Edgar Filing: Yuma Energy, Inc.

yuma_10q.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended June 30, 2015

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

For the transition period from to

Commission File Number: 001-32989

Yuma Energy, Inc.

(Exact name of registrant as specified in its charter)

CALIFORNIA

(State or other jurisdiction of incorporation)

94-0787340

(IRS Employer Identification No.)

1177 West Loop South, Suite 1825

Houston, Texas

(Address of principal executive offices)

77027

(Zip Code)

(713) 968-7000

(Registrant’s telephone number, including area code)

N/A

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

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

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

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 [ ] Accelerated filer [ ]

Non-accelerated filer [ ] (Do not check if a smaller reporting company) Smaller reporting company [X]

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

At August 14, 2015, 71,579,952 shares of the registrant’s common stock, no par value, were outstanding.

TABLE OF CONTENTS

	PART I – FINANCIAL INFORMATION

Item 1.	Financial Statements.

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

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

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

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

		Consolidated Statements of Cash Flows for the Six Months ended June 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.		23

Item 3.	Quantitative and Qualitative Disclosures About Market Risk.		37

Item 4.	Controls and Procedures.		37

	PART II – OTHER INFORMATION

Item 1.	Legal Proceedings.		37

Item 1A.	Risk Factors.		38

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds.		38

Item 3.	Defaults Upon Senior Securities.		38

Item 4.	Mine Safety Disclosures.		38

Item 5.	Other Information.		38

Item 6.	Exhibits.		39

	Signatures.		40

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements.

Yuma Energy, Inc.

CONSOLIDATED BALANCE SHEETS

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

CURRENT ASSETS:
Cash and cash equivalents	$	8,283,003		$	11,558,322
Short-term investments		-			1,170,868
Accounts receivable, net of allowance for doubtful accounts:
Trade		6,325,634			9,739,737
Officers and employees		47,565			316,077
Other		234,745			697,991
Commodity derivative instruments		110,027			3,338,537
Prepayments		843,838			782,234
Deferred taxes		245,922			245,922
Other deferred charges		281,409			342,798

Total current assets		16,372,143			28,192,486

OIL AND GAS PROPERTIES (full cost method):
Not subject to amortization		24,202,942			25,707,052
Subject to amortization		195,212,666			186,530,863

		219,415,608			212,237,915
Less: accumulated depreciation, depletion and amortization		(111,684,897	)		(103,929,493	)

Net oil and gas properties		107,730,711			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		(2,050,414	)		(1,909,352	)

Net other property and equipment		4,215,994			4,325,336

OTHER ASSETS AND DEFERRED CHARGES:
Commodity derivative instruments		6,579			1,403,109
Deposits		264,064			264,064
Goodwill		-			5,349,988
Other noncurrent assets		269,634			262,200

Total other assets and deferred charges		540,277			7,279,361

TOTAL ASSETS	$	128,859,125		$	148,105,605

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

Yuma Energy, Inc.

CONSOLIDATED BALANCE SHEETS – CONTINUED

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

CURRENT LIABILITIES:
Current maturities of debt	$	431,546		$	282,843
Accounts payable, principally trade		10,645,356			25,004,364
Commodity derivative instruments		720,299			-
Asset retirement obligations		673,336			-
Deferred taxes		471,995			471,995
Other accrued liabilities		2,144,437			1,419,565

Total current liabilities		15,086,969			27,178,767

LONG-TERM DEBT:
Bank debt		29,900,000			22,900,000

OTHER NONCURRENT LIABILITIES:
Asset retirement obligations		12,077,632			12,487,770
Commodity derivative instruments		51,219			-
Deferred taxes		8,971,643			14,388,662
Restricted stock units		-			71,569
Other liabilities		58,223			22,451

Total other noncurrent liabilities		21,158,717			26,970,452

EQUITY:
Common stock, no par value
(300 million shares authorized, 71,579,952 and 69,139,869 issued)		141,140,509			137,469,772
Preferred stock		10,828,603			9,958,217
Accumulated other comprehensive income (loss)		(15,542	)		38,801
Accumulated earnings (deficit)		(89,240,131	)		(76,410,404	)

Total equity		62,713,439			71,056,386

TOTAL LIABILITIES AND EQUITY	$	128,859,125		$	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 June 30,						Six Months Ended June 30,
	2015			2014			2015			2014
REVENUES:
Sales of natural gas and crude oil	$	5,534,894		$	11,709,051		$	10,107,573		$	24,016,069
Realized and unrealized net losses from
commodity derivatives		(1,696,979	)		(1,729,526	)		(626,411	)		(3,681,105	)
Other revenue		316,746			302,143			586,764			543,636
Total revenues		4,154,661			10,281,668			10,067,926			20,878,600

EXPENSES:
Marketing cost of sales		97,994			282,701			199,682			604,018
Lease operating		3,226,225			3,264,643			6,449,341			6,923,148
Re-engineering and workovers		60,063			550,401			554,492			551,911
General and administrative – stock-based
compensation		133,921			28,926			1,872,331			76,840
General and administrative – other		2,160,909			1,789,050			4,103,139			4,939,121
Depreciation, depletion and amortization		3,755,446			6,012,525			7,896,466			11,738,608
Asset retirement obligation accretion expense		166,773			145,945			329,557			288,089
Goodwill impairment		5,349,988			-			5,349,988			-
Bad debt expense		726,225			2,871			737,536			29,999
Recovery of bad debts		(18,887	)		(1,984	)		(18,887	)		(1,984	)
Total expenses		15,658,657			12,075,078			27,473,645			25,149,750

INCOME (LOSS) FROM OPERATIONS		(11,503,996	)		(1,793,410	)		(17,405,719	)		(4,271,150	)

OTHER INCOME (EXPENSE):
Change in fair value of preferred stock
derivative liability – Series A and Series B		-			(5,975,944	)		-			(4,503,914	)
Interest expense		(114,378	)		(67,856	)		(206,385	)		(207,275	)
Other, net		5,310			1,513			21,466			2,664
Total other income (expense)		(109,068	)		(6,042,287	)		(184,919	)		(4,708,525	)

NET INCOME (LOSS) BEFORE INCOME TAXES		(11,613,064	)		(7,835,697	)		(17,590,638	)		(8,979,675	)

Income tax expense (benefit)		(3,421,600	)		(285,000	)		(5,380,600	)		(1,134,000	)

NET INCOME (LOSS)		(8,191,464	)		(7,550,697	)		(12,210,038	)		(7,845,675	)

PREFERRED STOCK, SERIES A AND SERIES B:
Dividends paid in cash, perpetual preferred Series A		318,874			-			619,689			-
Accretion, Series A and Series B		-			284,580			-			566,529
Dividends paid in cash, Series A and Series B		-			98,960			-			98,960
Dividends paid in kind, Series A and Series B		-			4,133,380			-			4,133,380

NET INCOME (LOSS) ATTRIBUTABLE TO
COMMON STOCKHOLDERS	$	(8,510,338	)	$	(12,067,617	)	$	(12,829,727	)	$	(12,644,544	)

EARNINGS (LOSS) PER COMMON SHARE:
Basic	$	(0.12	)	$	(0.29	)	$	(0.18	)	$	(0.31	)
Diluted	$	(0.12	)	$	(0.29	)	$	(0.18	)	$	(0.31	)

WEIGHTED AVERAGE NUMBER OF COMMON
SHARES OUTSTANDING:
Basic		71,502,546			41,074,953			70,384,326			41,074,953
Diluted		71,502,546			41,074,953			70,384,326			41,074,953

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

Yuma Energy, Inc.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(Unaudited)

	Three Months Ended June 30,						Six Months Ended June 30,
	2015			2014			2015			2014

NET LOSS	$	(8,191,464	)	$	(7,550,697	)	$	(12,210,038	)	$	(7,845,675	)

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		8,118			63,416			31,554			4,250
Less income taxes		3,125			24,415			12,148			1,636

Reclassification of loss on settled
commodity derivatives, net of income taxes		4,993			39,001			19,406			2,614


OTHER COMPREHENSIVE INCOME (LOSS)		4,993			39,001			(54,343	)		2,614

COMPREHENSIVE LOSS	$	(8,186,471	)	$	(7,511,696	)	$	(12,264,381	)	$	(7,843,061	)

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

Yuma Energy, Inc.

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

	June 30,
	2015			December 31,
	(Unaudited)			2014
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 1,421,448 for 2015 and 19,440 for 2014 are vested		2,608,309			3,272,638
Buy back of 328,823 shares from vested stock awards		(300,732	)		-
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: 71,579,952 shares for 2015 and 69,139,869 shares for 2014		141,140,509			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		(54,343	)		31
Balance at end of period		(15,542	)		38,801

ACCUMULATED EARNINGS (DEFICIT):
Balance at beginning of period		(76,410,404	)		(50,596,088	)
Net loss		(12,210,038	)		(20,225,150	)
Series A perpetual preferred stock cash dividends		(619,689	)		(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		(89,240,131	)		(76,410,404	)

TOTAL EQUITY	$	62,713,439		$	71,056,386

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

Yuma Energy, Inc.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Six Months Ended June 30,
	2015			2014

CASH FLOWS FROM OPERATING ACTIVITIES:
Reconciliation of net loss to net cash provided by (used in) operating activities
Net loss	$	(12,210,038	)	$	(7,845,675	)
Goodwill impairment		5,349,988			-
Increase in fair value of preferred stock derivative liability		-			4,503,914
Depreciation, depletion and amortization of property and equipment		7,896,466			11,738,608
Accretion of asset retirement obligation		329,557			288,089
Stock-based compensation net of capitalized cost		1,872,331			76,840
Amortization of other assets and liabilities		136,758			93,240
Deferred tax expense (benefit)		(5,383,000	)		(1,134,000	)
Bad debt expense		737,536			29,999
Write off deferred offering costs		-			1,257,160
Commodity derivatives sold previously recognized in other
comprehensive income		(119,917	)		-
Amortization of benefit from commodity derivatives sold		-			(46,875	)
Net commodity derivatives mark-to-market loss		5,428,113			1,686,933
Other		(18,887	)		(4,668	)

Changes in current operating assets and liabilities:
Accounts receivable		3,427,212			(663,557	)
Other current assets		(61,604	)		(116,261	)
Accounts payable		(11,663,279	)		4,439,867
Other current liabilities		877,533			747,969

NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES		(3,401,231	)		15,051,583

CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures on property and equipment		(9,301,034	)		(7,162,819	)
Proceeds from sale of property		30,442			307,600
Decrease in short-term investments		1,170,868			-
Decrease in noncurrent receivable from affiliate		-			95,634

NET CASH USED IN INVESTING ACTIVITIES		(8,099,724	)		(6,759,585	)

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

Yuma Energy, Inc.

CONSOLIDATED STATEMENTS OF CASH FLOWS – CONTINUED

(Unaudited)

	Six Months Ended June 30,
	2015			2014

CASH FLOWS FROM FINANCING ACTIVITIES:
Change in borrowing on line of credit	$	7,000,000		$	(6,440,000	)
Proceeds from insurance note		536,762			624,457
Payments on insurance note		(388,059	)		(294,830	)
Line of credit financing costs		(210,194	)		(45,249	)
Net proceeds from sale of common stock		1,363,160			-
Net proceeds from sale of perpetual preferred stock		870,386			-
Cash dividends to preferred shareholders		(619,689	)		(98,960	)
Common stock purchased from employees		(300,732	)		-
Other		(25,998	)		-

NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES		8,225,636			(6,254,582	)

NET INCREASE (DECREASE) IN CASH AND
CASH EQUIVALENTS		(3,275,319	)		2,037,416

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

CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	8,283,003		$	6,231,927

Supplemental disclosure of cash flow information:
Interest payments (net of interest capitalized)	$	20,479		$	125,023
Interest capitalized	$	483,158		$	501,408
Supplemental disclosure of significant non-cash activity:
Change in capital expenditures financed by accounts payable	$	(2,695,729	)	$	2,580,503
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 – 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.

Recently Adopted

In April 2014, the FASB issued an amendment to accounting standards that changes the criteria for reporting discontinued operations while enhancing related disclosures. Under the amendment, only disposals representing a strategic shift in operations should be presented as discontinued operations. Expanded disclosures about the assets, liabilities, income and expenses of discontinued operations are required. In addition, disclosure of the pretax income attributable to a disposal of a significant part of an organization that does not qualify for discontinued operations reporting will be made in order to provide users with information about the ongoing trends in an organization’s results from continuing operations. The amendments were effective for the Company in the first quarter of 2015 and apply to dispositions or classifications as held for sale thereafter. Adoption of this standard did not impact the Company’s consolidated results of operations, financial position or cash flows.

NOTE C – 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 June 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 June 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	$	-	$	116,606	$	-	$	116,606
Total assets		-		116,606		-		116,606


Liabilities:
Commodity derivatives – oil	$	-	$	771,518	$	-	$	771,518
Total liabilities	$	-	$	771,518	$	-	$	771,518

	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 D – 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 H – 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 D – 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 C – 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”) which is rated “A” by Standard and Poor’s, “A2” by Moody’s, “A” by Fitch and “AA(low)” 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 June 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		984,877			298,957		-
Price (NYMEX)	$	3.14	*	$	3.28		-

Reverse Swaps
Volume		114,066			-		-
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		94,154			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
	June 30,			December 31,
	2015			2014
Asset commodity derivatives:
Current assets	$	300,392		$	6,413,935
Noncurrent assets		794,833			3,163,891
		1,095,225			9,577,826

Liability commodity derivatives:
Current liabilities		(910,664	)		(3,075,398	)
Noncurrent liabilities		(839,473	)		(1,760,782	)
		(1,750,137	)		(4,836,180	)
Total commodity derivative instruments	$	(654,912	)	$	4,741,646

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

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2015			2014			2015			2014

Sales of natural gas and crude oil	$	5,534,894		$	11,709,051		$	10,107,573		$	24,016,069
Gain realized from sale of commodity
derivatives		-			-			4,030,000			-
Other gains (losses) realized on
commodity derivatives		(255,049	)		(1,044,416	)		651,785			(2,041,047	)
Unrealized losses on
commodity derivatives		(1,441,930	)		(708,547	)		(5,308,196	)		(1,686,933	)
Amortized gains from benefit of sold
qualified gas options		-			23,437			-			46,875
Total revenue from natural gas and crude oil	$	3,837,915		$	9,979,525		$	9,481,162		$	20,334,964

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

	Six Months Ended						Year Ended
	June 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		31,554			19,406			50		31
Balance, end of period	$	(25,272	)	$	(15,542	)	$	63,091	$	38,801

NOTE E – 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 K – 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.

NOTE F – 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 six months ended June 30, 2015 is presented below.

	Number of			Weighted
	unvested			average
	RSA			grant-date
	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
Vested		(1,421,448	)	$3.20 per share
Forfeited		(148,940	)	$3.90 per share
Unvested shares as of June 30, 2015		565,906		$3.53 per share

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		3.66	$	-
Granted		-		-		-		-
Exercised		-		-		-		-
Forfeited		-		-		-		-
Outstanding at June 30, 2015		105,000	$	5.17		3.16	$	-

Vested at June 30, 2015		105,000	$	5.17		3.16	$	-
Exercisable at June 30, 2015		105,000	$	5.17		3.16	$	-

As of June 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 June 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		.92	$	5.40		5,000	$	5.40
$	5.16		100,000		3.27	$	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 June 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 six months ended June 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 June 30, 2015		95,424	$2.72 per share

NOTE G – 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				Six Months Ended
	June 30,				June 30,
	2015		2014		2015		2014

Series A Preferred Stock		-		14,304,590		-		12,578,618
Series B Preferred Stock		-		7,567,316		-		7,156,839
Restricted Stock Awards		640,499		2,282,615		1,271,916		1,456,360
Restricted Stock Units		95,424		112,843		95,424		123,446
		735,923		24,267,364		1,367,340		21,315,263

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 three and six months ended June 30, 2015 and 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 H – DEBT AND INTEREST EXPENSE

	June 30,			December 31,
	2015			2014
Variable rate revolving credit agreement payable to Société Générale,
OneWest Bank, FSB, 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.	$	29,900,000		$	22,900,000

Installment loan due February 29, 2016, originating from the
financing of insurance premiums at 3.74% interest rate.		431,546			-

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
		30,331,546			23,182,843
Less: current portion		(431,546	)		(282,843	)
Total long-term debt	$	29,900,000		$	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 expires October 1, 2015. See Note M – Subsequent Events for a discussion of the Eighth Amendment.

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

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2015			2014			2015			2014

Credit agreement	$	280,113		$	262,714		$	521,407		$	580,625
Credit agreement commitment fees		9,331			18,482			25,159			28,076
Amortization of
credit agreement loan costs		71,613			47,167			136,757			93,240
Insurance installment loan		3,471			3,643			5,197			4,289
Other interest charges		186			357			1,023			2,453
Capitalized interest		(250,336	)		(264,507	)		(483,158	)		(501,408	)
Total interest expense	$	114,378		$	67,856		$	206,385		$	207,275

The terms of the credit agreement require Exploration to meet a specific current ratio, interest coverage ratio, and a 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. Exploration was in compliance with the loan covenants as of June 30, 2015.

NOTE I – INCOME TAXES

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

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2015			2014			2015			2014
Consolidated net income (loss) before
income taxes	$	(11,613,064	)	$	(7,835,697	)	$	(17,590,638	)	$	(8,979,675	)
Income tax expense (benefit)		(3,421,600	)		(285,000	)		(5,380,600	)		(1,134,000	)
Effective tax rate		29	%		4	%		31	%		13	%

The differences between the U.S. federal statutory rate of 35% and the Company’s effective tax rates for the three and six months ended June 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 six month periods ended June 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 six months ended June 30, 2015 or June 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 June 30, 2015 or June 30, 2014.

NOTE J – 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 six months ended June 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.

	Six Months Ended
	June 30, 2014

Revenues	$	22,944,956
Net loss	$	(1,687,277	)
Net loss per share:
Basic	$	(.04	)
Diluted	$	(.04	)

For the six months ended June 30, 2014, non-recurring transaction costs of $585,275 related to the merger, and costs of $1,299,643 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 six months ended June 30, 2015, the Company recognized $1,151,794 from sales of natural gas and crude oil less lease operating expenses, depletion and other operating expenses of $2,079,400 related to properties acquired in the merger.

NOTE K – 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 June 30, 2015, the Company has sold the following securities for the net proceeds listed below.

	Shares		Net Proceeds

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

NOTE L – 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 mediation session, and discussions are continuing. Management believes that the Company has adequate insurance to meet this potential claim.

2. Environmental Remediation Contingencies

As of June 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 Stated District Court, Eastern District of Louisiana. Plaintiff filed the suit on July 24, 2013 seeking damages and injunctive relief arising out of defendants’ drilling, exploration, and production activities from the early 1900s to the present day in coastal areas east of the Mississippi River in Southeast Louisiana.

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

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

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

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.

NOTE M – SUBSEQUENT EVENTS

The Company has evaluated subsequent events through August 14, 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.	Eighth Amendment to Credit Agreement

On July 27, 2015, Exploration entered into the Eighth Amendment (the “Eighth Amendment”) to that certain credit agreement dated August 10, 2011 with SocGen as Administrative Agent and Issuing Bank, and each of the lenders and guarantors.

Pursuant to the Eighth Amendment, the borrowing base under the credit agreement was adjusted to a $33.5 million conforming borrowing base and a $1.5 million additional non-conforming borrowing base, for a total of $35.0 million until the next borrowing base redetermination date scheduled for October 1, 2015.

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 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:

●	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. As a result of the merger between Yuma Energy, Inc., a Delaware corporation (“Yuma Co.”) and Pyramid Oil Company, the Company underwent a substantial change in ownership, management, assets and business strategy, all effective as of September 10, 2014. 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.”

Business Strategy

Our business strategy is to achieve long-term growth in production and cash flow on a cost-effective basis. We focus on maximizing our return on capital employed and adding production and reserves through the development of our Austin Chalk, Tuscaloosa, Wilcox, Frio, Marg Tex, Hackberry, Bakken, Three Forks, and Monterey Shale acreage.

Several of the key elements of our business strategy are as follows:

Ø	transition existing inventory of reserves into oil and natural gas production;

Ø	add to project inventory through ongoing prospect generation, exploration and strategic acquisitions; and

Ø	retain a greater percentage working interest in, and operatorship of, our projects going forward.

Our core competencies include:

Ø	generating unconventional oil resource plays;

Ø	generating onshore liquids-rich projects through the use of 3-D seismic surveys; and

Ø	identifying high impact deep onshore prospects located beneath known producing trends through the use of 3-D seismic surveys.

Operational Overview

Amazon 3-D Project – Calcasieu and Jefferson Parishes, Louisiana. During the second quarter of 2015, we completed our Anaconda prospect, the Talbot 23-1 well, where we hold approximately a 45.0% working interest after casing point. The well was perforated in a lower portion of the main Hackberry sand from 11,744 feet to 11,748 feet (MD) and tested at an initial gross production (“IP”) rate of approximately 7.0 MMcf/d and 180 Bbl/d of 55 degree API condensate on a 13/64th choke with flowing tubing pressures of approximately 9,000 pounds. Subsequent production from the well was held at approximately the same producing rates until July 23rd when the well stopped flowing. Cumulative production from this zone before it stopped producing was 227 MMcf of gas and 5.9 MBbls of condensate. Workover operations are underway and we anticipate having the well back on production in August 2015. The Talbot 23-1 has additional up-hole Hackberry sands in the main Hackberry section as well as four additional Marg-Tex sands with calculated pay behind pipe.

Greater Masters Creek Field – Allen, Vernon, Rapides and Beauregard Parishes, Louisiana. In January of 2015, the Crosby 14-1 well commenced production. During the initial clean-up period drilling mud and cuttings accumulated in the well which prevented it from flowing. Several attempts to clean out the well have since failed to establish sustainable production, and the well is now being prepared to be abandoned pending possible future utility. We hold a 61% working interest in this well.

La Posada, Bayou Hebert Field – Vermilion Parish, Louisiana. As of June 30, 2015, the field was producing approximately 53.6 MMcf/d of natural gas and 1,037 Bbl/d of oil gross (4.8 MMcf/d and 93 Bbl/d net). During the second quarter of 2015, the field averaged approximately 55.2 MMcf/d of natural gas and 1,044 Bbl/d of oil gross (5.0 MMcf/d and 94 Bbl/d net). We have an average net working interest in the project of approximately 12.5%.

Livingston Prospects – Livingston Parish, Louisiana. In January of 2015, we drilled the Blackwell 39-1 (35% working interest) to a total depth of 10,100 feet measured depth (10,042 feet TVD) and completed the well in the first Wilcox sand from 9,466 feet to 9,476 feet. During the third week in June of 2015, we installed artificial lift on the well using an electrical submersible pump (“ESP”) and tested the well at an initial gross production rate of 191 Bbl/d (50 Bbl/d net) of 42 degree API crude oil. The Blackwell 39-1 averaged approximately 146 Bbl/d (38 Bbl/d net) over the first 30 days of production with the ESP. Also during the second quarter of 2015, we converted the Roberts 57-1 (33% working interest) to ESP lift which resulted in a significant increase in production. Gross production from the Roberts 57-1 is currently averaging 110 Bbl/d (26 Bbl/d net) of 40 degree API crude oil.

We are currently in the process of evaluating further artificial lift enhancements in the remaining wells on the Livingston project. We currently have four wells producing from the lower Tuscaloosa sands, one of which is the Roberts 57-1, and three wells producing from the Wilcox sands, one of which is the Blackwell 39-1. During the second quarter of 2015, the field averaged approximately 515 Bbl/d gross (124 Bbl/d net). We have an average net working interest in the project of approximately 33%.

Lake Fortuna Field (Raccoon Island) – St. Bernard Parish, Louisiana. We are continuing to evaluate additional production enhancements and facility upgrades and plan to perform additional operations during the third quarter of 2015 to improve production from the field. During the second quarter of 2015, the field averaged approximately 132 Bbl/d gross (86 Bbl/d net). We have an average net working interest in the project of approximately 91%.

Gardner Island and Branville Bay – St. Bernard Parish, Louisiana. During the second quarter of 2015, we completed repair work on the salt water disposal well servicing the two fields and performed upgrades to the production facilities. Production from the two fields was restored in April 2015 and averaged approximately 359 Bbl/d gross (84 Bbl/d net) during the second quarter of 2015 inclusive of the downtime in April.

Cat Canyon Field – Santa Barbara County, California. We plan to drill our first operated well on this property in 2015. We are currently in the process of permitting the well.

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 six 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.

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 six months ended June 30, 2015 and 2014, and the average sales price per unit sold.

	Three Months Ended June 30,				Six Months Ended June 30,
	2015		2014		2015		2014
Production volumes:
Crude oil and condensate (Bbl)		60,956		60,603		124,592		123,490
Natural gas (Mcf)		500,404		860,515		990,540		1,716,404
Natural gas liquids (Bbl)		17,767		29,607		33,939		60,932
Total (Boe) (1)		162,124		233,629		323,621		470,490

Average prices realized:
Excluding commodity derivatives (both realized and unrealized)
Crude oil and condensate (per Bbl)	$	59.22	$	103.20	$	52.72	$	102.28
Natural gas (per Mcf)	$	2.85	$	4.86	$	2.80	$	4.97
Natural gas liquids (per Bbl)	$	22.71	$	37.86	$	19.57	$	41.39
Including commodity derivatives (realized only)
Crude oil and condensate (per Bbl)	$	52.00	$	91.90	$	73.62	$	93.69
Natural gas (per Mcf)	$	3.23	$	4.47	$	4.89	$	4.97
Natural gas liquids (per Bbl)	$	22.71	$	37.86	$	19.57	$	41.39

(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 six months ended June 30, 2015 and 2014.

	Three Months Ended June 30,						Six Months Ended June 30,
	2015			2014			2015			2014
Sales of natural gas and crude oil:
Crude oil and condensate	$	3,609,719		$	6,254,072		$	6,567,989		$	12,631,160
Natural gas		1,429,114			4,186,260			2,771,188			8,531,860
Natural gas liquids		403,544			1,120,936			664,110			2,522,182
Realized gain (loss) on commodity derivatives		(255,049	)		(1,020,979	)		4,681,785			(1,994,173	)
Unrealized loss on commodity derivatives		(1,441,930	)		(708,547	)		(5,308,196	)		(1,686,933	)
Gas marketing sales		92,517			147,783			104,286			330,868

Other revenue		316,746			302,143			586,764			543,636
Total revenues	$	4,154,661		$	10,281,668		$	10,067,926		$	20,878,600

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

	Three Months Ended June 30,				Six Months Ended June 30,
	2015		2014		2015		2014
Benchmarks:
WTI crude oil (per Bbl, average price) (a)	$	57.86	$	102.99	$	53.29	$	100.84
LLS crude oil (per Bbl, average price) (b)	$	62.97	$	105.55	$	57.89	$	104.96
Mont Belvieu NGLs (per Bbl) (c)	$	7.14	$	12.18	$	7.56	$	13.44
Henry Hub natural gas (per MMBtu) (d)	$	2.64	$	4.67	$	2.81	$	4.80

(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, BS&W (Basic Sediment and Water) and transportation. Generally, the index or posting is based on WTI (West Texas Intermediate) and adjusted to LLS (Light Louisiana Sweet) or HLS (Heavy Louisiana Sweet). For the three months ended June 30, 2015 and 2014, LLS postings averaged $5.11 and $2.56 over WTI, respectively. For the six months ended June 30, 2015 and 2014, LLS postings average $4.60 and $4.12 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 353 Bbls, or 0.6%, for the three months ended June 30, 2015 compared to the three months ended June 30, 2014. The increase resulted from the addition of Pyramid volumes, production from two new wells, the Blackwell 39-1 and the Nettles 39-1, and an increase in production from the Gardner Island and Branville Bay wells, all of which helped to offset a net decrease in production from the La Posada wells and decreases in production from the Crosby 12-1, the Bertha 8-3 and the Raccoon Island wells. The production decrease at Raccoon Island was due to constraints in the water handling system. There was a $43.98, or 42.6% decrease in price per Bbl for the three months ended June 30, 2015 compared to the three months ended June 30, 2014. For the six months ended June 30, 2015, crude oil volumes increased by 1,102 Bbls, or 0.9%, compared to the six months ended June 30, 2014. The increase resulted from the addition of Pyramid volumes, production from the Blackwell 39-1 and the Nettles 39-1, and the increase in production from the Gardner Island and Branville Bay wells, offsetting a net decrease in production from the La Posada wells and decreases in production from the Crosby 12-1, the Weyerhaeuser 57-3 and the Raccoon Island wells. There was a $49.56, or 48.6%, decrease in price per Bbl for the six months ended June 30, 2015 compared to the six months ended June 30, 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 June 30, 2015 and 2014, Henry Hub natural gas futures contract settlements averaged $2.64 and $4.67 respectively, a 43.5% decrease per MMBtu. For the six months ended June 30, 2015 and 2014, Henry Hub natural gas futures contract settlements decreased 41.5% to $2.81 from $4.80.

For the three months ended June 30, 2015 compared to the same period in 2014, a 41.8% decrease in natural gas volumes sold was due to a net decrease in production from the La Posada wells, which offset new production from the Talbot 23-1 well. During the three months ended June 30, 2015, natural gas prices decreased $2.01 per Mcf, or 41.4% compared to the same period in 2014. For the six months ended June 30, 2015 compared to the same period in 2014, a 42.3% decrease in natural gas volumes sold was also due to the net decrease in production from the La Posada wells offsetting new production from the Talbot 23-1 well. During the six months ended June 30, 2015, natural gas prices decreased $2.17 per Mcf, or 43.7% compared to 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 $.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 six months ended June 30, 2015 and 2014, are set forth below:

	Three Months Ended June 30,				Six Months Ended June 30,
	2015		2014		2015		2014
Lease operating expenses	$	3,226,225	$	3,264,643	$	6,449,341	$	6,923,148

LOE per Boe	$	19.90	$	13.97	$	19.93	$	14.71

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. If severance and ad valorem taxes were not included in the above table, LOE would have been reduced by $822,597 and $1,126,319 during the three months ended June 30, 2015 and 2014, respectively, and operating costs per barrel of oil equivalent would have been reduced to $14.82 and $9.15 for the three months ended June 30, 2015 and 2014, respectively. For the six months ended June 30, 2015 and 2014, if severance and ad valorem taxes were not included, LOE would have been reduced by $1,537,382 and $2,319,047, respectively, and operating costs per barrel of oil equivalent would have been reduced to $15.18 and $9.78, respectively.

LOE was $3,226,225 for the three months ended June 30, 2015 compared to $3,264,643 for the same period in 2014, a decrease of $38,418, or 1.2%. Included in expenses for the three months ended June 30, 2015, was $580,956 of LOE from Pyramid. Excluding the Pyramid LOE the decrease was $619,374, or 19.0%. Of that, $632,662 comes from reduced production taxes and marketing and transportation expenses, a consequence of lower natural gas sales volumes and lower natural gas and oil prices. An increase of $5.93 in LOE per Boe for the three months ended June 30, 2015, is primarily attributable to Pyramid’s LOE per Boe of $53.99.

For the six months ended June 30, 2015, LOE decreased by $473,807 from the same period in 2014, even with the addition of $1,129,192 in LOE from Pyramid. Most of the decrease was from reduced production taxes and marketing and transportation expenses of $1,380,126. LOE per Boe increased for the same period from $14.71 to $19.93, a 35.5% increase due primarily to Pyramid’s LOE per Boe of $51.13.

Re-engineering and Workovers

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

Workover expenses for the three months ended June 30, 2015 totaled $60,063 compared to $550,401 for the same period in 2014. Workover costs for the six months ended June 30, 2015 totaled $554,492, while costs for the same period in 2014 totaled $551,911.

General and Administrative Expenses

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

	Three Months Ended June 30,				Six Months Ended June 30,
	2015		2014		2015		2014
General and administrative
Stock-based compensation	$	160,498	$	35,816	$	2,573,240	$	91,938
Capitalized		26,577		6,890		700,909		15,098
Net stock-based compensation		133,921		28,926		1,872,331		76,840

Other		2,790,108		2,399,824		5,374,041		6,301,525
Capitalized		629,199		610,774		1,270,902		1,362,404
Net other		2,160,909		1,789,050		4,103,139		4,939,121

Net general and administrative	$	2,294,830	$	1,817,976	$	5,975,470	$	5,015,961

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 June 30, 2015 compared to the same period in 2014 was an increase of $476,854, or 26%. 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.

G&A expenses for the six month period ended June 30, 2015 increased by $959,509, or 19%, over the same period in 2014. In addition to the higher legal, regulatory and consulting costs discussed above, two items accounted for higher than normal G&A costs in each of the six month periods ended

June 30, 2015 and 2014. Stock-based compensation in the period ended June 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 $1,795,491 increase for the six months ended June 30, 2015 compared to the same period in 2014 for net stock-based compensation costs. Additionally, during the six months ended June 30, 2014, we had non-recurring professional costs associated with the merger and costs to explore other public listing options which totaled $1,884,965.

Depreciation, Depletion and Amortization

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

	Three Months Ended June 30,				Six Months Ended June 30,
	2015		2014		2015		2014
Depreciation, Depletion and Amortization	$	3,755,446	$	6,012,525	$	7,896,466	$	11,738,608

DD&A per Boe	$	23.16	$	25.74	$	24.40	$	24.95

The net Boe quantities of oil, natural gas and natural gas liquids produced and sold by us decreased by 31% for both the three months and six months ended June 30, 2015 compared to the same periods in 2014. This decrease in production was the primary factor for the 38% decrease in DD&A for the current quarter and 33% decrease for year-to-date. 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 June 30,						Six Months Ended June 30,
	2015			2014			2015			2014
Net Income	$	(8,191,464	)	$	(7,550,697	)	$	(12,210,038	)	$	(7,845,675	)
Depreciation, depletion & amortization of property and equipment		3,755,446			6,012,525			7,896,466			11,738,608
Interest expense, net of interest income and amounts capitalized		109,305			66,402			188,447			204,772
Income tax benefit		(3,421,600	)		(285,000	)		(5,380,600	)		(1,134,000	)
Costs to obtain a public listing		-			295,835			-			1,884,965
Increase in value of preferred stock derivative liability		-			5,975,944			-			4,503,914
Stock-based compensation net of capitalized cost		133,921			28,926			1,872,331			76,840
Accretion of asset retirement obligation		166,773			145,945			329,557			288,089
Goodwill impairment		5,349,988			-			5,349,988			-
Amortization of benefit from commodity derivatives sold		-			(23,437	)		-			(46,875	)
Net commodity derivatives mark-to-market loss		1,441,930			708,547			5,308,196			1,686,933
Adjusted EBITDA	$	(655,701	)	$	5,374,990		$	3,354,347		$	11,357,571

Adjusted EBITDA is provided as an additional metric that is used by our board of directors and management to measure operating performance and trends. Adjusted EBITDA for the three and six months ended June 30, 2015 decreased from the same periods in 2014 by $6,030,691 (112%) and $8,003,224 (70%), respectively.

Adjusted EBITDA is presented based on management’s belief that it will enable a user of the financial information to understand the impact of these items on reported results. Additionally, this presentation provides a helpful comparison to similarly adjusted measurements of prior periods. Adjusted EBITDA is not a measure of financial performance under GAAP and should not be considered as an alternative to net income, earnings per share and cash flow from operations, as defined by GAAP. Adjusted EBITDA may not be comparable to similarly named non-GAAP financial measures that other companies may use and may not be useful in comparing the performance of those companies to our performance.

Interest Expense

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

	Three Months Ended June 30,						Six Months Ended June 30,
	2015			2014			2015			2014
Interest expense	$	364,714		$	332,363		$	689,543		$	708,683
Interest capitalized		(250,336	)		(264,507	)		(483,158	)		(501,408	)
Net	$	114,378		$	67,856		$	206,385		$	207,275

Bank debt	$	29,900,000		$	24,775,000		$	29,900,000		$	24,775,000
Bank debt - weighted average outstanding	$	28,880,824		$	28,838,736		$	28,113,619		$	30,571,961

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 $5,380,600 on a pre-tax net loss of $17,590,638 resulting in an effective tax rate of 31% for the six months ended June 30, 2015. For the six months ended June 30, 2014, we recorded an income tax benefit of $1,134,000 on a pre-tax loss of $8,979,675, resulting in an effective tax rate of 13%. A loss of $4,503,914 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 six months ended June 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 six months ended June 30, 2015 and 2014 is summarized as follows:

	Six Months Ended June 30,
	2015			2014
Cash flows provided by (used in) operating activities	$	(3,401,231	)	$	15,051,583
Cash flows used in investing activities		(8,099,724	)		(6,759,585	)
Cash flows provided by (used in) financing activities		8,225,636			(6,254,582	)
Net increase (decrease) in cash	$	(3,275,319	)	$	2,037,416

Cash Flows From Operating Activities

Cash flows from operations for the six months ended June 30, 2015 decreased 123% over the same period in 2014 principally due to declines in commodity prices. While crude oil volumes increased nominally, crude oil prices, LLS posting (a majority of the Company’s crude oil is sold at an LLS posting) averaged $57.89 per Bbl for the six months ended June 30, 2015 compared to $104.96 per Bbl for the same period in 2014, representing a 45% decline. Natural gas volumes declined 42.3% for the six months ended June 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 41.5% to $2.81 per MMBtu for the six months ended June 30, 2015 compared to the six months ended June 30, 2014. Total revenues were $10,067,926 and $20,878,600 for the six months ended June 30, 2015 and 2014, respectively, representing a 52% decline. In addition, there was a $7.4 million change in current operating assets and liabilities for the six months ended June 30, 2015, driven by an $11.7 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

	Six Months Ended June 30,
	2015			2014

Acquisition of acreage and new properties	$	1,950,946		$	2,625,909
Drilling and completion		3,612,660			7,827,840
Recompletions, capital workovers and plugging and abandoning (“P&A”)		1,009,979			(770,841	)
Total oil and natural gas investing activities		6,573,585			9,682,908
Corporate office property and equipment purchases		31,720			60,414
Total cash used for capitalized expenditures on property and equipment		6,605,305			9,743,322
Proceeds from sale of property		(30,442	)		(307,600	)
Decrease in short-term investments		(1,170,868	)		-
Decrease in noncurrent receivable from affiliate		-			(95,634	)
Cash flows used in investing activities, including accounts payable		5,403,995			9,340,088
Change in capital expenditures financed by accounts payable		2,695,729			(2,580,503	)
Cash flows used in investing activities	$	8,099,724		$	6,759,585

During the six months ended June 30, 2015, the Amazon 3-D Project accounted for $3,626,098 of our total oil and natural gas investing activities. Of that, $2,993,630 was spent on the drilling of the Talbot 23-1 well and related Anaconda prospect costs. At the Greater Masters Creek Field, $1,353,046 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, $885,579 was spent, with most of the expenditures going to the completion of the Blackwell 39-1 well and related Musial prospect costs.

For the six months ended June 30, 2014, lease related costs of $1,295,551 were incurred on the Austin Chalk Phase I and II, a part of the Greater Masters Creek Field, while $7,252,904 was incurred in the drilling of the Crosby 14-1, an Austin Chalk Phase II well. We incurred $568,881 of geological and geophysical costs in evaluating the California producing properties of Pyramid Oil Company. A net credit of $671,553 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 a significant portion of future crude oil and natural gas production out three years (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 April 7, 2015, we entered into the Seventh Amendment to the credit agreement which provided for a $33.0 million conforming borrowing base and a $3.0 million non-conforming borrowing base, providing a total borrowing base of $36.0 million. At June 30, 2015, we had available borrowing capacity of $6.1 million. On July 27, 2015, the Eighth Amendment set the borrowing base at $33.5 million plus a $1.5 million non-conforming portion for a total of $35.0 million. The borrowing base is scheduled to be reviewed again on October 1, 2015.

	Six Months Ended		Year Ended
	June 30, 2015		December 31, 2014
Credit Facility:
Balances outstanding, beginning of year	$	22,900,000	$	31,215,000
Activity		7,000,000		(8,315,000	)
Balances outstanding, end of period	$	29,900,000	$	22,900,000

Other than the credit facility, we had debt of $431,546 and $282,843 at June 30, 2015 and December 31, 2014, respectively, from installment loans financing oil and natural gas property insurance premiums. We had a cash balance of $8.3 million at June 30, 2015.

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

	June 30, 2015				December 31, 2014
	Oil		Gas		Oil		Gas
Assets
Current	$	-	$	110,027	$	1,851,542	$	1,486,995
Noncurrent		-		6,579		1,006,845		396,264

Liabilities
Current		720,299		-		-		-
Noncurrent		51,219		-		-		-

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 D – Commodity Derivative Instruments.

The fair market value of our commodity derivative contracts in place at June 30, 2015 and December 31, 2014 were net liabilities of $654,912 and net assets of $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 $15,542 net after taxes into earnings from accumulated other comprehensive income during the remaining six months 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 D – 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 June 30, 2015:

			Commodity Derivatives			Operating		Asset Retirement
	Debt (1)		Assets (2)			Leases		Obligations
2015	$	431,546	$	(483,784	)	$	284,875	$	-
2016		-		(303,453	)		576,274		673,336
2017		29,900,000		132,325			561,106		2,807,881
2018		-		-			2,264		787,428
2019		-		-			-		338,086
Thereafter		-		-			-		8,144,237
Totals	$	30,331,546	$	(654,912	)	$	1,424,519	$	12,750,968

(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 June 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).

Recent Developments

At Market Issuance Sales Agreement

On December 19, 2014, we entered into an At Market Issuance Sales Agreement (the “sales agreement”) with an investment banking firm (the “Agent”). The offer and sale of these shares are registered under a shelf registration statement filed with the SEC on November 21, 2013. The sales agreement provides that our Series A Preferred Stock and our common stock will be sold at market prices prevailing at the time of the sale of such shares, at no discount to market. We are not obligated to make any sales under the sales agreement. We have agreed to pay the Agent a commission rate of up to 6.0% of the gross proceeds from the sale of shares of Series A Preferred Stock and shares of our common stock sold through the Agent under the sales agreement, reimburse the Agent for certain expenses incurred in connection with entering into the sales agreement, and provide the Agent with customary indemnification rights. The full terms and text of the sales agreement were filed with our Current Report on Form 8-K on December 29, 2014. Through August 14, 2015, we have sold and issued 46,857 shares of Series A Preferred Stock and 1,347,458 shares of our common stock under the sales agreement.

Shareholder Meeting

On June 9, 2015, Yuma held its annual shareholder meeting. Class I directors, Sam L. Banks and Ben T. Morris, were elected for another term. Richard W. Volk did not stand for re-election, and is no longer a member of our Board. The other matters presented to shareholders were passed as filed in our Current Report on Form 8-K on June 15, 2015.

Amendment to Senior Credit Agreement

On July 27, 2015, we entered into the Eighth Amendment to our Credit Agreement (the “credit agreement”) with Société Générale (the “Bank”) as Administrative Agent, which provides for a line of credit until May 20, 2017. Pursuant to the credit agreement, we secured a credit facility (the “credit facility”), which is available to provide financing of up to $35.0 million. The credit agreement is secured by a first lien on substantially all of the Company’s assets. The credit facility has a $33.5 million conforming borrowing base and a non-conforming borrowing base of $1.5 million. The next borrowing base redetermination date is scheduled for October 1, 2015. Generally, the credit facility is subject to redetermination on March 1 and October 1 of each year. Amounts borrowed under the credit agreement bear interest at either (a) the LIBOR rate plus 2.25% to 3.75% or (b) the prime rate plus 1.25% to 2.75%, depending on the amount borrowed under the credit facility. The credit facility contains a number of covenants that, among other things, restrict, subject to certain exceptions, our ability to incur additional indebtedness, create liens on assets, sell certain assets and engage in certain transactions with affiliates. Additionally, the credit agreement contains a covenant restricting the payment of dividends on preferred stock if there is less than ten percent availability on the borrowing base. The credit facility also requires the maintenance of certain financial ratios. See Part I, Item 1. Unaudited Notes to the Consolidated Financial Statements, Note H – Debt and Interest Expense.

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 June 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 L – Contingencies, and is incorporated herein by reference.

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

Item 1A. Risk Factors.

In addition to the other information set forth in this report, you should carefully consider the factors discussed in Part I, “Item 1A – Risk Factors” in our Annual Report for the year ended December 31, 2014 on Form 10-K, which could materially affect our business, financial condition or future results. The risks described in our 2014 Annual Report on Form 10-K may not be the only risks facing our Company. There are no updates to our risk factors as disclosed in our Annual Report on Form 10-K for the year ended December 31, 2014. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial may materially adversely affect our business, financial condition and/or operating results.

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

None.

Item 3. Defaults Upon Senior Securities.

None.

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 June 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.


	By:	/s/ Sam L. Banks
	Name:	Sam L. Banks
Date: August 14, 2015	Title:	President and Chief Executive Officer (Principal Executive Officer)



	By:	/s/ Kirk F. Sprunger
Date: August 14, 2015	Name:	Kirk F. Sprunger
	Title:	Chief Financial Officer (Principal Financial Officer)