 1, 2015 for a five year throughput commitment. In connection with the Commitment, the operator and the Company failed to reach the volume commitments in year two, and the Company anticipates that a shortfall will exist through the expiration of the five year term, which expires in March 2020. Accordingly, the Company is accruing the expected volume commitment shortfall amounts based on production to lease operating expense (“LOE”) on a monthly basis. On a net basis, the Company anticipates accruing approximately $30,000 in LOE per month, which represents the maximum amounts that could be owed based upon the Commitment. Lease Agreements On July 26, 2017, the Company entered into a tenth amendment to its office lease whereby the term of the lease was extended to August 31, 2023. The lease amendment covers a period of 68 calendar months and went into effect on January 1, 2018. In addition, the lease amendment included seven months of abated rent and operating expenses from June 1, 2017 through February 1, 2018, as well as other incentives, including abated parking cost and tenant lease improvement allowances. The base rent amount (which began on January 1, 2018) starts at $258,060 per annum and escalates to $288,420 per annum during the final 19 months of the lease extension. In addition to the base rent amount, the Company will also be responsible for additional operating expenses of the building as well as parking charges once the abatement period ends. The Company accounts for the lease as an operating lease under GAAP. The Company also currently leases approximately 3,200 square feet of office space at an off-site location as a storage facility. The current lease expires on April 30, 2020. Certain Legal Proceedings From time to time, the Company is party to various legal proceedings arising in the ordinary course of business. The Company expenses or accrues legal costs as incurred. A summary of the Company’s legal proceedings is as follows: Yuma Energy, Inc. v. Cardno PPI Technology Services, LLC Arbitration On May 20, 2015, counsel for Cardno PPI Technology Services, LLC (“Cardno PPI”) sent a notice of the filing of liens totaling $304,209 on the Company’s Crosby 14 No. 1 Well and Crosby 14 SWD No. 1 Well in Vernon Parish, Louisiana. The Company disputed the validity of the liens and of the underlying invoices, and notified Cardno PPI that applicable credits had not been applied. The Company invoked mediation on August 11, 2015 on the issues of the validity of the liens, the amount due pursuant to terms of the parties’ Master Service Agreement (“MSA”), and PPI Cardno’s breaches of the MSA. Mediation was held on April 12, 2016; no settlement was reached. On May 12, 2016, Cardno filed a lawsuit in Louisiana state court to enforce the liens; the Court entered an Order Staying Proceeding on June 13, 2016, ordering that the lawsuit “be stayed pending mediation/arbitration between the parties.” On June 17, 2016, the Company served a Notice of Arbitration on Cardno PPI, stating claims for breach of the MSA billing and warranty provisions. On July 15, 2016, Cardno PPI served a Counterclaim for $304,209 plus attorneys’ fees. The parties selected an arbitrator, and the arbitration hearing was held on March 29, April 12 and April 13, 2018. The parties submitted closing statements on April 30, 2018. Management intends to pursue the Company’s claims and to defend the counterclaim vigorously. At this point in the legal process, no evaluation of the likelihood of an unfavorable outcome or associated economic loss can be made; therefore no liability has been recorded on the Company’s consolidated financial statements. The Parish of St. Bernard v. Atlantic Richfield Co., et al On October 13, 2016, two subsidiaries of the Company, Yuma Exploration and Production Company, Inc. (“Exploration”) and Yuma Petroleum Company (“YPC”), were named as defendants, among several other defendants, in an action by the Parish of St. Bernard in the Thirty-Fourth Judicial District of Louisiana. The petition alleges violations of the State and Local Coastal Resources Management Act of 1978, as amended, in the St. Bernard Parish. The Company has notified its insurance carrier of the lawsuit. Management intends to defend the plaintiffs’ claims vigorously. The case has been removed to federal district court for the Eastern District of Louisiana. A motion to remand has been filed and the Court officially remanded the case on July 6, 2017. Exceptions for Exploration, YPC and the other defendants have been filed; however, the hearing for such exceptions was continued from the original date of October 6, 2017 to November 22, 2017. The November 22, 2017 hearing was continued without date because the parties agreed the case will be de-cumulated into subcases, but the details of this are yet to be determined. At this point in the legal process, no evaluation of the likelihood of an unfavorable outcome or associated economic loss can be made; therefore no liability has been recorded on the Company’s consolidated financial statements. Cameron Parish vs. BEPCO LP, et al & Cameron Parish vs. Alpine Exploration Companies, Inc., et al. The Parish of Cameron, Louisiana, filed a series of lawsuits against approximately 190 oil and gas companies alleging that the defendants, including Davis Petroleum Acquisition Corp. (“Davis”), have failed to clear, revegetate, detoxify, and restore the mineral and production sites and other areas affected by their operations and activities within certain coastal zone areas to their original condition as required by Louisiana law, and that such defendants are liable to Cameron Parish for damages under certain Louisiana coastal zone laws for such failures; however, the amount of such damages has not been specified. Two of these lawsuits, originally filed February 4, 2016 in the 38th Judicial District Court for the Parish of Cameron, State of Louisiana, name Davis as defendant, along with more than 30 other oil and gas companies. Both cases have been removed to federal district court for the Western District of Louisiana. The Company denies these claims and intends to vigorously defend them. Davis has become a party to the Joint Defense and Cost Sharing Agreements for these cases. Motions to remand were filed and the Magistrate Judge recommended that the cases be remanded. The Company has been advised that the new District Judge assigned to these cases is Judge Terry A. Doughty, and on May 9, 2018, Judge Doughty agreed with the Magistrate Judge's recommendation and the cases have now been remanded to the 38th Judicial District Court, Cameron Parish, Louisiana. At this point in the legal process, no evaluation of the likelihood of an unfavorable outcome or associated economic loss can be made; therefore no liability has been recorded on the Company’s consolidated financial statements. Louisiana, et al. Escheat Tax Audits The States of Louisiana, Texas, Minnesota, North Dakota and Wyoming have notified the Company that they will examine the Company’s books and records to determine compliance with each of the examining state’s escheat laws. The review is being conducted by Discovery Audit Services, LLC. The Company has engaged Ryan, LLC to represent it in this matter. The exposure related to the audits is not currently determinable and therefore, no liability has been recorded on the Company’s consolidated financial statements. Louisiana Severance Tax Audit The State of Louisiana, Department of Revenue, notified Exploration that it was auditing Exploration’s calculation of its severance tax relating to Exploration’s production from November 2012 through March 2016. The audit relates to the Department of Revenue’s recent interpretation of long-standing oil purchase contracts to include a disallowable “transportation deduction,” and thus to assert that the severance tax paid on crude oil sold during the contract term was not properly calculated. The Department of Revenue sent a proposed assessment in which they sought to impose $476,954 in additional state severance tax plus associated penalties and interest. Exploration engaged legal counsel to protest the proposed assessment and request a hearing. Exploration then entered a Joint Defense Group of operators challenging similar audit results. Since the Joint Defense Group is challenging the same legal theory, the Board of Tax Appeals proposed to hear a motion brought by one of the taxpayers that would address the rule for all through a test case. Exploration’s case has been stayed pending adjudication of the test case. The hearing for the test case was held on November 7, 2017, and on December 6, 2017, the Board of Tax Appeals rendered judgment in favor of the taxpayer in the first of these cases. The Department of Revenue filed an appeal to this decision on January 5, 2018 and we are still waiting for the case record to be lodged at the Louisiana Third Circuit Court of Appeal. At this point in the legal process, no evaluation of the likelihood of an unfavorable outcome or associated economic loss can be made; therefore no liability has been recorded on the Company’s consolidated financial statements. Louisiana Department of Wildlife and Fisheries The Company received notice from the Louisiana Department of Wildlife and Fisheries (“LDWF”) in July 2017 stating that Exploration has open Coastal Use Permits (“CUPs”) located within the Louisiana Public Oyster Seed Grounds dating back from as early as November 1993 and through a period ending in November 2012. The majority of the claims relate to permits that were filed from 2000 to 2005. Pursuant to the conditions of each CUP, LDWF is alleging that damages were caused to the oyster seed grounds and that compensation of an aggregate amount of approximately $500,000 is owed by the Company. The Company is currently evaluating the merits of the claim, is reviewing the LDWF analysis, and has now requested that the LDWF revise downward the amount of area their claims of damages pertain to. At this point in the regulatory process, no evaluation of the likelihood of an unfavorable outcome or associated economic loss can be made; therefore no liability has been recorded on the Company’s consolidated financial statements. Miami Corporation – South Pecan Lake Field Area P&A The Company, along with several other exploration and production companies in the chain of title, received letters in June 2017 from representatives of Miami Corporation demanding the performance of well plugging and abandonment, facility removal and restoration obligations for wells in the South Pecan Lake Field Area, Cameron Parish, Louisiana. Apache is one of the other companies in the chain of title, and after taking a field tour of the area, has sent to the Company, along with BP and other companies in the chain of title, a proposed work plan to comply with the Miami Corporation demand. The Company is currently evaluating the merits of the claim and the proposed work plan. At this point in the process, no evaluation of the likelihood of an unfavorable outcome or associated economic loss can be made; therefore no liability has been recorded on the Company’s consolidated financial statements.

16. SUBSEQUENT EVENTS

16. SUBSEQUENT EVENTS	3 Months Ended
	Mar. 31, 2018
Subsequent Events [Abstract]
SUBSEQUENT EVENTS	The Company is not aware of any subsequent events which would require recognition or disclosure in its consolidated financial statements, except as noted below or disclosed in the Company’s filings with the SEC. On May 8, 2018, the Company entered into the Limited Waiver and Second Amendment to its Credit Agreement and Borrowing Base Redetermination with its lender (see Note 2 – Liquidity and Going Concern and Note 11 – Debt and Interest Expense).

3. REVENUE RECOGNITION - ADOP23

3. REVENUE RECOGNITION - ADOPTION OF ASC 606, REVENUE FROM CONTRACTS WITH CUSTOMERS (Tables)	3 Months Ended
	Mar. 31, 2018
Revenue Recognition - Adoption Of Asc 606 Revenue From Contracts With Customers Tables
Disaggregation of revenue	Three Months Ended March 31, 2018 2017 Sales of natural gas and crude oil: Crude oil and condensate $ 3,066,258 $ 3,815,932 Natural gas 1,791,251 2,553,443 Natural gas liquids 788,027 775,049 Total revenues $ 5,645,536 $ 7,144,424

5. ASSET RETIREMENT OBLIGATIO24

5. ASSET RETIREMENT OBLIGATIONS (Tables)	3 Months Ended
	Mar. 31, 2018
Asset Retirement Obligation Disclosure [Abstract]
Asset retirement obligations	Three Months Ended March 31, 2018 Asset retirement obligations at December 31, 2017 $ 10,466,413 Liabilities incurred 25,940 Liabilities settled (194,422 ) Accretion expense 142,940 Revisions in estimated cash flows - Asset retirement obligations at March 31, 2018 $ 10,440,871

6. FAIR VALUE MEASUREMENTS (Tab

6. FAIR VALUE MEASUREMENTS (Tables)	3 Months Ended
	Mar. 31, 2018
Fair Value Disclosures [Abstract]
Fair value measurements by hierarchy	Fair value measurements at March 31, 2018 Significant Quoted prices other Significant in active observable unobservable markets inputs inputs (Level 1) (Level 2) (Level 3) Total Liabilities: Commodity derivatives – oil $ - $ 2,163,001 $ - $ 2,163,001 Commodity derivatives – gas - (201,696 ) - $ (201,696 ) Total liabilities $ - $ 1,961,305 $ - $ 1,961,305 Fair value measurements at December 31, 2017 Significant Quoted prices other Significant in active observable unobservable markets inputs inputs (Level 1) (Level 2) (Level 3) Total Liabilities: Commodity derivatives – oil $ - $ 1,517,410 $ - $ 1,517,410 Commodity derivatives – gas - (278,001 ) - $ (278,001 ) Total liabilities $ - $ 1,239,409 $ - $ 1,239,409

7. COMMODITY DERIVATIVE INSTR26

7. COMMODITY DERIVATIVE INSTRUMENTS (Tables)	3 Months Ended
	Mar. 31, 2018
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Commodity derivative instruments	2018 2019 Settlement Settlement (1) NATURAL GAS (MMBtu): Swaps Volume 1,245,893 373,906 Price $ 3.00 $ 3.00 CRUDE OIL (Bbls): Swaps Volume 140,818 156,320 Price $ 53.17 $ 53.77 (1) Represents volumes through March 2019.
Schedule of derivative assets and liablities	Fair value as of March 31, 2018 December 31, 2017 Asset commodity derivatives: Current assets $ 201,696 $ 295,304 Noncurrent assets - 118 201,696 295,422 Liability commodity derivatives: Current liabilities (1,677,767 ) (1,198,307 ) Noncurrent liabilities (485,234 ) (336,524 ) (2,163,001 ) (1,534,831 ) Total commodity derivative instruments $ (1,961,305 ) $ (1,239,409 )
Gains (losses) from commodity derivatives	Three Months Ended March 31, 2018 2017 Derivative settlements $ (529,364 ) $ 98,700 Mark to market on commodity derivatives (721,896 ) 3,458,083 Net gains (losses) from commodity derivatives $ (1,251,260 ) $ 3,556,783

10. NET INCOME (LOSS) PER COM27

10. NET INCOME (LOSS) PER COMMON SHARE (Tables)	3 Months Ended
	Mar. 31, 2018
INCOME (LOSS) PER COMMON SHARE:
Reconciliation of earnings (loss) per common share	Three Months Ended March 31, 2018 2017 Net income (loss) attributable to common stockholders $ (3,536,937 ) $ 2,262,515 Weighted average common shares outstanding Basic 22,813,130 12,211,256 Add potentially dilutive securities: Unvested restricted stock awards - 67,855 Stock appreciation rights - - Stock options - - Series D preferred stock - 1,777,059 Diluted weighted average common shares outstanding 22,813,130 14,056,170 Net income (loss) per common share: Basic $ (0.16 ) $ 0.19 Diluted $ (0.16 ) $ 0.16

11. DEBT AND INTEREST EXPENSE (

11. DEBT AND INTEREST EXPENSE (Tables)	3 Months Ended
	Mar. 31, 2018
Debt Disclosure [Abstract]
Debt	March 31, December 31, 2018 2017 Senior credit facility $ 27,050,000 $ 27,700,000 Installment loan due 7/22/18 originating from the financing of insurance premiums at 5.14% interest rate 374,499 651,124 Total debt 27,424,499 28,351,124 Less: current maturities (27,424,499 ) (651,124 ) Total long-term debt $ - $ 27,700,000

3. REVENUE RECOGNITION - ADOP29

3. REVENUE RECOGNITION - ADOPTION OF ASC 606, REVENUE FROM CONTRACTS WITH CUSTOMERS (Details) - USD ($)	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Sales of natural gas and crude oil	$ 5,645,536	$ 7,144,424
Crude oil and condensate
Sales of natural gas and crude oil	3,066,258	3,815,932
Natural gas
Sales of natural gas and crude oil	1,791,251	2,553,443
Natural gas liquids
Sales of natural gas and crude oil	$ 788,027	$ 775,049

4. ASSET IMPAIRMENTS (Details N

4. ASSET IMPAIRMENTS (Details Narrative) - USD ($)	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Asset Impairments Details Narrative
Oil and gas impairment	$ 0	$ 0

5. ASSET RETIREMENT OBLIGATIO31

5. ASSET RETIREMENT OBLIGATIONS (Details) - USD ($)	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Asset Retirement Obligation Disclosure [Abstract]
Asset retirement obligations, beginning	$ 10,466,413
Liabilities incurred	25,940
Liabilities settled	(194,422)
Accretion expense	142,940	$ 138,569
Revisions in estimated cash flows	0
Asset retirement obligations, ending	$ 10,440,871

6. FAIR VALUE MEASUREMENTS (Det

6. FAIR VALUE MEASUREMENTS (Details) - USD ($)	Mar. 31, 2018	Dec. 31, 2017
Total liabilities	$ 1,961,305	$ 1,239,409
Commodity derivatives - oil
Derivative liability	2,163,001	1,517,410
Commodity derivatives - gas
Derivative liability	(201,696)	(278,001)
Quoted prices in active markets (Level 1)
Total liabilities	0	0
Quoted prices in active markets (Level 1) | Commodity derivatives - oil
Derivative liability	0	0
Quoted prices in active markets (Level 1) | Commodity derivatives - gas
Derivative liability	0	0
Significant other observable inputs (Level 2)
Total liabilities	1,961,305	1,239,409
Significant other observable inputs (Level 2) | Commodity derivatives - oil
Derivative liability	2,163,001	1,517,410
Significant other observable inputs (Level 2) | Commodity derivatives - gas
Derivative liability	(201,696)	(278,001)
Significant unobservable inputs (Level 3)
Total liabilities	0	0
Significant unobservable inputs (Level 3) | Commodity derivatives - oil
Derivative liability	0	0
Significant unobservable inputs (Level 3) | Commodity derivatives - gas
Derivative liability	$ 0	$ 0

7. COMMODITY DERIVATIVE INSTR33

7. COMMODITY DERIVATIVE INSTRUMENTS (Details) - Swaps	Dec. 31, 2019bblMMBbls$ / bbl$ / MMBTU	[1]	Dec. 31, 2018bblMMBbls$ / bbl$ / MMBTU
Natural Gas (MMBtu):
Volume | MMBbls	373,906		1,245,893
Price | $ / MMBTU	3		3
Crude Oil:
Volume | bbl	156,320		140,818
Price | $ / bbl	53.77		53.17
[1]	Represents volumes through March 2019.

7. COMMODITY DERIVATIVE INSTR34

7. COMMODITY DERIVATIVE INSTRUMENTS (Details 1) - USD ($)	Mar. 31, 2018	Dec. 31, 2017
Asset commodity derivatives:
Current assets	$ 201,696	$ 295,304
Noncurrent assets	0	118
Total	201,696	295,422
Liability commodity derivatives:
Current liabilities	(1,677,767)	(1,198,307)
Noncurrent liabilities	(485,234)	(336,524)
Total	(2,163,001)	(1,534,831)
Total commodity derivative instruments	$ (1,961,305)	$ (1,239,409)

7. COMMODITY DERIVATIVE INSTR35

7. COMMODITY DERIVATIVE INSTRUMENTS (Details 2) - USD ($)	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
C. Commodity Derivative Instruments Details 1
Derivative settlements	$ (529,364)	$ 98,700
Mark to market on commodity derivatives	(721,896)	3,458,083
Net gains (losses) from commodity derivatives	$ (1,251,260)	$ 3,556,783

10. NET INCOME (LOSS) PER COM36

10. NET INCOME (LOSS) PER COMMON SHARE (Details) - USD ($)	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
INCOME (LOSS) PER COMMON SHARE:
Net income (loss) attributable to common stockholders	$ (3,536,937)	$ 2,262,515
Weighted average common shares outstanding
Basic	22,813,130	12,211,256
Add potentially dilutive securities
Unvested restricted stock awards	0	67,855
Stock appreciation rights	0	0
Stock options	0	0
Series D preferred stock	0	1,777,059
Diluted weighted average common shares outstanding	22,813,130	14,056,170
Net income (loss) per common share:
Basic	$ (0.16)	$ 0.19
Diluted	$ (0.16)	$ 0.16

11. DEBT AND INTEREST EXPENSE37

11. DEBT AND INTEREST EXPENSE (Details) - USD ($)	Mar. 31, 2018	Dec. 31, 2017
Total Debt	$ 27,424,499	$ 28,351,124
Less: current maturities	(27,424,499)	(651,124)
Total long-term debt	0	27,700,000
Senior Credit Facility [Member]
Total Debt	27,050,000	27,700,000
Installment loan due 7/22/18 [Member]
Total Debt	$ 374,499	$ 651,124