Edgar Filing: Yuma Energy, Inc.

yuma_10q.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended September 30, 2015

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

1177 West Loop South, Suite 1825 Houston, Texas		77027
(Address of principal executive offices)		(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 þ 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 þ 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		Smaller reporting company þ
(Do not check if a smaller reporting company)

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

At November 16, 2015, 71,664,720 shares of the registrant’s common stock, no par value, were outstanding.

TABLE OF CONTENTS

			Page
PART I – FINANCIAL INFORMATION

	Item 1. Financial Statements.		3

		Consolidated Balance Sheets as of September 30, 2015 and December 31, 2014.	3

		Consolidated Statements of Operations for the Three and Nine Months ended September 30, 2015 and 2014.	5

		Consolidated Statements of Comprehensive Income for the Three and Nine Months ended September 30, 2015 and 2014.	6

		Consolidated Statements of Changes in Equity for the Nine Months ended September 30, 2015 and the year ended December 31, 2014.	7

		Consolidated Statements of Cash Flows for the Nine Months ended September 30, 2015 and 2014.	8

		Unaudited Condensed Notes to the Consolidated Financial Statements.	10

	Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations.		22

	Item 3. Quantitative and Qualitative Disclosures About Market Risk.		33

	Item 4. Controls and Procedures.		33

PART II – OTHER INFORMATION

	Item 1. Legal Proceedings.		34

	Item 1A. Risk Factors.		34

	Item 2. Unregistered Sales of Equity Securities and Use of Proceeds.		34

	Item 3. Defaults Upon Senior Securities.		34

	Item 4. Mine Safety Disclosures.		34

	Item 5. Other Information.		34

	Item 6. Exhibits.		35

	Signatures.		36

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements.

Yuma Energy, Inc.

CONSOLIDATED BALANCE SHEETS

	September 30,			December 31,
	2015			2014
	(Unaudited)
ASSETS

CURRENT ASSETS:
Cash and cash equivalents	$	5,048,104		$	11,558,322
Short-term investments		-			1,170,868
Accounts receivable, net of allowance for doubtful accounts:
Trade		5,379,899			9,739,737
Officers and employees		49,765			316,077
Other		468,181			697,991
Commodity derivative instruments		1,822,034			3,338,537
Prepayments		859,687			782,234
Deferred taxes		245,922			245,922
Other deferred charges		277,858			342,798

Total current assets		14,151,450			28,192,486

OIL AND GAS PROPERTIES (full cost method):
Not subject to amortization		24,842,415			25,707,052
Subject to amortization		196,299,194			186,530,863

		221,141,609			212,237,915
Less: accumulated depreciation, depletion and amortization		(114,741,341	)		(103,929,493	)

Net oil and gas properties		106,400,268			108,308,422

OTHER PROPERTY AND EQUIPMENT:
Land, buildings and improvements		2,795,000			2,795,000
Other property and equipment		3,471,408			3,439,688
		6,266,408			6,234,688
Less: accumulated depreciation and amortization		(2,117,783	)		(1,909,352	)

Net other property and equipment		4,148,625			4,325,336

OTHER ASSETS AND DEFERRED CHARGES:
Commodity derivative instruments		993,849			1,403,109
Deposits		264,064			264,064
Goodwill		-			5,349,988
Other noncurrent assets		210,473			262,200

Total other assets and deferred charges		1,468,386			7,279,361

TOTAL ASSETS	$	126,168,729		$	148,105,605

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

Yuma Energy, Inc.

CONSOLIDATED BALANCE SHEETS – CONTINUED

	September 30,			December 31,
	2015			2014
	(Unaudited)
LIABILITIES AND EQUITY

CURRENT LIABILITIES:
Current maturities of debt	$	30,217,400		$	282,843
Accounts payable, principally trade		8,086,414			25,004,364
Asset retirement obligations		733,917			-
Deferred taxes		471,995			471,995
Other accrued liabilities		2,195,531			1,419,565

Total current liabilities		41,705,257			27,178,767

LONG-TERM DEBT:
Bank debt		-			22,900,000

OTHER NONCURRENT LIABILITIES:
Asset retirement obligations		12,239,139			12,487,770
Deferred taxes		8,577,081			14,388,662
Restricted stock units		-			71,569
Other liabilities		43,671			22,451

Total other noncurrent liabilities		20,859,891			26,970,452

EQUITY:
Common stock, no par value
(300 million shares authorized, 71,609,741 and 69,139,869 issued)		141,707,502			137,469,772
Preferred stock		10,828,603			9,958,217
Accumulated other comprehensive income (loss)		(9,410	)		38,801
Accumulated earnings (deficit)		(88,923,114	)		(76,410,404	)

Total equity		63,603,581			71,056,386

TOTAL LIABILITIES AND EQUITY	$	126,168,729		$	148,105,605

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

Yuma Energy, Inc.

CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2015			2014			2015			2014
REVENUES:
Sales of natural gas and crude oil	$	4,649,009		$	7,821,497		$	14,756,582		$	31,837,566
Realized and unrealized net gains (losses) from
commodity derivatives		3,893,650			2,407,783			3,267,239			(1,273,322	)
Total revenues		8,542,659			10,229,280			18,023,821			30,564,244

EXPENSES:
Marketing cost of sales		234,507			408,559			434,189			1,012,577
Lease operating		2,718,919			2,838,055			9,168,260			9,761,203
Re-engineering and workovers		1,136			778,628			555,628			1,330,539
General and administrative – stock-based
compensation		338,619			521,978			2,210,950			598,818
General and administrative – other		1,873,484			2,054,961			5,389,859			6,450,446
Depreciation, depletion and amortization		3,123,812			3,865,675			11,020,278			15,604,283
Asset retirement obligation accretion expense		170,209			150,628			499,766			438,717
Goodwill impairment		-			-			5,349,988			-
Bad debt expense		49,728			55,102			787,264			85,101
Recovery of bad debts		(324,057	)		-			(342,944	)		(1,984	)
Total expenses		8,186,357			10,673,586			35,073,238			35,279,700

INCOME (LOSS) FROM OPERATIONS		356,302			(444,306	)		(17,049,417	)		(4,715,456	)

OTHER INCOME (EXPENSE):
Change in fair value of preferred stock
derivative liability – Series A and Series B		-			(11,172,928	)		-			(15,676,842	)
Interest expense		(131,114	)		(114,405	)		(337,499	)		(321,680	)
Other, net		14,055			2,970			35,521			5,634
Total other income (expense)		(117,059	)		(11,284,363	)		(301,978	)		(15,992,888	)

NET INCOME (LOSS) BEFORE INCOME TAXES		239,243			(11,728,669	)		(17,351,395	)		(20,708,344	)

Income tax benefit		(398,400	)		(576,632	)		(5,779,000	)		(1,710,632	)

NET INCOME (LOSS)		637,643			(11,152,037	)		(11,572,395	)		(18,997,712	)

PREFERRED STOCK, SERIES A AND SERIES B:
Dividends paid in cash, perpetual preferred Series A		320,626			-			940,315			-
Accretion, Series A and Series B		-			220,007			-			786,536
Dividends paid in cash, Series A and Series B		-			346,192			-			445,152
Dividends paid in kind, Series A and Series B		-			-			-			4,133,380

NET INCOME (LOSS) ATTRIBUTABLE TO
COMMON STOCKHOLDERS	$	317,017		$	(11,718,236	)	$	(12,512,710	)	$	(24,362,780	)

EARNINGS (LOSS) PER COMMON SHARE:
Basic	$	(0.00	)	$	(0.25	)	$	(0.18	)	$	(0.56	)
Diluted	$	(0.00	)	$	(0.25	)	$	(0.18	)	$	(0.56	)

WEIGHTED AVERAGE NUMBER OF COMMON
SHARES OUTSTANDING:
Basic		71,603,265			47,414,388			70,795,104			43,211,317
Diluted		73,273,007			47,414,388			70,795,104			43,211,317

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

Yuma Energy, Inc.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(Unaudited)

	Three Months Ended September 30,					Nine Months Ended September 30,
	2015		2014			2015			2014

NET INCOME (LOSS)	$	637,643	$	(11,152,037	)	$	(11,572,395	)	$	(18,997,712	)

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 loss on settled
commodity derivatives		9,971		(7,117	)		41,525			(2,867	)
Less income taxes		3,839		(2,740	)		15,987			(1,104	)

Reclassification of loss on settled
commodity derivatives, net of income taxes		6,132		(4,377	)		25,538			(1,763	)


OTHER COMPREHENSIVE INCOME (LOSS)		6,132		(4,377	)		(48,211	)		(1,763	)

COMPREHENSIVE INCOME (LOSS)	$	643,775	$	(11,156,414	)	$	(11,620,606	)	$	(18,999,475	)

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

Yuma Energy, Inc.

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

	September 30,			December 31,
	2015			2014
	(Unaudited)
COMMON STOCK, NO PAR VALUE:
Balance at beginning of period: 69,139,869 shares for 2015 and 41,074,950 shares for 2014	$	137,469,772		$	2,669,465
Sales of 1,347,458 shares of common stock		1,363,160			-
Restricted stock awards, of which 1,451,237 for 2015 and 19,440 for 2014 are vested		3,079,743			3,272,638
Buy back of 328,823 shares from vested stock awards		(300,732	)		-
Stock appreciation rights issued, not vested		95,559
Restricted stock unit awards (273,907 shares)		-			869,231
Convert preferred stock to 22,883,487 shares of common stock on September 10, 2014		-			107,552,938
Pyramid Oil Company 4,788,085 shares outstanding last day of trading September 10, 2014		-			22,504,000
Fair value of Pyramid Oil Company stock options		-			100,500
Stock awards (100,000 shares) to employees, directors and consultants of Pyramid Oil Company
vested upon the change in control and issued September 11, 2014		-			501,000
Balance at end of period: 71,609,741 shares for 2015 and 69,139,869 shares for 2014		141,707,502			137,469,772

PERPETUAL PREFERRED STOCK - 9.25% CUMULATIVE AND REDEEMABLE,
NO PAR VALUE:
Balance at beginning of period: 507,739 shares for 2015 and 0 shares for 2014		9,958,217			-
Sales of 46,857 shares for 2015 and 507,739 shares for 2014		870,386			9,958,217
Balance at end of period: 554,596 shares for 2015 and 507,739 shares for 2014		10,828,603			9,958,217

ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS):
Balance at beginning of period		38,801			38,770
Comprehensive income (loss) from commodity derivative instruments, net of income taxes		(48,211	)		31
Balance at end of period		(9,410	)		38,801

ACCUMULATED EARNINGS (DEFICIT):
Balance at beginning of period		(76,410,404	)		(50,596,088	)
Net loss		(11,572,395	)		(20,225,150	)
Series A perpetual preferred stock cash dividends		(940,315	)		(224,098	)
Preferred stock accretion (Series A and B)		-			(786,536	)
Preferred stock cash dividends (Series A and B)		-			(445,152	)
Preferred stock dividends paid in kind (Series A and B)		-			(4,133,380	)
Balance at end of period		(88,923,114	)		(76,410,404	)

TOTAL EQUITY	$	63,603,581		$	71,056,386

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

Yuma Energy, Inc.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Nine Months Ended September 30,
	2015			2014

CASH FLOWS FROM OPERATING ACTIVITIES:
Reconciliation of net loss to net cash provided by (used in) operating activities
Net loss	$	(11,572,395	)	$	(18,997,712	)
Goodwill impairment		5,349,988			-
Increase in fair value of preferred stock derivative liability		-			15,676,842
Depreciation, depletion and amortization of property and equipment		11,020,278			15,604,283
Accretion of asset retirement obligation		499,766			438,717
Stock-based compensation net of capitalized cost		2,210,950			598,818
Amortization of other assets and liabilities		209,904			140,954
Deferred tax expense (benefit)		(5,781,400	)		(1,710,632	)
Bad debt expense		787,264			85,101
Write off deferred offering costs		-			1,257,160
Amortization of benefit from commodity derivatives sold		-			(70,313	)
Unrealized (gains) losses on commodity derivatives		1,847,371			(921,026	)
Other		(342,944	)		2,058

Changes in current operating assets and liabilities:
Accounts receivable		4,411,640			1,868,318
Other current assets		(77,453	)		(274,235	)
Accounts payable		(13,938,649	)		6,165,919
Other current liabilities		1,095,356			971,048

NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES		(4,280,324	)		20,835,300

CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures on property and equipment		(11,211,634	)		(16,042,655	)
Proceeds from sale of property		30,442			307,600
Cash received from merger		-			4,550,082
Decrease in short-term investments		1,170,868			2,142,128
Decrease in noncurrent receivable from affiliate		-			95,634

NET CASH USED IN INVESTING ACTIVITIES		(10,010,324	)		(8,947,211	)

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

Yuma Energy, Inc.

CONSOLIDATED STATEMENTS OF CASH FLOWS – CONTINUED

(Unaudited)

	Nine Months Ended September 30,
	2015			2014

CASH FLOWS FROM FINANCING ACTIVITIES:
Change in borrowing on line of credit	$	6,800,000		$	(6,250,000	)
Proceeds from insurance note		813,562			901,257
Payments on insurance note		(579,005	)		(514,118	)
Line of credit financing costs		(215,141	)		(47,291	)
Net proceeds from sale of common stock		1,363,160			-
Net proceeds (preparations costs) from sale of perpetual preferred stock		870,386			(165,034	)
Cash dividends to preferred shareholders		(940,315	)		(445,152	)
Common stock purchased from employees		(300,732	)		-
Other		(31,485	)		-

NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES		7,780,430			(6,520,338	)

NET INCREASE (DECREASE) IN CASH AND
CASH EQUIVALENTS		(6,510,218	)		5,367,751

CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD		11,558,322			4,194,511

CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	5,048,104		$	9,562,262

Supplemental disclosure of cash flow information:
Interest payments (net of interest capitalized)	$	73,342		$	210,323
Interest capitalized	$	750,107		$	767,908
Supplemental disclosure of significant non-cash activity:
Change in capital expenditures financed by accounts payable	$	(2,979,301	)	$	1,858,609
Preferred dividends paid in kind	$	-		$	4,133,380

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

Yuma Energy, Inc.

UNAUDITED CONDENSED NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

NOTE A – 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 condensed consolidated financial statements should be read in conjunction with the consolidated financial statements as of and for the year ended December 31, 2014 and the notes thereto included with the Annual Report on Form 10-K of Yuma Energy, Inc. (the “Company”) filed with the Securities and Exchange Commission (“SEC”) on March 30, 2015.

NOTE B – LIQUIDITY CONSIDERATIONS

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, the Company is anticipating that it will not be in compliance with the trailing four quarter funded debt to EBITDA financial ratio covenant under its senior credit facility at September 30, 2015.

A breach of any of the terms and conditions of the credit agreement or a breach of the financial covenants under the Company’s senior credit facility could result in acceleration of the Company’s indebtedness, in which case the debt would become immediately due and payable. As a result, the Company has classified its bank debt as a current liability in its financial statements. The Company is in discussions with its lenders who are still in the process of their borrowing base review.

The Company is working on several strategic alternatives to remedy the Company's debt covenant compliance issue and provide working capital to develop the Company's existing assets. These alternatives include, but are not limited to, refinancing the Company's debt, a sale of equity, and possible joint ventures or mergers, but the Company cannot say with certainty that one or more of these alternatives will be realized.

NOTE C – ACCOUNTING STANDARDS

Not Yet Adopted

In April 2015, the Financial Accounting Standards Board (“FASB”) issued an update that requires debt issuance costs to be presented in the balance sheet as a direct reduction from the associated debt liability. This standard is effective for the Company in the first quarter of 2016 and will be applied on a retrospective basis. Early adoption is permitted, including in interim periods. The Company does not expect the adoption of this standard to have a significant impact on its consolidated results of operations, financial position or cash flows.

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 in the first quarter of 2016 and early adoption is permitted, including in interim periods. The Company does not expect the adoption of this standard to have a significant impact on its consolidated results of operations, financial position or cash flows.

In August 2014, the FASB issued an update that requires management to assess an entity’s ability to continue as a going concern by incorporating and expanding upon certain principles that are currently in United States auditing standards. This standard is effective for the Company in the first quarter of 2017 and early adoption is permitted. The Company does not expect the adoption of this standard to have a significant impact on its consolidated results of operations, financial position or cash flows.

In May 2014, the FASB issued an update that supersedes the existing revenue recognition requirements. This standard includes a five-step revenue recognition model to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for those goods or services. Among other things, the standard also eliminates industry-specific revenue guidance, requires enhanced disclosures about revenue, provides guidance for transactions that were not previously addressed comprehensively, and improves guidance for multiple-element arrangements. This standard is effective for the Company in 2018 and should be applied retrospectively to each prior reporting period presented or with the cumulative effect of initially applying the update recognized at the date of initial application. Early adoption is not permitted. The Company is evaluating the provisions of this accounting standards update and assessing the impact, if any, it may have on its consolidated results of operations, financial position or cash flows.

NOTE D – 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 September 30, 2015, 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 September 30, 2015
			Significant
	Quoted prices		other		Significant
	in active		observable		unobservable
	markets		inputs		inputs
	(Level 1)		(Level 2)		(Level 3)		Total
Assets:
Commodity derivatives – oil	$	-	$	2,502,368	$	-	$	2,502,368
Commodity derivatives – gas		-		313,515		-		313,515
Total assets	$	-	$	2,815,883	$	-	$	2,815,883

	Fair value measurements at December 31, 2014
			Significant
	Quoted prices		other		Significant
	in active		observable		unobservable
	markets		inputs		inputs
	(Level 1)		(Level 2)		(Level 3)		Total
Assets:
Commodity derivatives – oil	$	-	$	2,858,387	$	-	$	2,858,387
Commodity derivatives – gas		-		1,883,259		-		1,883,259
Total assets	$	-	$	4,741,646	$	-	$	4,741,646

Derivative instruments listed above include swaps, reverse swaps and three-way collars. For additional information on the Company’s derivative instruments and derivative liabilities, see Note E – 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 I – 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 E – 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 will remain in accumulated other comprehensive income (“AOCI”) until such time that the original hedged forecasted transaction occurs. The last of these contracts will expire in December 2015. Starting with year 2013, mark-to-market adjustments to the contracts that were in AOCI at year-end 2012 will not be made to AOCI, but instead are recognized in earnings, as are all other commodity derivative contracts going forward. As a result of discontinuing the application of hedge accounting, the Company’s earnings are potentially more volatile. See Note D – 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.

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 September 30, 2015 are provided below. Natural gas prices are New York Mercantile Exchange (“NYMEX”) Henry Hub prices, and crude oil prices are NYMEX West Texas Intermediate (“WTI”), except for the oil swaps that are based on Argus Light Louisiana Sweet (“LLS”).

	2015			2016		2017
	Settlement			Settlement		Settlement
NATURAL GAS (MMBtu):
Swaps
Volume		435,207			298,957		-
Price (NYMEX)	$	3.15	*	$	3.28		-

Reverse Swaps
Volume		50,441			-		-
Price (NYMEX)	$	4.33			-		-

3-way collars
Volume		-			-		67,361
Ceiling sold price (call) (NYMEX)		-			-	$	4.03
Floor purchased price (put) (NYMEX)		-			-	$	3.50
Floor sold price (short put) (NYMEX)		-			-	$	3.00

CRUDE OIL (Bbls):
Swaps
Volume		44,966			138,286		-
Price (LLS)	$	56.90		$	62.27		-

3-way collars
Volume		-			-		113,029
Ceiling sold price (call) (WTI)		-			-	$	77.00
Floor purchased price (put) (WTI)		-			-	$	60.00
Floor sold price (short put) (WTI)		-			-	$	45.00

* 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:

	Fair value as of
	September 30,			December 31,
	2015			2014
Asset commodity derivatives:
Current assets	$	1,909,426		$	6,413,935
Noncurrent assets		1,659,323			3,163,891
		3,568,749			9,577,826

Liability commodity derivatives:
Current liabilities		(87,392	)		(3,075,398	)
Noncurrent liabilities		(665,474	)		(1,760,782	)
		(752,866	)		(4,836,180	)
Total commodity derivative instruments	$	2,815,883		$	4,741,646

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

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2015		2014			2015			2014

Sales of natural gas and crude oil	$	4,649,009	$	7,821,497		$	14,756,582		$	31,837,566
Gains (losses) realized from sale of commodity
derivatives		-		-			4,030,000			-
Other gains (losses) realized on
commodity derivatives		432,825		(223,614	)		1,084,610			(2,264,661	)
Unrealized gains (losses) on
commodity derivatives		3,460,825		2,607,959			(1,847,371	)		921,026
Amortized gains from benefit of sold
qualified gas options		-		23,438			-			70,313
Total revenue from natural gas and crude oil	$	8,542,659	$	10,229,280		$	18,023,821		$	30,564,244

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

	Nine Months Ended						Year Ended
	September 30, 2015						December 31, 2014
	Before tax			After tax			Before tax		After tax

Balance, beginning of period	$	63,091		$	38,801		$	63,041	$	38,770
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		41,525			25,538			50		31
Balance, end of period	$	(15,301	)	$	(9,410	)	$	63,091	$	38,801

NOTE F – PREFERRED STOCK

On October 23, 2014, the Company held an initial closing of its public offering of 9.25% Series A Cumulative Redeemable Preferred Stock, no par value per share, with a liquidation preference of $25.00 per share (the “Series A Preferred Stock”). The Company issued 477,273 shares at a public offering price of $22.00 per share, for gross proceeds of $10,500,006. On October 24, 2014, the Company held an additional closing for 30,466 shares of Series A Preferred Stock at a public offering price of $22.00 per share for gross proceeds of $670,252. In total, the Company received $9,983,335 net of the underwriters’ discount and other expenses. Preferred stock is also net of $25,118 in costs through December 31, 2014 to initiate an At Market Issuance Sales Agreement (“Sales Agreement”) (see Note L – At Market Issuance Sales Agreement). The $870,386 increase to preferred stock during 2015 represents the net proceeds from the sale of 46,857 shares (37,769 shares sold under the Sales Agreement during the quarter ended March 31, 2015 and 9,088 shares sold during the quarter ended June 30, 2015). The shares of Series A Preferred Stock trade on the NYSE MKT under the symbol “YUMAprA”. The Series A Preferred Stock cannot be converted into common stock (except upon a change in control and in the event the Company chooses to not redeem the Series A Preferred Stock), but may be redeemed by the Company, at the Company’s option, on or after October 23, 2017 (or in certain circumstances, prior to such date as a result of a change in control of the Company), at a redemption price of $25.00 per share plus any accrued and unpaid dividends. The Series A Preferred Stock has no stated maturity, is not subject to any sinking fund or mandatory redemption, and will remain outstanding indefinitely unless repurchased, redeemed or converted into common stock in connection with a change in control. Holders of the Series A Preferred Stock are entitled to receive, when, as and if declared by the Board of Directors, cumulative dividends at the rate of 9.25% per annum (the dividend rate) based on the liquidation price of $25.00 per share of the Series A Preferred Stock, payable monthly in arrears on each dividend payment date, with the first payment date of December 1, 2014. The Series A Preferred Stock is presented in the permanent equity section of the financial statements. Currently, dividend payments are suspended (see Note O – Subsequent Events).

NOTE G – STOCK-BASED COMPENSATION

Restricted stock awards were granted in the form of restricted shares of common stock (“RSAs”) subject to a “Liquidity Event” and time-based vesting. The merger with Pyramid Oil Company that closed on September 10, 2014 was a “Liquidity Event” within the Company’s stock award agreements. This event removed that requirement for vesting, and now each award will vest in accordance with its time-based vesting schedule, typically in equal amounts per year over three years, subject to continued service as an employee or director of the Company.

A summary of the status of the RSAs and changes for the nine months ended September 30, 2015 is presented below.

	Number of			Weighted average
	unvested			grant-date
	RSA shares			fair value

Unvested shares as of January 1, 2015		1,952,671		$3.40 per share
Granted on March 12, 2015		183,623		$2.67 per share
Granted on August 18, 2015		2,155,538		$0.61 per share
Granted on September 30, 2015		75,000		$0.48 per share
Vested on January 25, 2015		(65,638	)	$3.14 per share
Vested on April 1, 2015		(1,272,834	)	$3.16 per share
Vested on May 1, 2015		(6,232	)	$2.39 per share
Vested on May 20, 2015		(76,744	)	$3.96 per share
Vested on July 14, 2015		(29,789	)	$3.89 per share
Forfeited		(148,940	)	$3.90 per share
Unvested shares as of September 30, 2015		2,766,655		$1.17 per share

On August 18, 2015, the Company also issued Stock Appreciation Rights (“SARs”) under the Yuma 2014 Long-Term Incentive Plan, as follows:

			Weighted
	Number of		average
	unvested		grant-date
	SARs		fair value

Unvested shares as of January 1, 2015		-
Granted on August 18, 2015		2,159,855	$0.318 per share
Vested, forfeited, or other changes		-
Unvested shares as of September 30, 2015		2,159,855	$0.318 per share

The Company intends to settle these SARs in equity, as opposed to cash.

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, 2014		105,000	$	5.17		2.91	$	-
Granted		-		-		-		-
Exercised		-		-		-		-
Forfeited		-		-		-		-
Outstanding at September 30, 2015		105,000	$	5.17		2.91	$	-

Vested at September 30, 2015		105,000	$	5.17		2.91	$	-
Exercisable at September 30, 2015		105,000	$	5.17		2.91	$	-

As of September 30, 2015, there were no unvested stock options or unrecognized stock option expenses.

The following table summarizes the information about stock options outstanding and exercisable at September 30, 2015.

		Options Outstanding						Options Exercisable
				Weighted-		Weighted				Weighted
				average		average				average
Exercise		Number of		remaining		exercise		Number of		exercise
price		shares		life (years)		price		shares		price

$	5.40		5,000		.67	$	5.40		5,000	$	5.40
$	5.16		100,000		3.02	$	5.16		100,000	$	5.16
			105,000						105,000

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 September 30, 2015, the RSUs were valued at the closing price of the common stock of the Company on that date. Compensation expense is recognized over the three-year vesting period.

A summary of the status of the unvested RSUs and changes during the nine months ended September 30, 2015 is presented below.

			Weighted
	Number of		average
	unvested		grant-date
	RSUs		fair value

Unvested shares as of January 1, 2015		95,424	$2.72 per share
Granted, forfeited, or other changes		-
Unvested shares as of September 30, 2015		95,424	$2.72 per share

NOTE H – EARNINGS PER COMMON SHARE

Earnings per common share are computed by dividing earnings available to common stockholders by the weighted average number of shares of common stock outstanding during the period. Potential common stock equivalents are determined using the “if converted” method.

Potentially dilutive securities for the computation of diluted weighted average shares outstanding are as follows:

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2015		2014		2015		2014

Series A Preferred Stock		-		11,662,749		-		13,411,550
Series B Preferred Stock		-		5,997,333		-		7,037,394
Restricted Stock Awards		1,574,318		2,443,318		1,373,824		2,227,892
Restricted Stock Units		95,424		101,104		95,424		109,086
		1,669,742		20,204,504		1,469,248		22,785,922

The Series A and Series B Preferred Stock was converted to common stock on September 10, 2014. The Company excludes preferred stock and stock-based awards whose effect would be anti-dilutive from the calculation. For the nine months ended September 30, 2015 and the three and nine months ended September 30, 2014, 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.

NOTE I – DEBT AND INTEREST EXPENSE

	September 30,			December 31,
	2015			2014
Variable rate revolving credit agreement payable to Société Générale,
OneWest Bank, FSB (now CIT Bank, N.A.), 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.	$	29,700,000		$	22,900,000

Installment loan due February 29, 2016, originating from the
financing of insurance premiums at 3.74% interest rate.		517,400			-

Installment loan due June 11, 2015, originating from the
financing of insurance premiums at 3.76% interest rate.		-			154,750

Installment loan due February 28, 2015, originating from the
financing of insurance premiums at 3.65% interest rate.		-			128,093
		30,217,400			23,182,843
Less: current portion		(30,217,400	)		(282,843	)
Total long-term debt	$	-		$	22,900,000

On January 23, 2015, the Company’s wholly owned subsidiary, Yuma Exploration and Production Company, Inc. (“Exploration”), entered into the Sixth Amendment (the “Sixth Amendment”) to the credit agreement dated August 10, 2011 with SocGen as Administrative Agent and Issuing Bank, and each of the lenders and guarantors. Pursuant to the Sixth Amendment, (i) the borrowing base under the credit agreement remained at $40.0 million until the next borrowing base redetermination date which occurred on April 7, 2015, subject to a loan covenant requiring a ten percent availability under the line in order to pay dividends on any preferred stock, (ii) the Company could issue additional series of preferred stock subject to certain restrictions, (iii) the definition of “Change of Control” was amended and restated; (iv) the Company pledged the stock of Exploration; (v) Exploration pledged its interest in its wholly owned subsidiary, Pyramid Oil LLC (“POL”), and (vi) the oil and natural gas properties held by the Company in the state of California were transferred from the Company to POL and were mortgaged under the credit agreement. In addition, Exploration’s properties in North Dakota were mortgaged. On April 7, 2015, Exploration entered into the Seventh Amendment (the “Seventh Amendment”) to the credit agreement, which reduced the Company’s borrowing base to $33.0 million, with an additional $3.0 million non-conforming borrowing base that was to expire on September 1, 2015. However, the Eighth Amendment (the “Eighth Amendment”) to the credit agreement became effective July 27, 2015 that changed the borrowing base to $33.5 million with a $1.5 million additional but non-conforming portion that expired on October 1, 2015. The banks participate in the Company’s revolving line of credit at 37.5%, 37.5% and 25% for SocGen, OneWest Bank, FSB (now CIT Bank, N.A.) and LegacyTexas Bank, respectively.

The terms of the credit agreement require Exploration to meet a specific current ratio, interest coverage ratio, and a trailing four quarter funded debt to EBITDA ratio. In addition, the credit facility requires the guarantee of The Yuma Companies, Inc., a wholly owned subsidiary of the Company. The Company anticipates that it will not be in compliance with the trailing four quarter funded debt to EBITDA ratio as of September 30, 2015, as further described in Note B – Liquidity Considerations above.

The following summarizes interest expense for the three and nine months ended September 30, 2015 and 2014.

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2015			2014			2015			2014

Credit agreement	$	314,177		$	308,486		$	835,584		$	889,111
Credit agreement commitment fees		6,301			19,133			31,460			47,209
Amortization of
credit agreement loan costs		73,146			47,715			209,903			140,955
Insurance installment loan		4,400			4,955			9,597			9,244
Other interest charges		39			616			1,062			3,069
Capitalized interest		(266,949	)		(266,500	)		(750,107	)		(767,908	)
Total interest expense	$	131,114		$	114,405		$	337,499		$	321,680

NOTE J – INCOME TAXES

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

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2015			2014			2015			2014
Consolidated net income (loss) before
income taxes	$	239,243		$	(11,728,669	)	$	(17,351,395	)	$	(20,708,344	)
Income tax expense (benefit)		(398,400	)		(576,632	)		(5,779,000	)		(1,710,632	)
Effective tax rate		167	%		5	%		33	%		8	%

The differences between the U.S. federal statutory rate of 35% and the Company’s effective tax rates for the three and nine months ended September 30, 2015 and 2014 are due primarily to the tax effects of the excess of book basis over the tax basis in the full cost pool and net operating loss carryforwards. The three and nine month periods ended September 30, 2014 also included the tax effect of nondeductible changes in fair value of preferred stock derivative liability.

The Company knows of no uncertain tax positions and has no unrecognized tax benefits for the nine months ended September 30, 2015 or September 30, 2014. 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. No valuation allowance has been established as of September 30, 2015 or September 30, 2014.

NOTE K – 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”).

As a result of the merger announcement with Pyramid on February 6, 2014, expenses of approximately $1.3 million previously incurred by the Company in connection with exploring options to obtain a public listing were written off during the first quarter of 2014.

The merger was accounted for as a business combination in accordance with ASC 805 Business Combinations (“ASC 805”). ASC 805, among other things, requires assets acquired and liabilities assumed to be measured at their acquisition date fair values. 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 recent drop in crude oil prices and the resulting decline in the Company’s common share price caused the Company to test goodwill for impairment at June 30, 2015. Goodwill was determined to be fully impaired and as a result, the balance of $5,349,988 was written off.

The following unaudited pro forma combined results of operations are provided for the nine months ended September 30, 2014 as though the merger had been completed as of January 1, 2014. These pro forma combined results of operations have been prepared by adjusting the historical results of the Company to include the historical results of Pyramid. Pyramid’s historical depletion of oil and gas property was also adjusted to reflect the change to full cost accounting. These supplemental pro forma results of operations are provided for illustrative purposes only, and do not purport to be indicative of the actual results that would have been achieved by the combined company for the period presented or that may be achieved by the combined company in the future. The pro forma results of operations do not include any cost savings or other synergies that resulted, or may result, from the merger or any estimated costs that will be incurred to integrate Pyramid. Future results may vary significantly from the results reflected in this pro forma financial information because of future events and transactions, as well as other factors.

	Nine Months Ended
	September 30, 2014

Revenues	$	34,352,101
Net loss	$	(18,700,021	)
Net loss per share:
Basic	$	(.43	)
Diluted	$	(.43	)

For the nine months ended September 30, 2014, non-recurring transaction costs of $1,442,115 related to the merger, and costs of $1,287,285 to explore other options for a public listing are included in the Consolidated Statements of Operations as general and administrative expenses; however, these non-recurring transaction costs have been excluded from the pro forma results in the above table.

For the nine months ended September 30, 2015, the Company recognized $1,644,550 from sales of natural gas and crude oil less lease operating expenses, depletion and other operating expenses of $3,003,833 related to properties acquired in the merger.

NOTE L – AT MARKET ISSUANCE SALES AGREEMENT

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 September 30, 2015, the Company has sold the following securities for the net proceeds listed below (the Company made no sales of securities during the third 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 M – COMPENSATION

On September 21, 2015, the Board of Directors of the Company terminated the Company’s Working Interest Incentive Plan (“WIIP”) which was an executive compensation plan of the Company. The WIIP provided the Company’s principal executive officer with the option to acquire from the Company a working interest in the Company’s prospects and acquisitions in an amount up to 2.5% of the Company’s working interest in such prospects and up to 5% in any production acquisition made by the Company proportionally reduced.

NOTE N – CONTINGENCIES

1. Certain Legal Proceedings

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

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

2. Environmental Remediation Contingencies

As of September 30, 2015, there were no known environmental or other regulatory matters related to the Company’s operations that were reasonably expected to result in a material liability to the Company. The Company’s operations are subject to numerous laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection.

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

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

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

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

The Company tendered its defense to its liability insurance carriers, who are responding. On February 13, 2015, the federal judge adjudicating the matter granted defendants “Joint Motion to Dismiss for Failure to State a Claim Under Rule 12(b)(6)”, thereby dismissing plaintiff’s claims with prejudice in the matter. On February 20, 2015, the Board of Orleans filed a notice of appeal to the U. S. Fifth Circuit. 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.

3. Escheat Audits

The States of Louisiana, Texas, Minnesota and Wyoming have notified the Company that they will examine the Company’s books and records to determine compliance with each of the examining state’s escheat laws. The review is being conducted by Discovery Audit Services, LLC. The Company has engaged Ryan, LLC to represent it in this matter. The exposure related to the audits is not currently determinable.

NOTE O – SUBSEQUENT EVENTS

The Company has evaluated subsequent events through November 16, 2015, the date these financial statements were available to be issued. The Company is not aware of any subsequent events which would require recognition or disclosure in the financial statements, except as noted below or already recognized or disclosed in the Company’s filings with the SEC.

1. Payment of Series A Preferred Stock Dividend

Dividends on the Series A Preferred Stock are declared monthly based on the assessment of the Company’s financial position by the Board of Directors. Due to the current depressed commodity price environment which has adversely affected the Company’s cash flows and liquidity, the dividends on the Series A Preferred Stock have been suspended until such time as the Company and the Board of Directors have deemed that the Company has sufficient liquidity to restore their payment.

2. Borrowing Base Redetermination

The borrowing base review currently underway remains in process at this time, and the Company cannot say what the new borrowing base will be and what terms the lenders will require.

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 for the year ended December 31, 2014.

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 this report on Form 10-Q and under the “Risk Factors” section included in our previously filed Annual Report on Form 10-K for the fiscal year ended December 31, 2014, 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 liquidity and ability to finance our exploration, acquisition and development strategies;

●	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”);

●	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 large 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, which is necessary to fully execute our capital program;

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

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

●	the presence or recoverability of estimated oil and natural gas reserves and the 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 the 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 expected, 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.

Overview

Yuma Energy, Inc. is a U.S.-based oil and gas company focused on the exploration for, and development of, conventional and unconventional oil and natural gas properties, primarily through the use of 3-D seismic surveys, 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 central 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.”

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 for the year ended December 31, 2014.

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 nine months of 2015 compared to 2014; 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 B – Liquidity Considerations, 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 anticipate that we will not be in compliance with the trailing four quarter funded debt to EBITDA financial ratio covenant under our senior credit facility at September 30, 2015. We are currently in discussions with our lenders participating in our revolving credit facility concerning this anticipated breach.

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.

The Company is currently working on several strategic opportunities to remedy this situation, including, but not limited to, refinancing our debt, a sale of equity, and possible joint ventures or mergers, but cannot say with certainty that one or more of these alternatives will be realized.

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 and nine months ended September 30, 2015 and 2014, and the average sales price per unit sold.

	Three Months Ended September 30,				Nine Months Ended September 30,
	2015		2014		2015		2014
Production volumes:
Crude oil and condensate (Bbl)		61,938		49,475		186,531		172,965
Natural gas (Mcf)		497,868		513,002		1,488,408		2,229,405
Natural gas liquids (Bbl)		20,899		16,457		54,838		77,389
Total (Boe) (1)		165,815		151,432		489,437		621,922

Average prices realized:
Excluding commodity derivatives (both realized and unrealized)
Crude oil and condensate (per Bbl)	$	46.10	$	98.58	$	50.52	$	101.23
Natural gas (per Mcf)	$	2.72	$	4.04	$	2.77	$	4.76
Natural gas liquids (per Bbl)	$	18.61	$	40.73	$	19.20	$	41.25
Including commodity derivatives (realized only)
Crude oil and condensate (per Bbl)	$	51.41	$	93.66	$	66.25	$	93.68
Natural gas (per Mcf)	$	2.93	$	4.13	$	4.24	$	4.36
Natural gas liquids (per Bbl)	$	18.61	$	40.73	$	19.20	$	41.25

(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).

The following table presents our revenues for the three and nine months ended September 30, 2015 and 2014.

	Three Months Ended September 30,					Nine Months Ended September 30,
	2015		2014			2015			2014
Sales of natural gas and crude oil:
Crude oil and condensate	$	2,855,530	$	4,877,227		$	9,423,519		$	17,508,388
Natural gas		1,340,877		2,066,368			4,112,065			10,585,238
Natural gas liquids		388,966		670,267			1,053,076			3,192,449
Realized gains (losses) on commodity derivatives		432,824		(200,176	)		5,114,609			(2,194,348	)
Unrealized gains (losses) on commodity derivatives		3,460,825		2,607,959			(1,847,371	)		921,026
Gas marketing sales		63,637		207,635			167,923			551,491
Total revenues	$	8,542,659	$	10,229,280		$	18,023,821		$	30,564,244

The following table presents benchmark pricing for crude oil, natural gas and natural gas liquids for the three and nine months ended September 30, 2015 and 2014.

	Three Months Ended September 30,				Nine Months Ended September 30,
	2015		2014		2015		2014
Benchmarks:
WTI crude oil (per Bbl, average price) (a)	$	46.50	$	97.25	$	50.98	$	99.62
LLS crude oil (per Bbl, average price) (b)	$	50.36	$	101.03	$	55.46	$	103.62
Mont Belvieu NGLs (per Bbl) (c)	$	15.41	$	31.08	$	16.80	$	33.43
Henry Hub natural gas (per MMBtu) (d)	$	2.77	$	4.05	$	2.80	$	4.55

(a)	NYMEX (average of the near month futures contract for the period)

(b)	Bloomberg Finance LLP: LLS St. James

(c)	Bloomberg Finance LLP: Y-grade Mix NGL of 50% ethane, 25% propane, 10% butane, 5% isobutene and 10% natural gasoline

(d)	NYMEX contract settlement date average

Notes:

Crude oil and condensate – Our crude oil and condensate price realizations may differ from the benchmark due to the quality and location of the product.

Natural Gas Liquids – The majority of our NGL volumes are sold at reference to Mont Belvieu prices.

Sale of Crude Oil and Condensate

Crude oil and condensate are sold through month-to-month evergreen contracts. The prices for our production from our Louisiana properties are 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”). For the three months ended September 30, 2015 and 2014, LLS postings averaged $3.86 and $3.78 over WTI, respectively. For the nine months ended September 30, 2015 and 2014, LLS postings average $4.48 and $4.00 over WTI, respectively. Pricing for the 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 increased by 12,463 Bbls, or 25%, for the three months ended September 30, 2015 compared to the three months ended September 30, 2014. A significant portion of this increase is due to our acquisition of Pyramid Oil on September 10, 2014. Production from our Bakersfield, California properties was 10,706 Bbls during the third quarter of 2015 compared to 2,332 Bbls during the third quarter of 2014, representing an 8,374 Bbl increase. Pyramid was part of the Company for 20 days during the third quarter of 2014. Production from our Livingston area contributed a 7,874 Bbl increase this quarter over the same quarter in 2014, as a result of two new wells, the Blackwell 39-1 and the Nettles 39-1, and the conversion of two Livingston wells from rod pump to new artificial lift systems. Additionally, production from our Main Pass 4 wells was 7,333 Bbls for this quarter, an increase of 5,012 Bbls over the 2,321 Bbls produced during the same quarter in 2014. Finally, production from the Talbot 23-1 well added 1,435 Bbls. These increases were partially offset by a decline of 1,140 Bbls for the three months ended September 30, 2015 at Raccoon Island field and 997 Bbls at La Posada field compared to the same period in 2014. The remaining difference was due to natural declines from the other producing areas not mentioned. For the three months ended September 30, 2015, we averaged $46.10 per Bbl as compared to $98.58 per Bbl for the same period in 2014, representing a 53% decrease in crude oil prices.

Crude oil volumes increased by 13,566 Bbls for the nine months ended September 30, 2015 over the same period in 2014, representing an 8% increase. This increase was primarily due to the acquisition of Pyramid Oil in September 2014, representing 30,246 Bbls, two new wells, and improved production due to the conversion to new artificial lift systems at Livingston, representing 10,607 Bbls, and improved production at Main Pass 4, representing 10,392 Bbls. These increases were partially offset by decreases of 5,513 Bbls and 15,551 Bbls at Raccoon Island and La Posada fields, respectively. Crude oil prices for the nine months ended September 30, 2015 averaged $50.52 compared to $101.23 for the same period in 2014.

Sale of Natural Gas and Natural Gas Liquids

Our natural gas is sold under multi-year contracts with pricing tied to a first of the month index. 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 September 30, 2015 and 2014, Henry Hub natural gas futures contract settlements averaged $2.77 and $4.05 respectively, a 31.6% decrease per MMBtu. For the nine months ended September 30, 2015 and 2014, Henry Hub natural gas futures contract settlements decreased 38.5% to $2.80 from $4.55.

Natural gas volumes declined approximately 3% from 513,002 Mcf for the three months ended September 30, 2014 to 497,868 for the same period in 2015. The current quarter benefited from production from the Talbot 23-1 well, which added 49,351 Mcf. This increase was offset by a 45,388 Mcf decrease for the three months ended September 30, 2015 at the La Posada field. Natural gas prices averaged $2.72 per Mcf for the three months ended September 30, 2015 compared to $4.04 for the same period in 2014, representing a 33% decrease in the price of natural gas.

Natural gas volumes declined approximately 33% from 2,229,405 Mcf for the nine months ended September 30, 2014 to 1,488,408 Mcf for the same period in 2015. This decline was primarily realized at the La Posada field, representing 785,362 Mcf of the decline, and Masters Creek field, representing 42,550 Mcf of the decline. These decreases were partially mitigated by production from the Talbot 23-1 during July 2015. Natural gas prices for the nine months ended September 30, 2015 of $2.77 per Mcf were 42% below prices for the same period in 2014.

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 $0.03 per MMBtu. Our wholly owned subsidiary, Texas Southeastern Gas Marketing Company, purchases and sells natural gas on the behalf of the Company and our working interest partners.

Lease Operating Expenses

Our lease operating expenses (“LOE”) and LOE per Boe for the three and nine months ended September 30, 2015 and 2014, are set forth below:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2015		2014		2015		2014
Lease operating expenses	$	1,816,325	$	1,772,226	$	6,254,493	$	5,347,363
Severance, ad valorum taxes and marketing		902,594		1,065,829		2,913,767		4,413,840
Total lease operating expenses	$	2,718,919	$	2,838,055	$	9,168,260	$	9,761,203

LOE per Boe	$	16.40	$	18.74	$	18.73	$	15.70
LOE per Boe without severance, ad valorum
taxes and marketing	$	10.95	$	11.70	$	12.78	$	8.60

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.

LOE was $2,718,919 for the three months ended September 30, 2015 compared to $2,838,055 for the same period in 2014, a decrease of $119,136, or 4%. This decrease in LOE includes the increase to LOE associated with the merger with Pyramid Oil on September 10, 2014. For the three months ended September 30, 2014, Pyramid LOE was $125,996, representing only 20 days of LOE, compared to the current quarter of $492,736 For the three months ended September 30, 2015, the decrease in LOE is related to operating expense reductions at the Masters Creek, La Posada, and Raccoon Island fields of $367,227, $123,148 and $263,857, respectively. These results were somewhat mitigated by the addition of the Talbot 23-1 well during the quarter, along with increases in LOE for the Livingston field properties. LOE per Boe of $16.40 for the three months ended September 30, 2015 declined $2.34 per Boe from $18.74 per Boe for the same period in 2014. Excluding Pyramid crude oil volumes and operating expenses for these same periods, LOE declined $3.84 to $14.35 per Boe, compared to $18.19 per Boe in 2014.

For the nine months ended September 30, 2015, LOE decreased by $592,943 from $9,761,203 for the same period in 2014 to $9,168,260. For the nine months ended September 30, 2015, LOE related to the Pyramid merger represented $1,641,047 compared to $125,996 for the same period in 2014, a $1,515,051 increase due to the merger with Pyramid and that only 20 days of LOE are included in the nine months ended in 2014. For the nine months ended September 30, 2015, the decrease in LOE related to operating expense reductions at the Masters Creek, La Posada, and Main Pass 4 fields of $936,432, $1,052,170 and $431,684, respectively. LOE per Boe was $18.73 compared to $15.70 for the same period in 2014. Excluding the crude oil production and operating expense of Pyramid for each period, LOE per Boe for the nine months ended September 30, 2015 was $16.48 compared to $15.55 for the same period in 2014.

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.

Re-engineering and workover expenses for the three months ended September 30, 2015 totaled $1,136 compared to $778,628 for the same period in 2014. Workover costs for the nine months ended September 30, 2015 totaled $555,628, while costs for the same period in 2014 totaled $1,330,539.

During October 2014, the Company made significant changes to its staff responsible for field operations. The Company then began a review of its field operating practices and implemented changes to improve efficiency, reduce costs and increase monthly production. This process is continuing, and has been responsible for the reductions seen in re-engineering and workovers since October 2014.

General and Administrative Expenses

Our general and administrative (“G&A”) expenses for the three and nine months ended September 30, 2015 and 2014 are summarized as follows:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2015			2014			2015			2014
General and administrative
Stock-based compensation	$	385,712		$	521,978		$	2,958,952		$	613,917
Capitalized		(47,093	)		-			(748,002	)		(15,099	)
Net stock-based compensation		338,619			521,978			2,210,950			598,818

Other		2,431,148			2,691,892			7,218,426			8,449,780
Capitalized		(557,664	)		(636,931	)		(1,828,567	)		(1,999,334	)
Net other		1,873,484			2,054,961			5,389,859			6,450,446

Net general and administrative	$	2,212,103		$	2,576,939		$	7,600,809		$	7,049,264

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.

The net change in G&A expenses for the three months ended September 30, 2015 compared to the same period in 2014 was a decrease of $364,836, or 14%. Non-recurring professional costs associated with the merger contributed to higher expenses for the three months ended September 30, 2014 compared to the same period in 2015.

G&A expenses for the nine months ended September 30, 2015 increased by $551,545, or 8%, over the same period in 2014. Higher legal and regulatory costs associated with being a public company, higher consulting fees related to hedging activities and employee status changes (engineer to consultant and contractors replacing employees on leave), and the addition of the Bakersfield district office G&A following the merger contributed to the increase over the same period in 2014. In addition, two items accounted for higher than normal G&A costs in each of the nine month periods ended September 30, 2015 and 2014. Stock-based compensation in the period ended September 30, 2015 increased substantially over the same period in 2014 as a direct result of the closing of the merger in 2014. Over several years preceding the merger, we granted restricted stock awards dependent on the Company becoming a publicly traded company. Once that condition had been satisfied, we began amortizing the fair market value of these awards over the remaining service period required for vesting. The result of this change was a $1,612,132 increase for the nine months ended September 30, 2015 compared to the same period in 2014 for net stock-based compensation costs. Additionally, during the nine months ended September 30, 2014, we had non-recurring professional costs associated with the merger and costs to explore other public listing options which totaled $2,729,447.

Depreciation, Depletion and Amortization

Our depreciation, depletion and amortization (“DD&A”) and DD&A per Boe for the three and nine months ended September 30, 2015 and 2014 is summarized as follows:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2015		2014		2015		2014
Depreciation, Depletion and Amortization	$	3,123,812	$	3,865,675	$	11,020,278	$	15,604,283

DD&A per Boe	$	18.84	$	25.53	$	22.52	$	25.09

The net Boe quantities of oil, natural gas and natural gas liquids produced and sold by us increased by 9.5% for the three months ended September 30, 2015 and decreased by 21% for the nine months ended September 30, 2015 compared to the same periods in 2014. Decreased production during the nine months ended September 30, 2015 was the primary factor for the 29% decrease for year-to-date DD&A. DD&A decreased in the current quarter over last year from the decrease in our depletable base offset by increased production. See “Sales and Other Operating Revenues” above for the oil and natural gas production.

NON-GAAP FINANCIAL MEASURES

Adjusted EBITDA

The following table reconciles reported net income to Adjusted EBITDA for the periods indicated:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2015			2014			2015			2014
Net Income (loss)	$	637,643		$	(11,152,037	)	$	(11,572,395	)	$	(18,997,712	)
Depreciation, depletion & amortization of property and equipment		3,123,812			3,865,675			11,020,278			15,604,283
Interest expense, net of interest income and amounts capitalized		130,091			112,078			318,538			316,850
Income tax benefit		(398,400	)		(576,632	)		(5,779,000	)		(1,710,632	)
Costs to obtain a public listing		-			844,482			-			2,729,447
Increase in value of preferred stock derivative liability		-			11,172,928			-			15,676,842
Stock-based compensation net of capitalized cost		338,619			521,978			2,210,950			598,818
Accretion of asset retirement obligation		170,209			150,628			499,766			438,717
Goodwill impairment		-			-			5,349,988			-
Amortization of benefit from commodity derivatives sold		-			(23,438	)		-			(70,313	)
Unrealized (gains) losses on commodity derivatives		(3,460,825	)		(2,607,959	)		1,847,371			(921,026	)
Adjusted EBITDA	$	541,149		$	2,307,703		$	3,895,496		$	13,665,274

Adjusted EBITDA is used as a supplemental financial measure by our management and by external users of our financial statements, such as investors, commercial banks and others, to assess our operating performance compared to that of other companies in our industry, without regard to financing methods, capital structure or historical costs basis. It is also used to assess our ability to incur and service debt and fund capital expenditures.

Our Adjusted EBITDA should not be considered an alternative to net income (loss), operating income (loss), cash flow provided by (used in) operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. Our Adjusted EBITDA may not be comparable to similarly titled measures of another company because all companies may not calculate Adjusted EBITDA in the same manner. Adjusted EBITDA for the three and nine months ended September 30, 2015 decreased from the same periods in 2014 by $1,766,554 (77%) and $9,769,778 (71%), respectively.

Interest Expense

Our interest expense for the three and nine months ended September 30, 2015 and 2014 is summarized as follows:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2015			2014			2015			2014
Interest expense	$	398,063		$	380,905		$	1,087,606		$	1,089,588
Interest capitalized		(266,949	)		(266,500	)		(750,107	)		(767,908	)
Net	$	131,114		$	114,405		$	337,499		$	321,680

Bank debt	$	29,700,000		$	24,965,000		$	29,700,000		$	24,965,000
Bank debt - weighted average outstanding	$	30,351,630		$	29,526,141		$	28,867,821		$	30,219,524

Funds received from the February sale of oil and natural gas options of $4.03 million and the sale of shares of common stock and Series A Preferred Stock were initially used to pay down the revolving line of credit and meet working capital requirements.

Income Tax Expense

We recorded an income tax benefit of $5,779,000 on a pre-tax net loss of $17,351,395 resulting in an effective tax rate of 33% for the nine months ended September 30, 2015. For the nine months ended September 30, 2014, we recorded an income tax benefit of $1,710,632 on a pre-tax loss of $20,708,344, resulting in an effective tax rate of 8%. A loss of $15,676,842 from the change in fair value of the Series A and Series B Preferred Stock derivative liabilities included in the pre-tax net income for the nine months ended September 30, 2014 is not recognized for tax purposes.

Additionally, differences between the U.S. federal statutory rate of 35% and our effective tax rates are due to the tax effects of the excess of book carrying value over the tax basis in the full cost pool and the net operating loss carryforwards for each period.

Liquidity and Capital Resources

Cash Flows

The change in our cash for the nine months ended September 30, 2015 and 2014 is summarized as follows:

	Nine Months Ended September 30,
	2015			2014
Cash flows provided by (used in) operating activities	$	(4,280,324	)	$	20,835,300
Cash flows used in investing activities		(10,010,324	)		(8,947,211	)
Cash flows provided by (used in) financing activities		7,780,430			(6,520,338	)
Net increase (decrease) in cash	$	(6,510,218	)	$	5,367,751

Cash Flows from Operating Activities

Cash flows from operations for the nine months ended September 30, 2015 decreased 121% over the same period in 2014 principally due to declines in commodity prices. While crude oil volumes increased 7.8% from 172,965 Bbls for the nine months ended September 30, 2014 to 186,531 Bbls for the same period in 2015, crude oil prices, LLS posting (a majority of the Company’s crude oil is sold at an LLS posting) averaged $55.46 per Bbl for the nine months ended September 30, 2015 compared to $103.62 per Bbl for the same period in 2014, representing a 46% decline. Natural gas volumes declined 33% for the nine months ended September 30, 2015 compared to the same period in 2014, primarily due to decreases in production at the La Posada field. In addition, natural gas prices at Henry Hub declined 38% to $2.80 per MMBtu for the nine months ended September 30, 2015 compared to the same period in 2014. Total revenues were $18,023,821 and $30,564,244 for the nine months ended September 30, 2015 and 2014, respectively, representing a 41% decline. In addition, there was an $8.5 million change in current operating assets and liabilities for the nine months ended September 30, 2015, driven by a $13.9 million reduction in accounts payable. The combination of reduced drilling expenditures and a reduction in revenues distributable provided for the change in accounts payable.

Cash Flows from Investing Activities

	Nine Months Ended September 30,
	2015			2014

Acquisition of acreage and new properties	$	2,813,180		$	3,987,163
Drilling and completion		3,797,839			14,481,398
Recompletions, capital workovers and plugging and abandoning (“P&A”)		1,589,594			(630,021	)
Total oil and natural gas investing activities		8,200,613			17,838,540
Corporate office property and equipment purchases		31,720			62,724
Total cash used for capitalized expenditures on property and equipment		8,232,333			17,901,264
Proceeds from sale of property		(30,442	)		(307,600	)
Cash received in merger		-			(4,550,082	)
Decrease in short-term investments		(1,170,868	)		(2,142,128	)
Decrease in noncurrent receivable from affiliate		-			(95,634	)
Cash flows used in investing activities, including accounts payable		7,031,023			10,805,820
Change in capital expenditures financed by accounts payable		2,979,301			(1,858,609	)
Cash flows used in investing activities	$	10,010,324		$	8,947,211

During the nine months ended September 30, 2015, the Amazon 3-D Project accounted for $3,964,620 of our total oil and natural gas investing activities. Of that, $3,682,212 was spent on the drilling of the Talbot 23-1 well and related Anaconda prospect costs. At the Greater Masters Creek Field, $1,672,681 was spent primarily on the workover of the Bullock A-1 and the completion of the Crosby 14-1 and its salt water disposal well. At the Livingston 3-D Project, $1,377,842 was spent, with most of the expenditures going to the completion of the Blackwell 39-1 well and related Musial prospect costs, along with capital workovers to add electric submersible pumps to two wells.

During the nine months ended September 30, 2014, the Greater Masters Creek Field accounted for $14,886,638 of our total oil and natural gas investing activities. Of that, $1,837,333 was spent primarily on lease extensions and geological and geophysical activities. At the Livingston prospect, $1,400,028 was incurred to drill and complete the Nettles 39-1, of which $269,260 was spent on leasing. The remaining $13,049,305 represents drilling costs. A net credit of $669,670 for insurance recovery on the Grief Bros. No. 1 created a credit balance for recompletions, capital workovers and P&A for the period.

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, and 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 July 27, 2015, we entered into the Eighth Amendment to the credit agreement which provided for a $33.5 million conforming borrowing base and a $1.5 million non-conforming borrowing base which expired on October 1, 2015. Therefore, as of October 1, 2015, the total borrowing base is $33.5 million and the available borrowing capacity was $3.8 million. The October borrowing base review is ongoing at this time.

	Nine Months Ended		Year Ended
	September 30, 2015		December 31, 2014
Credit Facility:
Balances outstanding, beginning of year	$	22,900,000	$	31,215,000
Activity		6,800,000		(8,315,000	)
Balances outstanding, end of period	$	29,700,000	$	22,900,000

Other than the credit facility, we had debt of $517,400 and $282,843 at September 30, 2015 and December 31, 2014, respectively, from installment loans financing oil and natural gas property insurance premiums. We had a cash balance of $5.0 million at September 30, 2015.

We anticipate a breach of one of the financial covenants on our senior credit facility at September 30, 2015. We are working with our lenders who are currently in the process of their borrowing base review. See Item 1. Unaudited Condensed Notes to the Consolidated Financial Statements, Note B – Liquidity Considerations.

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

	September 30, 2015				December 31, 2014
	Oil		Gas		Oil		Gas
Assets
Current	$	1,531,222	$	290,812	$	1,851,542	$	1,486,995
Noncurrent		971,146		22,703		1,006,845		396,264

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 E – Commodity Derivative Instruments.

The fair market value of our commodity derivative contracts in place at September 30, 2015 and December 31, 2014 were net assets of $2,815,883 and $4,741,646, respectively. We sold all of our oil and natural gas options (while retaining swap contracts) in February 2015 for $4.03 million, accounting for the decrease in market value from December 31, 2014. New swaps and options contracts were concurrently initiated for the remainder of 2015 through 2017.

We expect to reclassify losses on commodity derivatives of $9,410 net after taxes into earnings from accumulated other comprehensive income during the final quarter of 2015; however, actual cash settlement gains and losses recognized may differ materially. Other comprehensive income for commodity derivatives will be gone at the end of 2015.

Please see Item 1. Unaudited Condensed Notes to the Consolidated Financial Statements, Note E – 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.

Commitments and Contingencies

We had the following contractual obligations and commitments as of September 30, 2015:

			Commodity Derivatives Assets (2)
					Operating		Asset Retirement
	Debt (1)				Leases		Obligations
2015	$	517,400	$	529,252	$	143,070	$	-
2016		29,700,000		1,577,436		576,274		733,917
2017		-		709,195		561,106		2,850,972
2018		-		-		2,264		798,066
2019		-		-		-		341,926
Thereafter		-		-		-		8,248,175
Totals	$	30,217,400	$	2,815,883	$	1,282,714	$	12,973,056

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

(2)	Represents the estimated future payments under our oil and natural gas derivative contracts based on the future market prices as of September 30, 2015. 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.

Our Chief Executive Officer and our Chief Financial Officer have concluded, based on their evaluation as of the end of the period covered by this Form 10-Q, that our disclosure controls and procedures, as defined under Rules 13a-15(e) and 15d-15(e) of the Exchange Act, are effective to ensure that information we are required to disclose in the reports we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that our disclosure controls and procedures are effective to ensure that information we are required to disclose in such reports is accumulated and communicated to management, including our Chief Executive Officer and our Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.

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 September 30, 2015 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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 N – 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.

The following risk factor updates the Risk Factors included in our Annual Report on Form 10-K for the year ended December 31, 2014. Except as set forth below and in each of our quarterly reports on Form 10-Q for the periods ended March 31, 2015 and June 30, 2015, there have been no material changes to the risks described in our Annual Report for the year ended December 31, 2014.

Our short-term liquidity is constrained, and could severely impact our cash flow and our development of our properties.

Currently, our principal sources of liquidity are cash flow from our operations and borrowing under our credit facility. During the first nine months of 2015, we have borrowed $6.8 million under our credit facility to fund a portion of our capital expenditures. On October 1, 2015, our non-conforming borrowing base, which was $1.5 million, expired pursuant to the terms of the Eighth Amendment to our credit agreement. Therefore, as of October 1, 2015, our total borrowing base was $33.5 million with approximately $3.8 million of remaining availability. We are currently undergoing our October 2015 borrowing base redetermination that could reduce our existing credit facility borrowing base. This reduction could result in our liquidity being severely limited and our expenditures being limited to our current cash flow.

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

None.

Item 3. Defaults upon Senior Securities.

We anticipate that we will breach one of the financial covenants on our senior credit facility at September 30, 2015. We are working with our lenders who are currently in the process of their borrowing base review. See Item 1. Unaudited Condensed Notes to the Consolidated Financial Statements, Note B – Liquidity Considerations.

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.

Item 6. Exhibits.

EXHIBIT INDEX

FOR

Form 10-Q for the quarter ended September 30, 2015.

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.

31.2

Certification of the Principal Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act.

32.1

Certification of the Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act.

32.2

Certification of the Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act.

101.INS

XBRL Instance Document.

101.SCH

XBRL Schema Document.

101.CAL

XBRL Calculation Linkbase Document.

101.DEF

XBRL Definition Linkbase Document.

101.LAB

XBRL Label Linkbase Document.

101.PRE

XBRL Presentation Linkbase Document.

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.

Date: November 16, 2015	By:	/s/ Sam L. Banks
		Sam L. Banks
		President and Chief Executive Officer
		(Principal Executive Officer)


Date: November 16, 2015	By:	/s/ Kirk F. Sprunger
		Kirk F. Sprunger
		Chief Financial Officer (Principal Financial Officer)