UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C.  20549

FORM 10-Q

x QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2016

o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from                        to

Commission File Number: 001-32989

Yuma Energy, Inc.

(Exact name of registrant as specified in its charter)

CALIFORNIA (State or other jurisdiction of incorporation) 94-0787340 (IRS Employer Identification No.)

1177 West Loop South, Suite 1825 Houston, Texas (Address of principal executive offices)   77027 (Zip Code)

(713) 968-7000

(Registrant’s telephone number, including area code)

N/A

(Former name, former address and former fiscal year, if changed since last report)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x   No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x   No o

Indicate by check mark whether the registrant is a large accelerated file, an accelerated file, a non-accelerated filer, or a smaller reporting company.  See the definitions of “large accelerated file,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Larger accelerated filer o                                                                                               Accelerated filer o

Non-accelerated filer o(Do not check if a smaller reporting company)                Smaller reporting company x

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o   No x

At May 23, 2016, 72,000,427 shares of the registrant’s common stock, no par value, were outstanding.

TABLE OF CONTENTS

	PART I – FINANCIAL INFORMATION
Item 1.	Financial Statements.
		Consolidated Balance Sheets as of March 31, 2016 and December 31, 2015.	3
		Consolidated Statements of Operations for the Three Months ended March 31, 2016 and 2015.	5
		Consolidated Statements of Comprehensive Income for the Three Months ended March 31, 2016 and 2015.	6
		Consolidated Statements of Changes in Equity for the Three Months ended March 31, 2016 and the year ended December 31, 2015.	7
		Consolidated Statements of Cash Flows for the Three Months ended March 31, 2016 and 2015.	8
		Unaudited Condensed Notes to the Consolidated Financial Statements.	9
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations.		24
Item 3.	Quantitative and Qualitative Disclosures About Market Risk.		37
Item 4.	Controls and Procedures.		37
	PART II – OTHER INFORMATION
Item 1.	Legal Proceedings.		38
Item 1A.	Risk Factors.		38
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds.		38
Item 3.	Defaults Upon Senior Securities.		38
Item 4.	Mine Safety Disclosures.		39
Item 5.	Other Information.		39
Item 6.	Exhibits.		40
	Signatures.		41

EXPLANATORY NOTE

Restatement Background

On May 11, 2016, subsequent to the filing of our Form 10-K for the year ended December 31, 2015 (the “2015 Form 10-K”), we determined that there were  non-cash errors in the computation of our income tax provision and the recording of our deferred taxes related to our asset retirement obligations, our stock based compensation, our allocation of the purchase price in the Pyramid merger and resultant amount of goodwill, the tax amortization of that goodwill, the tax treatment of expenses related to the Pyramid merger, the incorrect roll forward of the historic net operating losses and the difference in the book and the tax basis in our properties. As a result, our income tax provision and the net amount of our deferred tax liability were restated for the years ended December 31, 2015, 2014 and 2013 and the applicable quarterly periods in 2015 and 2014.

As a result, management, the Audit Committee and the Board of Directors determined after consideration of the relevant facts and circumstances, that our consolidated financial statements as of December 31, 2015 and 2014, and for the years ended December 31, 2015, 2014 and 2013 contained within the 2015 Form 10-K, and our financial data included in our interim consolidated financial statements set forth in our quarterly reports on Form 10-Q for the quarter ended September 30, 2014, and for all subsequent quarters through the quarter ended December 31, 2015, should be restated, and that such financial statements previously filed with the Securities and Exchange Commission (“SEC”), should no longer be relied upon. Additionally, it was determined that the Company should, as soon as practicable, file with the SEC an amendment to the 2015 Form 10-K, inclusive of restated financial data pertaining to each applicable quarterly period in 2015 and 2014.

On May 23, 2016, the Company filed Amendment No. 1 to its Annual Report on Form 10-K for the year ended December 31, 2015 (the “Amended Filing”). Prior period financial information in this Form 10-Q has been amended where necessary to reflect the restatement. Therefore, this Form 10-Q should be read in conjunction with the Amended Filing. Additional information regarding the restatement is contained in the Amendment Filing.

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements.

Yuma Energy, Inc.

CONSOLIDATED BALANCE SHEETS

	March 31,
	2016			December 31,
	(Unaudited)			2015
ASSETS				(As Restated)
CURRENT ASSETS:
Cash and cash equivalents	$	3,074,286		$	5,355,191
Accounts receivable, net of allowance for doubtful accounts:
Trade		2,536,812			2,829,266
Officers and employees		21,562			75,404
Other		667,342			633,573
Commodity derivative instruments		2,140,162			2,658,047
Prepayments		457,945			704,523
Other deferred charges		174,983			415,740
Total current assets		9,073,092			12,671,744
OIL AND GAS PROPERTIES (full cost method):
Not subject to amortization		14,606,401			14,288,716
Subject to amortization		204,949,817			204,512,038
		219,556,218			218,800,754
Less:  accumulated depreciation, depletion and amortization		(119,690,987	)		(117,304,945	)
Net oil and gas properties		99,865,231			101,495,809
OTHER PROPERTY AND EQUIPMENT:
Land, buildings and improvements		2,795,000			2,795,000
Other property and equipment		3,460,507			3,460,507
		6,255,507			6,255,507
Less: accumulated depreciation and amortization		(2,234,675	)		(2,174,316	)
Net other property and equipment		4,020,832			4,081,191
OTHER ASSETS AND DEFERRED CHARGES:
Commodity derivative instruments		800,250			1,070,541
Deposits		414,064			264,064
Other noncurrent assets		-			38,104
Total other assets and deferred charges		1,214,314			1,372,709
TOTAL ASSETS	$	114,173,469		$	119,621,453

The accompanying notes are an integral part of these financial statements.

3

Yuma Energy, Inc.

CONSOLIDATED BALANCE SHEETS – CONTINUED

	March 31,
	2016			December 31,
	(Unaudited)			2015
LIABILITIES AND EQUITY				(As Restated)
CURRENT LIABILITIES:
Current maturities of debt	$	29,862,186		$	30,063,635
Accounts payable, principally trade		6,424,557			7,933,664
Asset retirement obligations		470,607			70,000
Other accrued liabilities		1,781,611			1,781,484
Total current liabilities		38,538,961			39,848,783
OTHER NONCURRENT LIABILITIES:
Asset retirement obligations		8,368,545			8,720,498
Deferred taxes		884,431			1,417,364
Other liabilities		21,924			30,090
Total other noncurrent liabilities		9,274,900			10,167,952
EQUITY:
Preferred stock		10,828,603			10,828,603
Common stock, no par value (300 million shares authorized, 71,911,361 and 71,834,617 issued)		142,286,922			141,858,946
Accumulated earnings (deficit)		(86,755,917	)		(83,082,831	)
Total equity		66,359,608			69,604,718
TOTAL LIABILITIES AND EQUITY	$	114,173,469		$	119,621,453

The accompanying notes are an integral part of these financial statements.

4

Yuma Energy, Inc.

CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

	Three Months Ended March 31,
	2016			2015
				(As Restated)
REVENUES:
Sales of natural gas and crude oil	$	2,931,586		$	4,572,679
Net gains from commodity derivatives		370,938			1,070,568
Total revenues		3,302,524			5,643,247
EXPENSES:
Lease operating		2,013,149			3,223,116
Re-engineering and workovers		-			494,429
Marketing cost of sales		-			101,688
General and administrative – stock-based compensation		418,290			1,738,410
General and administrative – other		2,157,486			1,672,212
Depreciation, depletion and amortization		2,446,401			4,141,020
Asset retirement obligation accretion expense		105,014			162,784
Other		(25,432	)		11,311
Total expenses		7,114,908			11,544,970
INCOME (LOSS) FROM OPERATIONS		(3,812,384	)		(5,901,723	)
OTHER INCOME (EXPENSE):
Interest expense		(402,648	)		(92,007	)
Other, net		9,013			16,156
Total other income (expense)		(393,635	)		(75,851	)
NET INCOME (LOSS) BEFORE INCOME TAXES		(4,206,019	)		(5,977,574	)
Income tax benefit		(532,933	)		(2,294,582	)
NET INCOME (LOSS)		(3,673,086	)		(3,682,992	)
PREFERRED STOCK:
Dividends paid in cash, perpetual preferred Series A		-			300,815
Dividends in arrears, perpetual preferred Series A		320,626			-
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCKHOLDERS	$	(3,993,712	)	$	(3,983,807	)
EARNINGS (LOSS) PER COMMON SHARE:
Basic	$	(0.06	)	$	(0.06	)
Diluted	$	(0.06	)	$	(0.06	)
WEIGHTED AVERAGE NUMBER OF COMMON SHARES OUTSTANDING
Basic		71,911,361			69,253,681
Diluted		71,911,361			69,253,681

The accompanying notes are an integral part of these financial statements.

5

Yuma Energy, Inc.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(Unaudited)

	Three Months Ended March 31,
	2016			2015
				(As Restated)
NET INCOME (LOSS)	$	(3,673,086	)	$	(3,682,992	)
OTHER COMPREHENSIVE INCOME (LOSS):
Commodity derivatives sold		-			(119,917	)
Less income taxes		-			(46,168	)
Commodity derivatives sold, net of income taxes		-			(73,749	)
Reclassification of (gain) loss on settled commodity derivatives		-			23,436
Less income taxes		-			9,023
Reclassification of (gain) loss on settled commodity derivatives,
net of income taxes		-			14,413
OTHER COMPREHENSIVE INCOME (LOSS)		-			(59,336	)
COMPREHENSIVE INCOME (LOSS)	$	(3,673,086	)	$	(3,742,328	)

The accompanying notes are an integral part of these financial statements.

6

Yuma Energy, Inc.

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

	March 31,
	2016			December 31,
	(Unaudited)			2015
				(As Restated)
PERPETUAL PREFERRED STOCK - 9.25% CUMULATIVE AND REDEEMABLE, NO PAR VALUE:
Balance at beginning of period: 554,596 for 2016 and 507,739 shares for 2015	$	10,828,603		$	9,958,217
Sales of 46,857 shares for 2015		-			870,386
Balance at end of period: 554,596 shares for both 2016 and 2015		10,828,603			10,828,603
COMMON STOCK, NO PAR VALUE:
Balance at beginning of period: 71,834,617 shares for 2016 and 69,139,869 shares for 2015		141,858,946			137,469,772
Restricted stock awards, of which 76,744 vested in 2016 and 1,676,113 vested in 2015		322,507			3,171,477
Sales of 1,347,458 shares of common stock for 2015		-			1,363,160
Buy back of 328,823 shares from vested stock awards		-			(300,732	)
Stock appreciation rights issued, not vested		105,469			155,269
Balance at end of period: 71,911,361 shares for 2016 and 71,834,617 shares for 2015		142,286,922			141,858,946
ACCUMULATED OTHER COMPREHENSIVE INCOME:
Balance at beginning of period		-			38,801
Comprehensive income (loss) from commodity derivative instruments, net of income taxes		-			(38,801	)
Balance at end of period		-			-
ACCUMULATED EARNINGS (DEFICIT):
Balance at beginning of period		(83,082,831	)		(67,195,800	)
Net loss		(3,673,086	)		(14,839,840	)
Series A perpetual preferred stock cash dividends		-			(1,047,191	)
Balance at end of period		(86,755,917	)		(83,082,831	)
TOTAL EQUITY	$	66,359,608		$	69,604,718

The accompanying notes are an integral part of these financial statements.

7

Yuma Energy, Inc.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Three Months Ended March 31,
	2016			2015
				(As Restated)
CASH FLOWS FROM OPERATING ACTIVITIES:
Reconciliation of net loss to net cash provided by (used in) operating activities
Net loss	$	(3,673,086	)	$	(3,682,992	)
Depreciation, depletion and amortization of property and equipment		2,446,401			4,141,020
Accretion of asset retirement obligation		105,014			162,784
Stock-based compensation net of capitalized cost		418,290			1,738,410
Amortization of other assets and liabilities		262,474			65,145
Deferred tax expense (benefit)		(532,933	)		(2,294,582	)
Bad debt expense increase (decrease)		(25,432	)		11,311
Amortization of benefit from commodity derivatives (sold) and purchased, net		-			(119,917	)
Unrealized (gains) losses on commodity derivatives		788,176			3,866,266
Changes in current operating assets and liabilities:
Accounts receivable		337,959			3,680,915
Other current assets		246,578			206,467
Accounts payable		(987,980	)		(10,800,637	)
Other current liabilities		(14,194	)		367,639
Other noncurrent assets and liabilities		(108,618	)		-
NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES		(737,351	)		(2,658,171	)
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures on property and equipment		(1,322,128	)		(5,963,281	)
Proceeds from sale of property		1,740			30,442
Decrease (increase) in short-term investments		-			(10,431	)
NET CASH USED IN INVESTING ACTIVITIES		(1,320,388	)		(5,943,270	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Change in borrowing on line of credit		-			5,550,000
Payments on insurance note		(201,449	)		(220,658	)
Line of credit financing costs		(21,717	)		(221,373	)
Net proceeds from sale of common stock		-			298,259
Net proceeds from sale of perpetual preferred stock		-			708,590
Cash dividends to preferred shareholders		-			(300,815	)
Other		-			(4,783	)
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES		(223,166	)		5,809,220
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		(2,280,905	)		(2,792,221	)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD		5,355,191			11,558,322
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	3,074,286		$	8,766,101
Supplemental disclosure of cash flow information:
Interest payments (net of interest capitalized)	$	174,706		$	19,843
Interest capitalized	$	124,164		$	232,822
Supplemental disclosure of significant non-cash activity:
(Increase) decrease in capital expenditures financed by accounts payable	$	521,127		$	2,067,297

The accompanying notes are an integral part of these financial statements.

8

Yuma Energy, Inc.

UNAUDITED CONDENSED NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1 – BASIS OF PRESENTATION

These consolidated financial statements are unaudited; however, in the opinion of management, they reflect all adjustments necessary for a fair presentation of the results for the periods reported.  All such adjustments are of a normal recurring nature unless disclosed otherwise.  These consolidated financial statements, including notes, have been condensed and do not include all of the information and disclosures required by accounting principles generally accepted in the United States of America (“GAAP”) for complete financial statements.  These consolidated financial statements should be read in conjunction with the consolidated financial statements as of and for the year ended December 31, 2015 and the notes thereto included with the Annual Report on Form 10-K/A of Yuma Energy, Inc. (the “Company”) filed with the Securities and Exchange Commission (“SEC”) on May 23, 2016.

Restatement Background

On May 11, 2016, subsequent to the filing of the Company’s Form 10-K for the year ended December 31, 2015 (the “2015 Form 10-K”), the Company determined that there were non-cash errors in the computation of our income tax provision and the recording of our deferred taxes related to our asset retirement obligations, our stock based compensation, our allocation of the purchase price in the Pyramid merger and resultant amount of goodwill, the tax amortization of that goodwill, the tax treatment of expenses related to the Pyramid merger, the incorrect roll forward of the historic net operating losses and the difference in the book and the tax basis in our properties. As a result, the Company’s computation of its income tax provision and the net amount of its deferred tax liability were restated for the years ended December 31, 2015, 2014 and 2013 and the applicable quarterly periods in 2015 and 2014.

As a result, management, the Audit Committee and the Board of Directors determined after consideration of the relevant facts and circumstances, that the Company’s consolidated financial statements as of December 31, 2015 and 2014, and for the years ended December 31, 2015, 2014 and 2013 contained within the 2015 Form 10-K, and the financial data included in its interim consolidated financial statements set forth in its quarterly reports on Form 10-Q for the quarter ended September 30, 2014, and for all subsequent quarters through the quarter ended December 31, 2015, should be restated, and that such financial statements previously filed with the SEC, should no longer be relied upon. Additionally, it was determined that the Company should, as soon as practicable, file with the SEC an amendment to the 2015 Form 10-K, inclusive of restated financial data pertaining to each applicable quarterly period in 2015 and 2014.

On May 23, 2016, the Company filed Amendment No. 1 to its Annual Report on Form 10-K for the year ended December 31, 2015 (the “Amended Filing”). Prior period financial information in this Form 10-Q has been amended where necessary to reflect the restatement. Therefore, this Form 10-Q should be read in conjunction with the Amended Filing.

NOTE 2 – LIQUIDITY CONSIDERATIONS AND GOING CONCERN

The Company has borrowings which require, among other things, compliance with certain financial ratios.  Due to operating losses the Company has sustained during recent quarters as a result of the prolonged weak commodity price environment and other factors, the Company was not in compliance with the trailing four quarter funded debt to EBITDA financial ratio covenant under its credit facility at September 30, 2015, December 31, 2015 or at March 31, 2016, as well as its EBITDA to interest expense ratio as of December 31, 2015 and March 31, 2016. In addition, the Company was not in compliance due to its going concern opinion at March 31, 2016, as well as its failure to maintain a certain financial bank as its principal depository bank.  On May 20, 2016, the Company remedied its compliance with regard to the depository bank.  On December 30, 2015, the Company entered into the Waiver, Borrowing Base Redetermination and Ninth Amendment to the credit agreement which provided for a $29.8 million conforming borrowing base, which will be automatically reduced to $20.0 million on May 31, 2016 unless otherwise reduced by or adjusted to a different number by the lenders under the credit agreement, and waived the compliance with the trailing four quarter funded debt to EBITDA and EBITDA to interest expense financial ratio covenants or any other events of default under the credit facility for the quarters ended September 30, 2015 and December 31, 2015.  As of December 31, 2015, the Company had a working capital deficit of $27.2 million inclusive of the Company’s outstanding debt under its credit facility, which was fully drawn with no additional borrowing capacity available.

9

A breach of any of the terms and conditions of the credit agreement or a breach of the financial covenants under the Company’s credit facility could result in acceleration of the Company’s indebtedness, in which case the debt would become immediately due and payable. Given that the Company is in violation of the funded debt to EBITDA and EBITDA to interest expense covenants as of March 31, 2016, the Company has classified its bank debt as a current liability in its financial statements. The Company is currently in discussions with the lenders participating in the Company’s credit facility to obtain a waiver of those violations.

During 2015, the Company initiated several strategic alternatives to remedy its debt covenant compliance issues and provide working capital to develop the Company’s existing assets. On February 10, 2016, the Company entered into an Agreement and Plan of Merger and Reorganization with Davis Petroleum Acquisition Corp. (“Davis”) for an all-stock transaction. Upon completion of the transaction, which is subject to the approval of the stockholders of both companies and other conditions, Davis will become a wholly owned subsidiary of the Company. Subject to bank approval, it is anticipated that the Company will enter into another credit agreement amendment that will take into account the contemplated merger with Davis (see Note 14 – Agreement and Plan of Merger and Reorganization). However, the Company’s management can provide no assurance that the merger with Davis and the amendment to the credit agreement will actually occur.

The significant risks and uncertainties described above raise substantial doubt about the Company’s ability to continue as a going concern. The consolidated financial statements have been prepared on a going concern basis of accounting, which contemplates continuity of operations, realization of assets, and satisfaction of liabilities and commitments in the normal course of business. The consolidated financial statements do not include any adjustments that might result from the outcome of the going concern uncertainty.

NOTE 3 – ACCOUNTING STANDARDS

Not Yet Adopted

In March 2016, the Financial Accounting Standards Board (“FASB”) issued an update which seeks to simplify accounting for share-based payment transactions including income tax consequences, classification of awards as either equity or liabilities, and the classification on the statement of cash flows. The new standard requires the Company to recognize the income tax effects of awards in the income statement when the awards vest or are settled. The guidance is effective for fiscal years beginning after December 15, 2016. Early adoption is permitted and if an entity early adopts the guidance in an interim period, any adjustments must be reflected as of the beginning of the fiscal year that includes that interim period. The Company is currently evaluating the impact of adopting this standard on its Consolidated Financial Statements.

In February 2016, the FASB issued a new lease standard requiring lessees to recognize lease assets and lease liabilities for most leases classified as operating leases under previous GAAP. The guidance is effective for fiscal years beginning after December 15, 2018 with early adoption permitted. The Company will be required to use a modified retrospective approach for leases that exist or are entered into after the beginning of the earliest comparative period in the financial statements. The Company is currently evaluating the impact of adopting this standard on its Consolidated Financial Statements.

In May 2014, the FASB issued an update which removes inconsistencies in existing standards, changes the way companies recognize revenue from contracts with customers, and increases disclosure requirements. The guidance requires companies to recognize revenue to depict the transfer of goods or services to customers in amounts that reflect the consideration to which the company expects to be entitled in exchange for those goods or services. In March 2016, the FASB issued guidance which provides further clarification on the principal versus agent evaluation. The guidance is effective for annual and interim periods beginning after December 15, 2017. The standard is required to be adopted using either the full retrospective approach, with all prior periods presented adjusted, or the modified retrospective approach, with a cumulative adjustment to retained earnings on the opening balance sheet. The Company is currently evaluating the level of effort needed to implement the standard, the impact of adopting this standard on its Consolidated Financial Statements, and whether to use the full retrospective approach or the modified retrospective approach.

Recently Adopted

In April 2015, the FASB issued an update that requires debt issuance costs to be presented in the balance sheet as a direct reduction from the associated debt liability.  In August 2015, the FASB subsequently issued a clarification as to the handling of debt issuance costs related to line-of-credit arrangements that allows the presentation of these costs as an asset.  The standards update is effective for interim and annual periods beginning after December 15, 2015.  The Company has debt costs associated with its line-of-credit only; therefore, this standard had no impact on its Consolidated Financial Statements.  These costs remain an asset on the Company’s Balance Sheet.

10

In February 2015, the FASB issued an amendment to the guidance for determining whether an entity is a variable interest entity (“VIE”).  The standard does not add or remove any of the five characteristics that determine if an entity is a VIE.  However, it does change the manner in which a reporting entity assesses one of the characteristics.  In particular, when decision-making over the entity’s most significant activities has been outsourced, the standard changes how a reporting entity assesses if the equity holders at risk lack decision making rights.  This standard is effective for the Company for annual periods beginning after December 15, 2015 and early adoption is permitted, including in interim periods.  The Company adopted this standard’s update, as required, effective January 1, 2016.  The adoption of this standard’s update did not have a material impact on its Consolidated Financial Statements.

NOTE 4 – 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 Derivatives, 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 and are considered Level 1.

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 at March 31, 2016, the Company has not considered non-performance risk in the valuation of its derivatives.

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.

	Fair value measurements at March 31, 2016
			Significant
	Quoted prices		other		Significant
	in active		observable		unobservable
	markets		inputs		inputs
	(Level 1)		(Level 2)		(Level 3)		Total
Assets:
Commodity derivatives – oil	$	-	$	2,735,087	$	-	$	2,735,087
Commodity derivatives – gas		-		205,325		-		205,325
Total assets	$	-	$	2,940,412	$	-	$	2,940,412

11

	Fair value measurements at December 31, 2015
			Significant
	Quoted prices		other		Significant
	in active		observable		unobservable
	markets		inputs		inputs
	(Level 1)		(Level 2)		(Level 3)		Total
Assets:
Commodity derivatives – oil	$	-	$	3,442,693	$	-	$	3,442,693
Commodity derivatives – gas		-		285,895		-		285,895
Total assets	$	-	$	3,728,588	$	-	$	3,728,588

Derivative instruments listed above include swaps, reverse swaps and three-way collars.  For additional information on the Company’s derivative instruments and derivative liabilities, see Note 5 – Commodity Derivative Instruments.

Debt – The Company’s debt is recorded at the carrying amount on its Consolidated Balance Sheets.  For further discussion of the Company’s debt, please see Note 9 – Debt and Interest Expense.  The carrying amount of floating-rate debt approximates fair value because the interest rates are variable and reflective of market rates.

Asset Retirement Obligations (“AROs”) – The Company estimates the fair value of AROs 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.

NOTE 5 – 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.

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 remained in accumulated other comprehensive income (“AOCI”) until the original hedged forecasted transaction occurred.  The last of these contracts expired in December 2015 and the Company’s AOCI balance is now zero.  No mark-to-market adjustments for commodity derivative contracts are made to AOCI, but instead are recognized in earnings.  As a result of discontinuing the application of hedge accounting, the Company’s earnings are potentially more volatile.  See Note 4 – 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 Société Générale (“SocGen”) whose long-term senior unsecured debt is rated “A” by Standard and Poor’s, “A2” by Moody’s, “A” by Fitch and “A(high)” by DBRS.  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.

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On February 18, 2015, the Company settled all of its natural gas and crude oil options, realizing $4.03 million.  The Company retained its existing natural gas swap positions.  Concurrent with the settlement of the Company’s option positions and during the following day, the Company entered into new swap transactions for crude oil and natural gas for the balance of 2015 and all of 2016.  In addition, the Company entered into three-way collars for 2017 for both natural gas and crude oil.

In conjunction with certain derivative hedging activity, the Company deferred the payment of $153,389 put premiums which was recorded in both current other deferred charges and current other accrued liabilities at year-end 2014 and was for production months January 2015 through December 2015.  The put premium liabilities became payable monthly as the hedge production month became the prompt production month.  The Company amortized the deferred put premium liabilities in January and February 2015; however, the liability for the remainder of the year was settled as part of the $4.03 million settlement.

Commodity derivative instruments open as of March 31, 2016 are provided below.  Natural gas prices are New York Mercantile Exchange (“NYMEX”) Henry Hub prices, and crude oil prices are Argus Light Louisiana Sweet (“LLS”).

	2016			2017
	Settlement			Settlement
NATURAL GAS (MMBtu):
Swaps
Volume		406,655			-
Price	$	2.657	*		-
3-way collars
Volume		-			248,023
Ceiling sold price (call)		-		$	3.280	*
Floor purchased price (put)		-		$	2.946	*
Floor sold price (short put)		-		$	2.381	*
CRUDE OIL (Bbls):
Put spread
Volume		98,902			-
Floor purchased price (put)	$	62.27			-
Floor sold price (short put)	$	40.00			-
3-way collars
Volume		23,449			113,029
Ceiling sold price (call) (WTI)	$	47.15		$	77.00
Floor purchased price (put) (WTI)	$	40.00		$	60.00
Floor sold price (short put) (WTI)	$	30.00		$	45.00
Swaps
Volume		11,533			-
Price	$	40.25			-

           *Price is a weighted average

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:

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	Fair value as of
	March 31,			December 31,
	2016			2015
Asset commodity derivatives:
Current assets	$	2,765,219		$	3,069,115
Noncurrent assets		1,467,664			1,841,120
		4,232,883			4,910,235
Liability commodity derivatives:
Current liabilities		(625,057	)		(411,068	)
Noncurrent liabilities		(667,414	)		(770,579	)
		(1,292,471	)		(1,181,647	)
Total commodity derivative instruments	$	2,940,412		$	3,728,588

Sales of natural gas and crude oil on the Consolidated Statements of Operations are comprised of the following:

	Three Months Ended
	March 31,
	2016			2015
Sales of natural gas and crude oil	$	2,931,586		$	4,572,679
Gains (losses) realized from sale of commodity derivatives		-			4,030,000
Other gains (losses) realized on commodity derivatives		1,159,114			906,834
Unrealized gains (losses) on commodity derivatives		(788,176	)		(3,866,266	)
Total revenue from natural gas and crude oil	$	3,302,524		$	5,643,247

A reconciliation of the components of accumulated other comprehensive income (loss) in the Consolidated Statements of Changes in Equity is presented below:

	Three Months Ended				Year Ended
	March 31, 2016				December 31, 2015
	Before tax		After tax		Before tax			After tax
Balance, beginning of period	$	-	$	-	$	63,091		$	38,801
Sale of unexpired contracts previously subject
to hedge accounting rules		-		-		(119,917	)		(73,749	)
Other reclassifications due to expired contracts
previously subject to hedge accounting rules		-		-		56,826			34,948
Balance, end of period	$	-	$	-	$	-		$	-

NOTE 6 – PREFERRED STOCK

The Company’s shares 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”), 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 not to 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. Currently, dividend payments are suspended.

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NOTE 7 – STOCK-BASED COMPENSATION

The Yuma Co. 2011 Stock Option Plan (the “Yuma Co. Plan”) was adopted on June 21, 2011.  On September 10, 2014, the shareholders of Pyramid adopted the 2014 Long-Term Incentive Plan (the “2014 Plan”).  Under these plans, the Board of Directors is authorized to grant stock options, stock awards (including restricted stock and restricted stock unit awards) and performance awards to officers, directors, employees and consultants.  At March 31, 2016, 4,307,672 shares of the 8,900,000 shares of Yuma common stock originally authorized under active share-based compensation plans remained available for future issuance.  The Company generally issues new shares to satisfy awards under employee share-based payment plans.  The number of shares available is reduced by awards granted.

Restricted Stock – The Company granted restricted stock awards (“RSAs”) under the Yuma Co. Plan and the 2014 Plan in 2013, 2014 and 2015.  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 the Company’s transfer agent.

A summary of the status of the RSAs for employees and non-employees and changes for the period ended March 31, 2016 is presented below.

	Number of			Weighted average
	unvested			grant-date
	RSA shares			fair value
Unvested shares as of January 1, 2016		2,514,434		$0.87 per share
Vested on January 1, 2016		(76,744	)	$3.02 per share
Unvested shares as of March 31, 2016		2,437,690		$0.80 per share

At March 31, 2016, total unrecognized RSA compensation cost of $927,518 is expected to be recognized over a weighted average remaining service period of 1.35 years.

Stock Appreciation Rights – In 2015, the Company also granted Stock Appreciation Rights (“SARs”) to employees and non-employees under the 2014 Plan.  A summary of the status of these SARs and changes for the three months ended March 31, 2016 is presented below.

			Weighted
	Number of		average
	unvested		grant-date
	SARs		fair value
Unvested shares as of January 1, 2016		1,912,419	$0.30 per share
Vested, forfeited, or other changes		-
Unvested shares as of March 31, 2016		1,912,419	$0.30 per share

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Weighted average assumptions used to estimate fair value for employees were expected life of five years, 61.17% volatility, 1.60% risk-free rate, and zero annual dividends.

Stock compensation cost for consultants is adjusted at the end of each reporting period to reflect the cost based on the closing stock price at the end of that reporting period.  That price was $0.21 at March 31, 2016 and was used to compute a new fair value of $0.03 per share.  Weighted average assumptions used to estimate fair value were expected option life of .66 years, 134% volatility, 0.59% risk-free interest rate, and zero expected dividend rate.

At March 31, 2016, total unrecognized SAR compensation cost of $311,864 is expected to be recognized over a weighted average remaining service period of 1.5 years.

The SARs in the tables above have a weighted average exercise price of $.605 and an aggregate intrinsic value of zero.  The Company intends to settle these SARs in equity, as opposed to cash.

Stock Options – Pyramid Oil Company issued stock options as compensation for non-employee members of its board of directors under the Pyramid Oil Company 2006 Equity Incentive Plan.  The options vested immediately, and are exercisable for a five-year period from the date of the grant.

The following is a summary of the Company’s stock option activity.

					Weighted-
			Weighted-		average
			average		remaining		Aggregate
			exercise		contractual		intrinsic
	Options		price		life (years)		value
Outstanding at December 31, 2015		105,000	$	5.17		2.65	$	-
Granted		-		-		-		-
Exercised		-		-		-		-
Forfeited		-		-		-		-
Outstanding at March 31, 2016		105,000	$	5.17		2.41	$	-
Vested at March 31, 2016		105,000	$	5.17		2.41	$	-
Exercisable at March 31, 2016		105,000	$	5.17		2.41	$	-

As of March 31, 2016, there were no unvested stock options or unrecognized stock option expenses.

The following table summarizes the information about stock options outstanding and exercisable at March 31, 2016.

		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		.17	$	5.40		5,000	$	5.40
$	5.16		100,000		2.52	$	5.16		100,000	$	5.16
			105,000						105,000

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Restricted Stock Units – On April 1, 2013, the Company granted 163 Restricted Stock Units 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); consequently, the awards are liability-based and the booked valuation will change as the market value for common stock changes.  At March 31, 2016, the RSUs were valued at the closing price of the common stock of the Company on that date.  Compensation expense was recognized over the three-year vesting period.  The RSUs vested on April 1, 2016 and were settled in cash for $16,858.

A summary of the status of the unvested RSUs and changes during the three months ended March 31, 2016 is presented below.

			Weighted
	Number of		average
	unvested		grant-date
	RSUs		fair value
Unvested shares as of January 1, 2016		80,278	$2.72 per share
Granted, forfeited, or other changes		-
Unvested shares as of March 31, 2016		80,278	$2.72 per share

NOTE 8 – EARNINGS (LOSS) PER COMMON SHARE

Earnings (loss) per common share is computed by dividing earnings or losses attributable 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 shares outstanding are as follows:

	Three Months Ended
	March 31,
	2016		2015
Restricted Stock Awards		2,437,690		1,910,349
Restricted Stock Units		-		95,424
		2,437,690		2,005,773

For the three months ended March 31, 2016 and the three months ended March 31, 2015, adjusted earnings were losses, therefore common stock equivalents were excluded from the calculation of diluted net loss per share of common stock, as their effect was anti-dilutive.  RSUs were settled in cash during April 2016 and are no longer considered potentially dilutive.

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NOTE 9 – DEBT AND INTEREST EXPENSE

	March 31,			December 31,
	2016			2015
Variable rate revolving credit agreement payable to Société Générale,
CIT Bank, NAC, and LegacyTexas Bank, maturing May 20, 2017,
secured by the stock of Exploration and its interest in POL, and
guaranteed by The Yuma Companies, Inc.	$	29,800,000		$	29,800,000
Installment loan due February 29, 2016, originating from the
financing of insurance premiums at 3.74% interest rate.		-			108,894
Installment loan due June 11, 2016, originating from the
financing of insurance premiums at 3.76% interest rate.		62,186			154,741
		29,862,186			30,063,635
Less:  current portion		(29,862,186	)		(30,063,635	)
Total long-term debt	$	-		$	-

On December 30, 2015, the Company’s wholly owned subsidiary, Yuma Exploration and Production Company, Inc. (“Exploration”) entered into the Waiver, Borrowing Base Redetermination and Ninth Amendment (“Ninth Amendment”) to the credit agreement dated August 10, 2011 with SocGen as Administrative Agent and Issuing Banks, and each of the lenders and guarantors.  Pursuant to the Ninth Amendment, the borrowing base was reduced to $29.8 million and will automatically be reduced to $20.0 million on May 31, 2016 unless otherwise reduced by or to a different amount by the lenders under the credit agreement.  The Ninth Amendment also provided a waiver of the financial covenant related to the maximum permitted ratio of funded debt to EBITDA for the fiscal quarter ended September 30, 2015 and any failure to comply with that financial covenant and certain other financial covenants for the fiscal quarter ended December 31, 2015.  Pursuant to the Ninth Amendment, Exploration agreed that on or before February 6, 2016, it would engage an investment bank to explore strategic options for its finances and, on or before March 31, 2016, would either enter into an underwritten commitment for additional capital in an aggregate amount sufficient to pay any borrowing base deficiency then existing or enter into a definitive agreement for the acquisition by a third party of all or substantially all of the assets of Exploration and its subsidiaries by merger, asset purchase, equity purchase or other structure acceptable to the Administrative Agent and the lenders.  On February 10, 2016, the Company entered into the merger agreement with Davis (see Note 14 – Agreement and Plan of Merger and Reorganization), and expects to enter into another amendment to the credit agreement to account for the contemplated merger with Davis.

Costs and fees paid to the banks in connection with the revolving credit facility are amortized through May 31, 2016, due to the possible accelerated maturity date pursuant to the Ninth Amendment.  SocGen, as Agent Bank, is also paid an annual administrative fee of $25,000 that is usually amortized over the year, but will also be amortized through May 31, 2016.

The 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 the Company.  Exploration was not in compliance with all of the loan covenants as of March 31, 2016; however, it is in discussion with the lenders under the credit facility to obtain a waiver of those violations.

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The following summarizes interest expense for the three months ended March 31, 2016 and 2015.

	Three Months Ended
	March 31,
	2016			2015
Credit agreement	$	257,728		$	241,294
Credit agreement commitment fees		-			15,828
Amortization of credit agreement loan costs		262,474			65,144
Insurance installment loan		1,670			1,726
Other interest charges		4,940			837
Capitalized interest		(124,164	)		(232,822	)
Total interest expense	$	402,648		$	92,007

NOTE 10 – MERGER WITH PYRAMID OIL COMPANY AND GOODWILL

On September 10, 2014, a wholly owned subsidiary of Pyramid merged with and into Yuma Energy, Inc., a Delaware corporation (“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”).

The merger was accounted for as a business combination in accordance with ASC 805 Business Combinations (“ASC 805”).  ASC 805, among other things, requires assets acquired and liabilities assumed to be measured at their acquisition date fair values.  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.  Certain assets and liabilities may be adjusted as additional information is obtained; but no later than one year from the acquisition date.  The provisions of ASC 350, on Intangibles – Goodwill and Other require that intangible assets with indefinite lives, including goodwill, be evaluated on an annual basis for impairment, or more frequently if events occur or circumstances change that could potentially result in impairment.  The goodwill impairment test requires the allocation of goodwill and all other assets and liabilities to reporting units; however, the Company has only one reporting unit.  The Company was to perform its goodwill impairment test annually, using a measurement date of July 1.

The drop in crude oil prices and the resulting decline in the Company’s common share price since the merger caused the Company to test goodwill for impairment at June 30, 2015.  Goodwill was determined to be fully impaired and as a result, the balance of $4,927,508 was written off at that time.

NOTE 11 – INCOME TAXES

The following summarizes the income tax expense (benefit) and effective tax rates:

	Three Months Ended
	March 31,
	2016			2015
Consolidated net income (loss) before income taxes	$	(4,206,019	)	$	(5,977,574	)
Income tax expense (benefit)		(532,933	)		(2,294,582	)
Effective tax rate		12.7	%		38.4	%

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The differences between the U.S. federal statutory rate of 34% and the Company’s effective tax rates for the three months ended March 31, 2016 and 2015 are due primarily to state taxes and nondeductible expenses.  In addition, March 31, 2016 was impacted by the expected valuation allowance on our deferred tax asset at year-end, which affected our expected annual effective tax rate and the tax effect of nondeductible stock compensation.

The Company knows of no uncertain tax positions and has no unrecognized tax benefits for the three months ended March 31, 2016 or March 31, 2015.  When the Company believes that it is more likely than not that a net operating loss or credit may expire unused, it establishes a valuation allowance against that loss or credit.  As of March 31, 2016, the Company anticipates that it will have a net deferred tax asset at year-end 2016, for which a valuation allowance will be required.  The Company has considered the effect of the valuation allowance in the current period in determining its expected annual effective tax rate to record tax expense for the period ending March 31, 2016.  No valuation allowance was established as of March 31, 2016 or March 31, 2015.

NOTE 12 – AT MARKET SECURITY SALES

The Company entered into an At Market Issuance Sales Agreement (“Sales Agreement”) with an investment banking firm (the “Agent”) on December 19, 2014.  Under the Sales Agreement, the Company may sell both common stock and Series A Preferred Stock pursuant to the Registration Statement on Form S-3 of the Company filed on November 5, 2013 (Registration No. 333-192094), which became effective under the Securities Act on November 21, 2013.  Upon the Company’s delivery and the Agent’s acceptance of a placement notice, the Agent will use its commercially reasonable efforts, consistent with its sales and trading practices, to sell any shares subject to the placement notice.  The Company initiated the sales of securities under the Sales Agreement on February 18, 2015, and as of March 31, 2016, the Company sold the following securities for the net proceeds listed below (the Company made no sales of securities since the second quarter of 2015).

	Shares		Net Proceeds
Common Stock		1,347,458	$	1,363,160
Series A Preferred Stock		46,857		870,386
Total			$	2,233,546

NOTE 13 – CONTINGENCIES

Certain Legal Proceedings

From time to time, the Company is party to various legal proceedings arising in the ordinary course of business.  While the outcome of lawsuits cannot be predicted with certainty, the Company is not currently a party to any proceeding that it believes, if determined in a manner adverse to the Company, could have a potential material adverse effect on its financial condition, results of operations, or cash flows.

On July 9, 2014, Nabors Drilling USA, L.P. and other Nabors entities and Yuma Energy, Inc. and several of its wholly owned subsidiaries were named in a lawsuit filed in the District Court of Harris County, Texas, in the 80th Judicial District, concerning the death of an employee of Timco Services during the drilling of the Crosby 12-1 well.  The Company has tendered its defense to its liability insurance carriers who are responding.  There has been one unsuccessful mediation session.  Depositions are being scheduled.  Management believes that the Company has adequate insurance to meet this potential claim.

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In September 2015, a suit was filed against the Company and Pyramid Oil LLC styled Mark A. Ontiveros and Louise D. Ontiveros, Trustees of The Ontiveros Family Trust dated March 29, 2007 vs. Pyramid Oil, LLC, et al.  In the suit, the plaintiffs allege that the 1950 Community Oil and Gas Lease between them and Pyramid Oil LLC has expired by non-production.  The Company claims that the lease is still in effect, as there is no cessation of production time frame set out in the lease; production had temporarily ceased, but was still profitable when measured over an appropriate time period; and the Company was conducting workover operations on a well on the lease in an effort to re-establish production when served with the quit claim deed demand from the plaintiff’s attorney.  All present owners of the minerals covered by the 1950 Community Oil and Gas Lease, with the exception of the plaintiffs and one other owner, have executed amendments signifying their concurrence that the 1950 Community Oil and Gas Lease is still in force and effect.  The parties are presently in the process of document discovery.

Environmental Remediation Contingencies

As of December 31, 2015, there were no known environmental or other regulatory matters related to the Company’s operations that were reasonably expected to result in a material liability to the Company.  The Company’s operations are subject to numerous laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection.

Exploration, a subsidiary of the Company, has been named as one of 97 defendants in a matter entitled Board of Commissioners of the Southeast Louisiana Flood Protection Authority – East, Individually and As the Board Governing the Orleans Levee District, the Lake Borgne Basin Levee District, and the East Jefferson Levee District v. Tennessee Gas Pipeline Company, LLC, et al., Civil District Court for the Parish of Orleans, State of Louisiana, No. 13-6911, Division “J” - 5, now removed as Civil Action No. 13-5410, before the United States District Court, Eastern District of Louisiana.  Plaintiff filed the suit on July 24, 2013 seeking damages and injunctive relief arising out of defendants’ drilling, exploration, and production activities from the early 1900s to the present day in coastal areas east of the Mississippi River in Southeast Louisiana.

The suit alleges that defendants’ activities have caused “removal, erosion, and submergence” of coastal lands resulting in significant reduction or loss of the protection such lands afforded against hurricanes and tropical storms.  Plaintiff alleges that it now faces increased costs to maintain and operate the man-made hurricane protection system and may reach the point where that system no longer adequately protects populated areas.

Plaintiff lists hundreds of wells, pipelines, and dredging events as possible sources of the alleged land loss. Exploration is named in association with 11 wells, four rights-of-way, and one dredging permit.  The suit does not specify any deficiency or harm caused by any individual activity or facility.

Although the suit references various federal statutes as sources of standards of care, plaintiff claims that all causes of action arise under state law: negligence, strict liability, natural servitude of drain, public nuisance, private nuisance, and as third-party beneficiary under breach of contract.

The Company tendered its defense to its liability insurance carriers, who are responding.  On February 13, 2015, the federal judge adjudicating the matter granted defendants “Joint Motion to Dismiss for Failure to State a Claim Under Rule 12(b)(6)”, thereby dismissing plaintiff’s claims with prejudice in the matter.  On February 20, 2015, the Board of Orleans filed a notice of appeal to the U.S. Fifth Circuit.  On February 29, 2016, oral arguments were held regarding the appeal, but as of May 23, 2016, no ruling on the appeal has been made.  The Company will continue to contest plaintiff’s legal arguments and factual assertions.  At this point in the legal process, no evaluation of the likelihood of an unfavorable outcome or associated economic loss can be made; therefore no liability has been recorded on the Company’s books.

21

Escheat 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.

NOTE 14 – AGREEMENT AND PLAN OF MERGER AND REORGANIZATION

On February 10, 2016, the Company and privately held Davis Petroleum Acquisition Corp. (“Davis”) entered into a definitive merger agreement for an all-stock transaction. Upon completion of the transaction, the Company will reincorporate in Delaware, implement a one for ten reverse split of its common stock, and convert each share of its existing Series A Preferred Stock into 35 shares of common stock prior to giving effect for the reverse split (3.5 shares post reverse split).  Following these actions, the Company will issue additional shares of common stock in an amount sufficient to result in approximately 61.1% of the common stock being owned by the current common stockholders of Davis.  In addition, the Company will issue approximately 3.3 million shares of a new Series D preferred stock to existing Davis preferred stockholders, which  is estimated to have a conversion price of approximately $5.70 per share, after giving effect for the reverse split.  The Series D preferred stock is estimated to have a liquidation preference of approximately $19.0 million at closing, and will be paid dividends in the form of additional Series D preferred stock at a rate of 7% per annum. Upon closing, there will be an aggregate of approximately 23.7 million shares of common stock outstanding (after giving effect to the reverse stock split and conversion of Series A Preferred Stock to common stock). The transaction is expected to qualify as a tax-deferred reorganization under Section 368(a) of the Code.

The merger agreement is subject to the approval of the shareholders of both companies, as well as other customary conditions and approvals, including authorization to list the newly issued shares on the NYSE MKT. The parties anticipate completing the transaction in the third quarter of 2016.

NOTE 15 – GREATER MASTERS CREEK FIELD AREA

During the first quarter of 2016, the Company shut-in 14 Austin Chalk wells in Beauregard, Rapides and Vernon Parishes, Louisiana due to low oil and natural gas prices. Since production was not restarted from these wells, the associated leases have expired, reducing the Company’s proved reserves by approximately 1,629 MBoe, acreage by 22,021 gross (18,140 net) acres, operated proved undeveloped locations by three, and operated non-proved undeveloped locations by seven.

During the first quarter of 2016, the Company received notice from the operator of certain wells in Rapides and Vernon Parishes, Louisiana, that certain wells in which the Company has an interest were shut-in due to current economic conditions.  The operator has since sold its interest.  Since the operator and the subsequent operator have not restarted production from these wells, the associated leases have expired, reducing the Company’s proved reserves by approximately 285 MBoe from year-end 2015, acreage by 18,895 gross (3,737 net) acres, non-operated proved undeveloped locations by three, and non-operated non-proved undeveloped locations by 18.

On April 4, 2016, the Company entered into an amendment effective March 1, 2016 to an oil and gas lease in the Masters Creek Field area with a certain mineral owner for acreage that was not held by production as of March 31, 2016.  The total acreage is approximately 25,139 acres and, by virtue of the Company conducting certain location clean-up operations, the lease has now been extended until December 31, 2016.  This extension is subject to certain additional performance criteria, including the posting of a bond to cover P&A costs for wells located on this mineral owner’s property, and plugging and abandoning six of the mineral owner’s wells by December 31, 2016.  If the leased acreage expires, the Company’s proved reserves would be reduced by approximately 5,096 MBoe, the number of operated proved undeveloped locations and operated non-proved locations would be reduced by 13 and 16, respectively (See Note 17 – Subsequent Events).

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NOTE 16 – TEXAS SOUTHEASTERN GAS MARKETING COMPANY

As of January 1, 2016, the Company decided to discontinue the operations of Texas Southeastern Gas Marketing Company due to the limited volumes of natural gas that it marketed, as well as the costs associated with accounting for the entity.  Texas Southeastern Gas Marketing Company is not a significant subsidiary, and this discontinuation of operations does not represent a strategic shift in business for the Company.

NOTE 17 – SUBSEQUENT EVENTS

The Company has evaluated subsequent events through May 23, 2016, the date these financial statements were available to be issued.  The Company is not aware of any subsequent events which would require recognition or disclosure in the financial statements, except as noted below or already recognized or disclosed in the Company’s filings with the SEC.

Masters Creek Participation

In April 2016, a party to the participation agreement dated July 31, 2013 relating to Yuma’s Greater Masters Creek Area exercised its option to participate under the participation agreement for a four percent working interest.

Lease Extension

On April 4, 2016, the Company entered into an amendment effective March 1, 2016 to an oil and gas lease in the Masters Creek Field area with a certain mineral owner for acreage that was not held by production as of March 31, 2016.  The total acreage is approximately 25,139 acres and, by virtue of the Company conducting certain location clean-up operations, the lease has now been extended until December 31, 2016.  This extension is subject to certain additional performance criteria, including the posting of a bond to cover P&A costs for wells located on this mineral owner’s property, and plugging and abandoning six of the mineral owner’s wells by December 31, 2016.

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Item 2.                      Management’s Discussion and Analysis of Financial Condition and Results of Operations.

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with the accompanying unaudited consolidated financial statements and related notes thereto, included in Part I, Item 1 of this Quarterly Report on Form 10-Q and should further be read in conjunction with our Annual Report on Form 10-K/A for the year ended December 31, 2015.

Cautionary Statement Regarding Forward-Looking Statements

Certain statements contained in this Quarterly Report on Form 10-Q may contain “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). All statements other than statements of historical facts contained in this report are forward-looking statements. These forward-looking statements can generally be identified by the use of words such as “may,” “will,” could,” “should,” “project,” “intends,” “plans,” “pursue,” “target,” “continue,” “believes,” “anticipates,” “expects,” “estimates,” “predicts,” or “potential,” the negative of such terms or variations thereon, or other comparable terminology. Statements that describe our future plans, strategies, intentions, expectations, objectives, goals or prospects are also forward-looking statements. Readers should consider carefully the risks described in the “Risk Factors” section included in our Annual Report on Form 10-K/A for the fiscal year ended December 31, 2015, and the other disclosures contained herein and therein, which describe factors that could cause our actual results to differ from those anticipated in forward-looking statements, including, but not limited to, the following factors:

●   our ability to repay outstanding loans when due;

●   our limited liquidity and ability to finance our exploration, acquisition and development strategies;

●   reductions in the borrowing base under our credit facility;

●   impacts to our financial statements as a result of oil and natural gas property impairment write-downs;

●   volatility and weakness in commodity prices for oil and natural gas and the effect of prices set or influenced by action of the Organization of the Petroleum Exporting Countries (“OPEC”) and other Middle Eastern producers who are not OPEC members, Africa and Russia;

  ●   our ability to improve and implement changes to our internal controls over financial reporting;

●   our ability to successfully integrate acquired oil and natural gas businesses and operations;

●   the possibility that acquisitions and divestitures may involve unexpected costs or delays, and that acquisitions may not achieve intended benefits and will divert management’s time and energy, which could have an adverse effect on our financial position, results of operations, or cash flows;

●   risks in connection with potential acquisitions and the integration of significant acquisitions;

●   we may incur more debt; higher levels of indebtedness make us more vulnerable to economic downturns and adverse developments in our business;

●   our ability to successfully develop our inventory of undeveloped acreage in our resource plays;

●   our oil and natural gas assets are concentrated in a relatively small number of properties;

●   access to adequate gathering systems, processing facilities, transportation take-away capacity to move our production to market and marketing outlets to sell our production at market prices;

●   our ability to generate sufficient cash flow from operations, borrowings or other sources to enable us to fund our operations, satisfy our obligations and seek to develop our undeveloped acreage positions;

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●   our ability to replace our oil and natural gas reserves;

●   the presence or recoverability of estimated oil and natural gas reserves and actual future production rates and associated costs;

●   the potential for production decline rates for our wells to be greater than we expect;

●   our ability to retain key members of senior management and key technical employees;

●   environmental risks;

●   drilling and operating risks;

●   exploration and development risks;

●   the possibility that our industry may be subject to future regulatory or legislative actions (including additional taxes and changes in environmental regulations);

●   general economic conditions, whether internationally, nationally or in the regional and local market areas in which we do business, may be less favorable than we expect, including the possibility that economic conditions in the United States will worsen and that capital markets are disrupted, which could adversely affect demand for oil and natural gas and make it difficult to access capital;

●   social unrest, political instability or armed conflict in major oil and natural gas producing regions outside the United States, such as Africa, the Middle East, and armed conflict or acts of terrorism or sabotage;

●   other economic, competitive, governmental, regulatory, legislative, including federal, state and tribal regulations and laws, geopolitical and technological factors that may negatively impact our business, operations or oil and natural gas prices;

●   the insurance coverage maintained by us may not adequately cover all losses that may be sustained in connection with our business activities;

●   title to the properties in which we have an interest may be impaired by title defects;

●   management’s ability to execute our plans to meet our goals;

●   the cost and availability of goods and services, such as drilling rigs; and

●   our dependency on the skill, ability and decisions of third party operators of the oil and natural gas properties in which we have a non-operated working interest.

All forward-looking statements are expressly qualified in their entirety by the cautionary statements in this paragraph and elsewhere in this document. Other than as required under the securities laws, we do not assume a duty to update these forward-looking statements, whether as a result of new information, subsequent events or circumstances, changes in expectations or otherwise.

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Overview

Yuma Energy, Inc. is an independent Houston-based exploration and production company.  We are focused on the acquisition, development, and exploration for conventional and unconventional oil and natural gas resources, primarily in the U.S. Gulf Coast and California. We were incorporated in California on October 7, 1909. We have employed a 3-D seismic-based strategy to build a multi-year inventory of development and exploration prospects. Our current operations are focused on onshore assets located in central and southern Louisiana, where we are targeting the Austin Chalk, Tuscaloosa, Wilcox, Frio, Marg Tex and Hackberry formations. In addition, we have a non-operated position in the Bakken Shale in North Dakota and operated positions in Kern and Santa Barbara Counties in California. Our common stock is traded on the NYSE MKT under the trading symbol “YUMA.” Our Series A Preferred Stock is traded on the NYSE MKT under the trading symbol “YUMAprA.”

Recent Developments

The prices of crude oil and natural gas have declined dramatically since mid-year 2014, having recently reached multiyear lows, as a result of robust supply growth, weakening demand in emerging markets, and OPEC’s decision to continue to produce at current levels.  These market dynamics have led many to conclude that commodity prices are likely to remain lower for a prolonged period.  In response to these developments, among other things, we have reduced our spending and looked to enter into a merger with Davis Petroleum Acquisition Corp. to increase our liquidity and improve our financial position (see Item 1. Unaudited Condensed Notes to the Consolidated Financial Statements, Note 14 – Agreement and Plan of Merger and Reorganization).  In addition, we are continuing to actively explore and evaluate various strategic alternatives, including asset sales, to reduce the level of our debt and lower our future cash interest obligations.  We believe that a reduction in our debt and cash interest obligations on a per barrel basis is needed to improve our financial position and flexibility and to position us to take advantage of opportunities that may arise out of the current industry downturn.

Full Cost Ceiling Test Impairment

Oil and natural gas prices have remained low in the first quarter of 2016. If prices remain at or below the current low levels, subject to numerous factors and inherent limitations, and all other factors remain constant, we expect to incur a non-cash full cost impairment of approximately $12 million during the second quarter of 2016, which will have an adverse effect on our results of operations.

There are numerous uncertainties inherent in the estimation of proved reserves and accounting for oil and natural gas properties in future periods. Our estimated second-quarter 2016 full cost ceiling calculation has been prepared by substituting (i) $42.86 per barrel for oil, and (ii) $2.22 per MMBtu for natural gas for the expected realized prices as of June 30, 2016. The forecasted average realized price was based on the average realized price for sales of crude oil, natural gas liquids and natural gas on the first calendar day of each month for the first 11 months and an estimate for the twelfth month based on a quoted forward price. Changes to our reserves and future production due to expiring leases were made as well as changing the effective date of the evaluation from March 31, 2016 to June 30, 2016.  All other inputs and assumptions have been held constant. Accordingly, this estimate accounts for the impact of more current commodity prices on the second-quarter 2016 utilized in our full cost ceiling calculation.

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Agreement and Plan of Merger and Reorganization

On February 10, 2016, the Company and privately held Davis Petroleum Acquisition Corp. (“Davis”) entered into a definitive merger agreement for an all-stock transaction. Upon completion of the transaction, we will reincorporate in Delaware, implement a one-for-ten reverse split of our common stock, and convert each share of our existing Series A Preferred Stock into 35 shares of common stock prior to giving effect for the reverse split (3.5 shares post reverse split).  Following these actions, we will issue additional shares of common stock in an amount sufficient to result in approximately 61.1% of the common stock being owned by the current common stockholders of Davis.  In addition, we will issue approximately 3.3 million shares of a new Series D preferred stock to existing Davis preferred stockholders, which is estimated to have a conversion price of approximately $5.70 per share, after giving effect for the reverse split.  The Series D preferred stock is estimated to have an aggregate liquidation preference of approximately $19.0 million at closing, and will be paid dividends in the form of additional shares of Series D preferred stock at a rate of 7% per annum. The transaction is expected to qualify as a tax-deferred reorganization under Section 368(a) of the Internal Revenue Code of 1986, as amended (the “Code”).

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The merger agreement is subject to the approval of the shareholders of both companies, as well as other customary conditions and approvals, including authorization to list the newly issued shares on the NYSE MKT. The parties anticipate completing the transaction in the third quarter of 2016.

Davis is a Houston-based oil and gas company focused on the acquisition, exploration and development of domestic oil and gas properties.  Over 90% of the common stock of Davis is owned by entities controlled by or co-investing with Evercore Capital Partners, Red Mountain Capital Partners, and Sankaty Advisors. These major stockholders purchased the predecessor company from the family of Marvin Davis in 2006.  Davis’ company-operated properties are conventional fields located onshore in south Louisiana and the upper Texas Gulf Coast, and its non-operated properties include Eagle Ford and Woodbine properties in east Texas.

Upon closing, four of the five current board members will continue to serve on the combined company Board.  Richard K. Stoneburner will serve as Non-Executive Chairman, and Sam L. Banks will continue to serve as Director, President and Chief Executive Officer.  James W. Christmas and Frank A. Lodzinski will also continue to serve.  Three additional directors will be nominated by Davis, bringing the size of the new board to seven, and the board will meet the director independence requirements of the NYSE MKT.  All current officers of the Company will serve in their same capacity in the combined company.

Critical Accounting Policies

Critical accounting policies are defined as those that are reflective of significant judgments and uncertainties and that could potentially result in materially different results under different assumptions and conditions. For a detailed description of our accounting policies, see our Annual Report on Form 10-K/A for the year ended December 31, 2015.

Market Conditions

Prevailing prices for the crude oil, natural gas and NGLs that we produce significantly impact our revenues and cash flows.  The benchmark prices for crude oil, natural gas and NGLs were significantly lower in the first three months of 2016 compared to the same period in 2015; as a result, we experienced significant declines in our price realizations associated with those benchmarks.  Additional detail on market conditions, including our average price realizations and benchmarks for crude oil, natural gas and natural gas liquids (“NGLs”) relative to our operating segments, follows.

Liquidity Considerations

As discussed in Item 1. Unaudited Condensed Notes to the Consolidated Financial Statements, Note 2 – Liquidity Considerations and Going Concern, our credit agreement requires, among other things, compliance with certain financial ratios.  Because of the current weak commodity price environment, we have sustained losses during recent quarters.  As a result, we are not in compliance with the ratio of funded debt to EBITDA and the EBITDA to Interest Expense ratio under our senior credit facility at March 31, 2016.  We are currently in discussions with our lenders participating in our revolving credit facility, and anticipate entering into another amendment to the credit facility that will extend the waiver of these breaches until the closing of the merger.

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A breach of any of the terms and conditions of our credit agreement or a breach of our financial covenants under the senior credit facility could result in acceleration of our indebtedness, in which case the debt would become immediately due and payable.  As a result, we have classified the outstanding balance under our senior credit facility as current.

During 2015, the Company initiated several strategic alternatives to remedy its debt covenant compliance issues and provide working capital to develop the Company’s existing assets.  On February 10, 2016, the Company entered into an Agreement and Plan of Merger and Reorganization with Davis Petroleum Acquisition Corp. (“Davis”) for an all-stock transaction.  Upon completion of the transaction, which is subject to the approval of the stockholders of both companies and other conditions, Davis will become a wholly owned subsidiary of the Company.  Subject to bank approval, it is anticipated that the Company will enter into another credit agreement amendment that will take into account the contemplated merger with Davis (see Item 1. Unaudited Condensed Notes to the Consolidated Financial Statements, Note 14 – Agreement and Plan of Merger and Reorganization).  However, the Company’s management can provide no assurance that the merger with Davis and the amendment to the credit agreement will actually occur.

Sales and Other Operating Revenues

The following table presents the net quantities of oil, natural gas and natural gas liquids produced and sold by us for the three months ended March 31, 2016 and 2015, and the average sales price per unit sold.

	Three Months Ended March 31,
	2016		2015
Production volumes:
Crude oil and condensate (Bbl)		58,449		63,636
Natural gas (Mcf)		462,179		490,136
Natural gas liquids (Bbl)		16,179		16,172
Total (Boe) (1)		151,658		161,497
Average prices:
Excluding commodity derivatives:
Crude oil and condensate (per Bbl)	$	29.76	$	46.49
Natural gas (per Mcf)	$	2.05	$	2.74
Natural gas liquids (per Bbl)	$	14.99	$	16.11
Including commodity derivatives:
Crude oil and condensate (per Bbl)	$	32.64	$	94.34
Natural gas (per Mcf)	$	2.49	$	6.60
Natural gas liquids (per Bbl)	$	14.99	$	16.11

(1)   Barrels of oil equivalent have been calculated on the basis of six thousand cubic feet (Mcf) of natural gas equal to one barrel of oil equivalent (Boe).

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The following table presents our revenues for the three months ended March 31, 2016 and 2015.

	Three Months Ended March 31,
	2016			2015
Sales of natural gas and crude oil:
Crude oil and condensate	$	1,739,394		$	2,958,270
Natural gas		949,663			1,342,075
Natural gas liquids		242,529			260,566
Realized gains (losses) on commodity derivatives		1,159,114			4,936,833
Unrealized gains (losses) on commodity derivatives		(788,176	)		(3,866,266	)
Gas marketing sales		-			11,769
Total revenues	$	3,302,524		$	5,643,247

Sale of Crude Oil and Condensate

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 West Texas Intermediate (“WTI”) and adjusted to Light Louisiana Sweet (“LLS”) or Heavy Louisiana Sweet (“HLS”). Pricing for our California properties is based on an average of specified posted prices, adjusted for gravity, transportation, and for one field, a market differential.

Crude oil volumes sold were 8.2% lower for the three months ended March 31, 2016 than the crude oil volumes sold during the same period in 2015.  This decrease was a result of shut in wells in both operated and non-operated Master Creek field in addition to increased downtime in Main Pass 2 due to facility restrictions. Realized crude oil prices experienced a 36.0% decrease from the three months ended March 31, 2015 to the three months ended March 31, 2016.

Sale of Natural Gas and Natural Gas Liquids

Our natural gas is sold under multi-year contracts with pricing tied to either first of the month index or a monthly weighted average of purchaser prices received. Natural gas liquids are also sold under multi-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.

For the three months ended March 31, 2016 compared to the same period in 2015, we experienced a 5.7% decrease in natural gas volumes sold and remained neutral on natural gas liquids sold primarily due to production declines in the Bayou Hebert (La Posada) field, which were moderately offset by increased production from the Talbot 23-1 well. During the same period, realized natural gas prices decreased by 25.2% and realized natural gas liquids prices decreased by 7.0%.

Gas Marketing

Gas marketing sales are natural gas volumes purchased from certain of our operated wells and the aggregated volumes sold with a mark-up of $.03 per MMBtu. Our wholly owned subsidiary, Texas Southeastern Gas Marketing Company (“Marketing”), purchased and sold natural gas on our behalf and on behalf of our working interest partners. In early 2016, we discontinued Marketing due to a lack of volumes and the associated costs of running the company (see Item 1. Unaudited Condensed Notes to the Consolidated Financial Statements, Note 16 – Texas Southeastern Gas Marketing Company).

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Lease Operating Expenses

Our lease operating expenses (“LOE”) and LOE per Boe for the three months ended March 31, 2016 and 2015, are set forth below:

	Three Months Ended March 31,
	2016		2015
Lease operating expenses	$	1,330,747	$	2,261,528
Severance, ad valorem taxes and marketing		682,402		961,588
Total LOE	$	2,013,149	$	3,223,116
LOE per Boe	$	13.27	$	19.96
LOE per Boe without severance, ad valorem taxes and marketing	$	8.77	$	14.00

LOE includes all costs incurred to operate wells and related facilities, both operated and non-operated. In addition to direct operating costs such as labor, repairs and maintenance, equipment rentals, materials and supplies, fuel and chemicals, LOE also includes severance taxes, product marketing and transportation fees, insurance, ad valorem taxes and operating agreement allocable overhead. LOE excludes costs classified as re-engineering and workovers.

The 37.5% decrease in total LOE for the three months ended March 31, 2016 compared to the same period in 2015 was primarily due to our continued operating cost reduction initiatives implemented in our Greater Masters Creek Area, Main Pass 2 & 4, and California.  LOE per barrel of oil equivalent decreased by 33.5% for the same period generally due to enhancement projects that kept production stable and the cost reduction programs mentioned above.

Re-engineering and Workovers

Re-engineering and workover expenses include the costs to restore or enhance production in current producing zones as well as costs of significant non-recurring operations.

Workover expenses for the three months ended March 31, 2016 and 2015 totaled $0 and $494,429, respectively.  High workover expenses were incurred in early 2015 to restore facilities and salt water disposal at Main Pass 4 and artificial lift in Livingston Field.  All the 2015 re-engineered facilities upgrades and artificial lift optimization projects in our operated fields led to fewer workovers, down time, and fewer non-reoccurring operations overall. LOE per Boe, including re-engineering and workovers, for the three months ended March 31, 2016 and 2015 totaled $13.27 and $23.02, respectively, a 42.4% decrease.

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General and Administrative Expenses

Our general and administrative (“G&A”) expenses for the three months ended March 31, 2016 and 2015 are summarized as follows:

	Three Months Ended March 31,
	2016			2015
General and administrative
Stock-based compensation	$	430,852		$	2,412,743
Capitalized		(12,562	)		(674,333	)
Net stock-based compensation		418,290			1,738,410
Other		2,605,700			2,313,916
Capitalized		(448,214	)		(641,704	)
Net other		2,157,486			1,672,212
Net general and administrative	$	2,575,776		$	3,410,622

G&A expenses primarily consist of overhead expenses, employee remuneration and professional and consulting fees. We capitalize certain G&A expenditures when they satisfy the criteria for capitalization under GAAP as relating to oil and natural gas exploration activities following the full cost method of accounting.

For the three months ended March 31, 2016, net G&A expenses were $834,846 (24.5%) less than the amount for the same period in 2015. The reduction in G&A expenses was primarily attributed to a decrease in stock-based compensation and decreased salary expense due to a 25% reduction in staff from the same period in 2015.  These reductions were offset by costs associated with the Davis merger incurred during the three months ended March 31, 2016. Stock-based compensation net of amounts capitalized totaled $418,290 and $1,738,410 for the three months ended March 31, 2016 and 2015, respectively.  Salary and bonus expense totaled $1,175,135 and $1,302,469 for the three months ended March 31, 2016 and 2015, respectively.  Non-recurring professional costs related to the Davis merger totaled $479,947 and $-0- for the three months ended March 31, 2016 and 2015, respectively.

Depreciation, Depletion and Amortization

Our depreciation, depletion and amortization (“DD&A”) and DD&A per Boe for the three months ended March 31, 2016 and 2015 is summarized as follows:

	Three Months Ended March 31,
	2016		2015
DD&A	$	2,446,401	$	4,141,020
DD&A per Boe	$	16.13	$	25.64

DD&A per Boe decreased by 37.1% for the three months ended March 31, 2016 compared to the same period in 2015. Future development costs, a component of the depletion base, are down $334.2 million from March 31, 2015.  Depressed commodity prices caused more properties to no longer be economical to produce, thereby causing a reduction in projected future costs.

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Interest Expense

Our interest expense for the three and nine months ended March 31, 2016 and 2015 is summarized as follows:

	Three Months Ended March 31,
	2016			2015
Interest expense	$	526,812		$	324,829
Interest capitalized		(124,164	)		(232,822	)
Net	$	402,648		$	92,007
Bank debt	$	29,800,000		$	28,450,000

Gross interest expense increased $201,983 for the three months ended March 31, 2016 over the same period in 2015 because amortization of debt costs have been accelerated due to the possible earlier maturity date pursuant to the Ninth Amendment.  Capitalized interest decreased $108,658 for the three months ended March 31, 2016 from the same period in 2015, driven by a decrease in our unevaluated properties since 2014, which is the basis of our capitalized interest calculation.

Income Tax Expense

We recorded an income tax benefit of $532,933 on a pre-tax net loss of $4,206,019 resulting in an effective tax rate of 12.7% for the three months ended March 31, 2016. For the three months ended March 31, 2015, we recorded an income tax benefit of $2,294,582 on a pre-tax loss of $5,977,574, resulting in an effective tax rate of 38.4%.

Differences between the U.S. federal statutory rate of 34% and our effective tax rates are due primarily to state taxes and nondeductible expenses.  In addition, March 31, 2016 was impacted by the expected valuation allowance on our deferred tax asset at year-end, which affected our expected annual effective tax rate and the tax effect of nondeductible stock compensation.

Liquidity and Capital Resources

Cash Flows

The change in our cash for the three months ended March 31, 2016 and 2015 is summarized as follows:

	Three Months Ended March 31,
	2016			2015
Cash flows provided by (used in) operating activities	$	(737,351	)	$	(2,658,171	)
Cash flows used in investing activities		(1,320,388	)		(5,943,270	)
Cash flows provided by (used in) financing activities		(223,166	)		5,809,220
Net increase (decrease) in cash	$	(2,280,905	)	$	(2,792,221	)

Cash Flows from Operating Activities

Cash flows from operations for the three months ended March 31, 2016 increased by $1,920,820, or 72.3%, over the same period in 2015 primarily due to changes in working capital and decreases in lease operating and G&A expenses, somewhat offset by decreased revenues due to low commodity prices.

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Cash Flows from Investing Activities

Oil and natural gas investing activities decreased by $4,622,882 or 77.8% in the three months ended March 31, 2016 compared to the same period in 2015.  The decrease was primarily due to a reduction in capital expenditures in 2016 compared to 2015.

During the three months ended March 31, 2016, expenditures included acquisitions of acreage and additional working interest in Company-operated properties.  In addition, the Company incurred capital expenditures for recompletions, workovers and P&A activity during the quarter.  Notable projects included recompletion in the Chacahoula field and P&A of a Masters Creek well.  No drilling and completion investments were made during the quarter.

During the three months ended March 31, 2015, capital expenditures were primarily related to drilling the Talbot 23-1 well and trying to re-establish production from the Crosby 14-1 (Masters Creek field), and $577,215 was spent on completing the Blackwell 39-1 (Livingston 3D).

Cash Flows from Financing Activities

Our cash flows, both in the short-term and the long-term, are impacted by highly volatile oil and natural gas prices. Although we seek to mitigate this risk by hedging future crude oil and natural gas production through 2017 (three to five years historically), a significant deterioration in commodity prices negatively impacts revenues, earnings, and cash flows, capital spending, and potentially our liquidity.  Sales volumes and costs also impact cash flows; however, these historically have not been as volatile or as impactful as commodity prices in the short-term.

We expect to finance future acquisition, development and exploration activities through available working capital, cash flows from operating activities, advances from our credit facility, sale of non-strategic assets, increased liquidity from the possible merger with Davis, and/or the possible issuance of additional equity/debt securities.  In addition, we may slow or accelerate our development of existing reserves to more closely match our projected cash flows.

On December 30, 2015, we entered into the Waiver, Borrowing Base Redetermination and Ninth Amendment to the credit agreement which provided for a $29.8 million conforming borrowing base, which will be automatically reduced to $20.0 million on May 31, 2016 unless otherwise reduced by or to a different number by the lenders under the credit agreement.

At March 31, 2016, we had a $29.8 million conforming borrowing base with $29.8 million advanced, leaving no available borrowing capacity. The borrowing base will be reduced to $20.0 million on May 31, 2016 if another extension is not granted.

	Three Months Ended		Year Ended December 31,
	March 31, 2016		2015
Credit Facility:
Balances outstanding, beginning of year	$	29,800,000	$	22,900,000
Activity		-		6,900,000
Balances outstanding, end of period	$	29,800,000	$	29,800,000

Other than the credit facility, we had debt of $62,186 and $263,635 at March 31, 2016 and December 31, 2015, respectively, from installment loans financing oil and natural gas property insurance premiums.  We had a cash balance of $3,074,286 at March 31, 2016.

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Credit Facility

We have a credit facility with a syndicate of banks that, as of December 31, 2015, had a borrowing base of $29.8 million through May 31, 2016 and thereafter the borrowing base will automatically be reduced to $20.0 million unless otherwise reduced by or to a different amount or extended by the lenders under the credit agreement, with borrowings of $29.8 million outstanding. The credit agreement governing our credit facility provides for interest-only payments until May 20, 2017, when the credit agreement matures and any outstanding borrowings are due. The borrowing base under our credit agreement is subject to regular redeterminations in the spring and fall 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.

Our obligations under the credit agreement are guaranteed by our subsidiaries and are secured by liens on substantially all of our assets, including a mortgage lien on oil and natural gas properties having at least 85% of the proved developed reserve value and at least 50% of the proved undeveloped reserve value of the oil and natural gas properties included in the determination of the borrowing base.

Amounts borrowed under the credit agreement bear interest at either (a) the LIBOR rate plus 2.25% to 3.75% or (b) the prime rate plus 1.25% to 2.75%, depending on the amount borrowed under the credit facility. The credit facility contains a number of covenants that, among other things, restrict, subject to certain exceptions, our ability to incur additional indebtedness, create liens on assets, sell certain assets and engage in certain transactions with affiliates. Additionally, the credit agreement contains a covenant restricting the payment of dividends on preferred stock if there is less than ten percent availability on the borrowing base. See Part I, Item 1. Notes to the Consolidated Financial Statements, Note 2 – Liquidity Considerations and Going Concern, and Note 9 – Debt and Interest Expense.

We are subject to certain covenants under the terms of the credit agreement, which include the maintenance of the following financial covenants determined as of the last day of each quarter: (1) a ratio of EBITDA to Interest Expense (which includes dividends as defined in the credit agreement) of not less than 2.75 to 1.0; (2) a ratio of Funded Debt to EBITDA (as defined in the credit agreement) of not more than 4.0 to 1.0; and (3) a ratio of current assets to current liabilities of not less than 1.0 to 1.0. As of September 30, 2015, we were not in compliance with the ratio of Funded Debt to EBITDA and received a waiver for compliance from our lenders. Further, the waiver also waived any failure to comply with the above financial covenants as of December 31, 2015, at which time both the funded debt to EBITDA and the EBITDA to interest expense ratios were not in compliance.  Also, as of March 31, 2016, we are out of compliance with the ratio of Funded Debt to EBITDA and the ratio of EBITDA to Interest Expense. We are currently in discussions with our lenders participating in our revolving credit facility concerning these breaches. Because the financial covenants are determined as of the last day of each quarter, the ratios can fluctuate significantly period to period as the amounts outstanding under the credit agreement are dependent on the timing of cash flows from operations, capital expenditures, acquisitions and dispositions of oil and natural gas properties and securities offerings.

Our credit facility also places restrictions on us and certain of our subsidiaries with respect to additional indebtedness, liens, dividends and other payments to shareholders, repurchases or redemptions of our common stock, payment of cash dividends on our Series A Preferred Stock, investments, acquisitions, mergers, asset dispositions, transactions with affiliates, hedging transactions and other matters.

The credit agreement is subject to customary events of default, including in connection with a change in control. If an event of default occurs and is continuing, the lenders may elect to accelerate amounts due under the credit agreement (except in the case of a bankruptcy event of default, in which case such amounts will automatically become due and payable).

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Hedging Activities

Current Commodity Derivative Contracts

We seek to reduce our sensitivity to oil and gas price volatility and secure favorable debt financing terms by entering into commodity derivative transactions which may include fixed price swaps, price collars, puts, calls and other derivatives. We believe our hedging strategy should result in greater predictability of internally generated funds, which in turn can be dedicated to capital development projects and corporate obligations. 

Fair Market Value of Commodity Derivatives

	March 31, 2016				December 31, 2015
	Oil		Gas		Oil		Gas
Assets
Current	$	1,951,434	$	188,728	$	2,393,032	$	265,015
Noncurrent		783,653		16,597		1,049,661		20,880

Assets and liabilities are netted within each commodity on the Consolidated Balance Sheets as all contracts are with the same counterparty. For the balances without netting, refer to Item 1. Unaudited Condensed Notes to the Consolidated Financial Statements, Note 5 – Commodity Derivative Instruments.

The fair market value of our commodity derivative contracts in place at March 31, 2016 and December 31, 2015 were net assets of $2,940,412 and $3,728,588, respectively.  We sold all of our oil and natural gas options (while retaining swap contracts) in February 2015 for $4.03 million. New swaps and options contracts were concurrently initiated for the remainder of 2015 through 2017.

Please see Item 1. Unaudited Condensed Notes to the Consolidated Financial Statements, Note 5 – Commodity Derivative Instruments, for additional information on our commodity derivatives.

Hedging commodity prices for a portion of our production is a fundamental part of our corporate financial management. In implementing our hedging strategy we seek to:

● effectively manage cash flow to minimize price volatility and generate internal funds available for operations, capital development projects and additional acquisitions; and

● ensure our ability to support our exploration activities as well as administrative and debt service obligations.

Estimating the fair value of derivative instruments requires complex calculations, including the use of a discounted cash flow technique, estimates of risk and volatility, and subjective judgment in selecting an appropriate discount rate. In addition, the calculations use future market commodity prices which, although posted for trading purposes, are merely the market consensus of forecasted price trends. The results of the fair value calculation cannot be expected to represent exactly the fair value of our commodity derivatives. We currently obtain fair value positions from our counterparties and compare that value to the calculated value provided by our outside commodity derivative consultant. We believe that the practice of comparing the consultant’s value to that of our counterparties, who are more specialized and knowledgeable in preparing these complex calculations, reduces our risk of error and approximates the fair value of the contracts, as the fair value obtained from our counterparties would be the cost to us to terminate a contract at that point in time.

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Commitments and Contingencies

We had the following contractual obligations and commitments as of March 31, 2016:

	Debt (1)		Commodity Derivatives (2)		Operating Leases		Asset Retirement Obligations
2016	$	29,862,186	$	1,829,886	$	434,986	$	470,607
2017		-		1,110,526		564,326		291,384
2018		-		-		2,264		3,628,576
2019		-		-		-		2,116,829
2020		-		-		-		154,053
Thereafter		-		-		-		2,177,703
Totals	$	29,862,186	$	2,940,412	$	1,001,576	$	8,839,152

(1) Does not include future commitment, modification or covenant waiver fees, interest expense or other expenses or costs because the credit agreement is a floating rate instrument, and we cannot determine with accuracy the timing of future loans, advances, modifications, repayments or future interest rates to be charged.

(2) Represents the estimated future receipts under our oil and natural gas derivative contracts based on the future market prices as of March 31, 2016. These amounts will change as oil and natural gas commodity prices change.

Off Balance Sheet Arrangements

We do not have any off balance sheet arrangements, special purpose entities, financing partnerships or guarantees (other than our guarantee of our wholly owned subsidiary’s credit facility).

Item 3.                      Quantitative and Qualitative Disclosures about Market Risk.

We are a smaller reporting company as defined by Rule 12b-2 of the Exchange Act and are not required to provide the information under this Item.

Item 4.                      Controls and Procedures.

Evaluation of disclosure controls and procedures.

We maintain disclosure controls and procedures that are designed to ensure that information required to be disclosed in our Exchange Act reports is accurately recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.  In designing and evaluating the disclosure controls and procedures, management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives, and management necessarily applied its judgment in evaluating the cost-benefit relationship of possible controls and procedures.

As of March 31, 2016, we carried out an evaluation, under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)).  Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were not effective as of March 31, 2016. Specifically, we did not have appropriate policies and procedures in place to properly evaluate the accuracy of certain of our financial accounts as more particularly described in our annual report on form 10-K/A filed with the SEC on May 23, 2016.

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Changes in internal control over financial reporting.

There have been no changes in our internal control over financial reporting that occurred during the three month period ended March 31, 2016 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Remedial Action

We have begun our remediation plan with respect to improving and implementing our control over financial reporting, and have hired an internationally known accounting firm as our new tax consultants to assist management with is preparation of these items, and intend to hire additional accounting personnel. Additionally, we are in the process of implementing a more robust review, and increasing the supervision and monitoring of the financial reporting processes related to our material weakness.

PART II.  OTHER INFORMATION

Item 1.  Legal Proceedings.

A description of our legal proceedings is included in Item 1. Unaudited Condensed Notes to the Consolidated Financial Statements, Note 13 – Contingencies, and is incorporated herein by reference.

From time to time, we may be a plaintiff or defendant in a pending or threatened legal proceeding arising in the normal course of our business. While the outcome and impact of currently pending legal proceedings cannot be determined, our management and legal counsel believe that the resolution of these proceedings through settlement or adverse judgment will not have a material effect on our consolidated operating results, financial position or cash flows.

Item 1A.  Risk Factors.

In addition to the other information set forth in this report, you should carefully consider the factors discussed in Part I, “Item 1A – Risk Factors” in our Annual Report for the year ended December 31, 2015 on Form 10-K/A, which could materially affect our business, financial condition or future results. The risks described in our 2015 Annual Report on Form 10-K/A may not be the only risks facing our Company. There are no updates to our risk factors as disclosed in our Annual Report on Form 10-K/A for the year ended December 31, 2015. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial may materially adversely affect our business, financial condition and/or operating results.

Item 2.                       Unregistered Sales of Equity Securities and Use of Proceeds.

None.

Item 3.                       Defaults upon Senior Securities.

We breached two of the financial covenants on our senior credit facility at March 31, 2016.  We are in discussions with our lenders to obtain a waiver of the covenant violations.  See Item 1. Unaudited Condensed Notes to the Consolidated Financial Statements, Note 2 – Liquidity Considerations and Going Concern.

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Effective November 1, 2015, we have suspended the payment of dividends on the Series A Preferred Stock until such time as the Board believes the Company has adequate liquidity to restore the payment of the dividends.

Item 4.                       Mine Safety Disclosure.

Not Applicable.

Item 5.                       Other Information.

None.

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Item 6.                       Exhibits.

EXHIBIT INDEX

FOR

Form 10-Q for the quarter ended March 31, 2016.
		Incorporated by Reference
Exhibit No.	Description	Form	SEC File No.	Exhibit	Filing Date	Filed Herewith	Furnished Herewith
31.1	Certification of the Principal Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act.					X
31.2	Certification of the Principal Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act.					X
32.1	Certification of the Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act.						X
32.2	Certification of the Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act.						X
101.INS	XBRL Instance Document.					X
101.SCH	XBRL Schema Document.					X
101.CAL	XBRL Calculation Linkbase Document.					X
101.DEF	XBRL Definition Linkbase Document.					X
101.LAB	XBRL Label Linkbase Document.					X
101.PRE	XBRL Presentation Linkbase Document.					X

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

	YUMA ENERGY, INC.
	By:	/s/ Sam L. Banks
	Name:	Sam L. Banks
Date: May 23, 2016	Title:	President and Chief Executive Officer (Principal Executive Officer)
	By:	/s/ James J. Jacobs
Date: May 23, 2016	Name:	James J. Jacobs
	Title:	Chief Financial Officer (Principal Financial Officer)

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