Yuma Energy, Inc. - FORM 10-Q

Attached files

file	filename
EX-31.1 - CERTIFICATION PURSUANT TO RULE 13A-14(A)/15D-14(A) CERTIFICATIONS SECTION 302 OF THE SARBANES-OXLY ACT OF 2002 - Yuma Energy, Inc.	yuma_ex311.htm
EX-32.2 - CERTIFICATE PURSUANT TO SECTION 18 U.S.C. PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002 - Yuma Energy, Inc.	yuma_ex322.htm
EX-32.1 - CERTIFICATE PURSUANT TO SECTION 18 U.S.C. PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002 - Yuma Energy, Inc.	yuma_ex321.htm
EX-31.2 - CERTIFICATION PURSUANT TO RULE 13A-14(A)/15D-14(A) CERTIFICATIONS SECTION 302 OF THE SARBANES-OXLY ACT OF 2002 - Yuma Energy, Inc.	yuma_ex312.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, 2016

[ ] 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 15, 2016, 72,579,820 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, 2016 and December 31, 2015.	3

		Consolidated Statements of Operations for the Three and Six Months ended June 30, 2016 and 2015.	5

		Consolidated Statements of Comprehensive Income (Loss) for the Three and Six Months ended June 30, 2016 and 2015.	6

		Consolidated Statements of Changes in Equity for the Six Months ended June 30, 2016 and the year ended December 31, 2015.	7

		Consolidated Statements of Cash Flows for the Six Months ended June 30, 2016 and 2015.	8

		Unaudited Condensed Notes to the Consolidated Financial Statements.	9

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations.		27

Item 3.	Quantitative and Qualitative Disclosures About Market Risk.		40

Item 4.	Controls and Procedures.		40

	PART II – OTHER INFORMATION

Item 1.	Legal Proceedings.		41

Item 1A.	Risk Factors.		41

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds.		42

Item 3.	Defaults Upon Senior Securities.		42

Item 4.	Mine Safety Disclosures.		42

Item 5.	Other Information.		42

Item 6.	Exhibits.		43

	Signatures.		44

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements.

Yuma Energy, Inc.

CONSOLIDATED BALANCE SHEETS

	June 30,	December 31,
	2016	2015
	(Unaudited)	(As Restated)
ASSETS

CURRENT ASSETS:
Cash and cash equivalents	$2,092,997	$5,355,191
Accounts receivable, net of allowance for doubtful accounts:
Trade	2,781,350	2,829,266
Officers and employees	62,058	75,404
Other	316,723	633,573
Commodity derivative instruments	980,189	2,658,047
Prepayments	375,656	704,523
Other deferred charges	29,805	415,740

Total current assets	6,638,778	12,671,744

OIL AND GAS PROPERTIES (full cost method):
Not subject to amortization	14,940,004	14,288,716
Subject to amortization	205,301,727	204,512,038

	220,241,731	218,800,754
Less: accumulated depreciation, depletion and amortization	(132,665,148)	(117,304,945)

Net oil and gas properties	87,576,583	101,495,809

OTHER PROPERTY AND EQUIPMENT:
Land, buildings and improvements	2,795,000	2,795,000
Other property and equipment	3,497,948	3,460,507
	6,292,948	6,255,507
Less: accumulated depreciation and amortization	(2,296,906)	(2,174,316)

Net other property and equipment	3,996,042	4,081,191

OTHER ASSETS AND DEFERRED CHARGES:
Commodity derivative instruments	329,819	1,070,541
Deposits	414,064	264,064
Other noncurrent assets	-	38,104

Total other assets and deferred charges	743,883	1,372,709

TOTAL ASSETS	$98,955,286	$119,621,453

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

Yuma Energy, Inc.

CONSOLIDATED BALANCE SHEETS – CONTINUED

	June 30,	December 31,
	2016	2015
	(Unaudited)	(As Restated)
LIABILITIES AND EQUITY

CURRENT LIABILITIES:
Current maturities of debt	$29,800,000	$30,063,635
Accounts payable, principally trade	6,335,891	7,933,664
Commodity derivative instruments	143,987	-
Asset retirement obligations	435,936	70,000
Other accrued liabilities	2,022,327	1,781,484

Total current liabilities	38,738,141	39,848,783

OTHER NONCURRENT LIABILITIES:
Asset retirement obligations	8,469,015	8,720,498
Commodity derivative instruments	10,004	-
Deferred taxes	192,129	1,417,364
Other liabilities	14,540	30,090

Total other noncurrent liabilities	8,685,688	10,167,952

EQUITY:
Preferred stock	10,828,603	10,828,603
Common stock, no par value (300 million shares authorized, 72,544,053 and 71,834,617 issued)	142,533,459	141,858,946
Accumulated earnings (deficit)	(101,830,605)	(83,082,831)

Total equity	51,531,457	69,604,718

TOTAL LIABILITIES AND EQUITY	$98,955,286	$119,621,453

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,
	2016	2015	2016	2015
		(As Restated)		(As Restated)
REVENUES:
Sales of natural gas and crude oil	$3,124,424	$5,534,894	$6,056,010	$10,107,573
Net gains (losses) from commodity derivatives	(1,226,702)	(1,696,979)	(855,764)	(626,411)
Total revenues	1,897,722	3,837,915	5,200,246	9,481,162

EXPENSES:
Lease operating	1,880,060	3,226,225	3,893,209	6,449,341
Re-engineering and workovers	-	60,063	-	554,492
Marketing cost of sales	-	97,994	-	199,682
General and administrative – stock-based
compensation	301,808	133,921	720,098	1,872,331
General and administrative – other	2,003,719	1,844,163	4,161,205	3,516,375
Depreciation, depletion and amortization	2,020,804	3,755,446	4,467,205	7,896,466
Asset retirement obligation accretion expense	105,242	166,773	210,256	329,557
Impairments	11,015,589	4,927,508	11,015,589	4,927,508
Other	8,647	707,338	(16,785)	718,649
Total expenses	17,335,869	14,919,431	24,450,777	26,464,401

INCOME (LOSS) FROM OPERATIONS	(15,438,147)	(11,081,516)	(19,250,531)	(16,983,239)

OTHER INCOME (EXPENSE):
Interest expense	(326,396)	(114,378)	(729,044)	(206,385)
Other, net	(2,447)	5,310	6,566	21,466
Total other income (expense)	(328,843)	(109,068)	(722,478)	(184,919)

NET INCOME (LOSS) BEFORE INCOME TAXES	(15,766,990)	(11,190,584)	(19,973,009)	(17,168,158)

Income tax expense (benefit)	(692,302)	(1,640,910)	(1,225,235)	(3,935,492)

NET INCOME (LOSS)	(15,074,688)	(9,549,674)	(18,747,774)	(13,232,666)

PREFERRED STOCK, PERPETUAL PREFERRED
SERIES A:
Dividends paid in cash	-	318,874	-	619,689
Dividends in arrears	320,626	-	641,252	-

NET INCOME (LOSS) ATTRIBUTABLE TO
COMMON STOCKHOLDERS	$(15,395,314)	$(9,868,548)	$(19,389,026)	$(13,852,355)

EARNINGS (LOSS) PER COMMON SHARE:
Basic	$(0.21)	$(0.14)	$(0.27)	$(0.20)
Diluted	$(0.21)	$(0.14)	$(0.27)	$(0.20)

WEIGHTED AVERAGE NUMBER OF COMMON
SHARES OUTSTANDING:
Basic	72,185,618	71,502,546	72,048,490	70,384,326
Diluted	72,185,618	71,502,546	72,048,490	70,384,326

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,
	2016	2015	2016	2015
		(As Restated)		(As Restated)

NET LOSS	$(15,074,688)	$(9,549,674)	$(18,747,774)	$(13,232,666)

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	-	31,554
Less income taxes	-	3,125	-	12,148

Reclassification of loss on settled
commodity derivatives, net of income taxes	-	4,993	-	19,406


OTHER COMPREHENSIVE INCOME (LOSS)	-	4,993	-	(54,343)

COMPREHENSIVE LOSS	$(15,074,688)	$(9,544,681)	$(18,747,774)	$(13,287,009)

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

Yuma Energy, Inc.

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

	June 30,	December 31,
	2016	2015
	(Unaudited)	(As Restated)

PERPETUAL PREFERRED STOCK - 9.25% CUMULATIVE AND REDEEMABLE, NO PAR VALUE:
Balance at beginning of period: 554,596 for 2016 and 507,739 shares for 2015	$10,828,603	$9,958,217
Sales of 46,857 shares for 2015	-	870,386
Balance at end of period: 554,596 shares for both 2016 and 2015	10,828,603	10,828,603

COMMON STOCK, NO PAR VALUE:
Balance at beginning of period: 71,834,617 shares for 2016 and 69,139,869 shares for 2015	141,858,946	137,469,772
Sales of 1,347,458 shares of common stock in 2015	-	1,363,160
Restricted stock awards, of which 983,804 vested in 2016 and 1,676,113 vested in 2015	570,376	3,171,477
Buy back shares from vested stock awards: 274,368 in 2016 and 328,823 in 2015	(69,177)	(300,732)
Stock appreciation rights issued in 2015, of which 789,117 vested in 2016	173,314	155,269
Balance at end of period: 72,544,053 shares for 2016 and 71,834,617 shares for 2015	142,533,459	141,858,946

ACCUMULATED OTHER COMPREHENSIVE INCOME:
Balance at beginning of period	-	38,801
Comprehensive income (loss) from commodity derivative instruments, net of income taxes	-	(38,801)
Balance at end of period	-	-

ACCUMULATED EARNINGS (DEFICIT):
Balance at beginning of period	(83,082,831)	(67,195,800)
Net loss	(18,747,774)	(14,839,840)
Series A perpetual preferred stock cash dividends	-	(1,047,191)
Balance at end of period	(101,830,605)	(83,082,831)

TOTAL EQUITY	$51,531,457	$69,604,718

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,
	2016	2015
		(As Restated)
CASH FLOWS FROM OPERATING ACTIVITIES:
Reconciliation of net loss to net cash provided by (used in) operating activities
Net loss	$(18,747,774)	$(13,232,666)
Impairment of oil and gas properties	11,015,589	-
Impairment of goodwill	-	4,927,508
Depreciation, depletion and amortization of property and equipment	4,467,205	7,896,466
Accretion of asset retirement obligation	210,256	329,557
Stock-based compensation net of capitalized cost	720,098	1,872,331
Amortization of other assets and liabilities	457,990	136,758
Deferred tax expense (benefit)	(1,225,235)	(3,937,892)
Bad debt expense increase (decrease)	(16,785)	737,536
Unrealized (gains) losses on commodity derivatives	2,572,571	5,308,196
Other	-	(18,887)
Changes in current operating assets and liabilities:
Accounts receivable	394,897	3,427,212
Other current assets	328,867	(61,604)
Accounts payable	(1,273,595)	(11,663,279)
Other current liabilities	219,138	877,533
Other noncurrent assets and liabilities	(108,618)	-
NET CASH USED IN OPERATING ACTIVITIES	(985,396)	(3,401,231)

CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures on property and equipment	(1,873,671)	(9,301,034)
Proceeds from sale of property	1,740	30,442
Decrease in short-term investments	-	1,170,868
NET CASH USED IN INVESTING ACTIVITIES	(1,871,931)	(8,099,724)

CASH FLOWS FROM FINANCING ACTIVITIES:
Change in borrowing on line of credit	-	7,000,000
Proceeds from insurance note	-	536,762
Payments on insurance note	(263,635)	(388,059)
Line of credit financing costs	(72,055)	(210,194)
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)
Common stock purchased from employees	(69,177)	(300,732)
Other	-	(25,998)
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES	(404,867)	8,225,636

NET DECREASE IN CASH AND CASH EQUIVALENTS	(3,262,194)	(3,275,319)

CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD	5,355,191	11,558,322

CASH AND CASH EQUIVALENTS AT END OF PERIOD	$2,092,997	$8,283,003

Supplemental disclosure of cash flow information:
Interest payments (net of interest capitalized)	$308,434	$20,479
Interest capitalized	$253,313	$483,158
Supplemental disclosure of significant non-cash activity:
(Increase) decrease in capital expenditures financed by accounts payable	$324,178	$2,695,729

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

Yuma Energy, Inc.

UNAUDITED CONDENSED NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1 – BASIS OF PRESENTATION

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

Restatement Background

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

As a result, management, the Audit Committee and the Board of Directors determined after consideration of the relevant facts and circumstances, that the Company’s consolidated financial statements as of December 31, 2015 and 2014, and for the years ended December 31, 2015, 2014 and 2013 contained within the Company’s Annual Report on Form 10-K for the year ended December 31, 2015 (the “2015 Form 10-K”), and the financial data included in its interim consolidated financial statements set forth in its quarterly reports on Form 10-Q for the quarter ended September 30, 2014, and for all subsequent quarters through the quarter ended December 31, 2015, should be restated, and that such financial statements previously filed with the SEC, should no longer be relied upon.

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

NOTE 2 – LIQUIDITY CONSIDERATIONS AND GOING CONCERN

The Company has borrowings which require, among other things, compliance with certain financial ratios. Due to operating losses the Company has sustained during recent quarters as a result of the prolonged weak commodity price environment and other factors, the Company was not in compliance with the trailing four quarter funded debt to EBITDA financial ratio covenant under its credit facility at September 30, 2015, December 31, 2015 or at March 31, 2016, as well as its EBITDA to interest expense ratio as of December 31, 2015 and March 31, 2016. In addition, the Company was not in compliance due to its going concern opinion at March 31, 2016, as well as its failure to maintain a certain financial bank as its principal depository bank. On May 20, 2016, the Company remedied its compliance with regard to the depository bank. On December 30, 2015, the Company’s wholly owned subsidiary, Yuma Exploration and Production Company, Inc. (“Exploration”) entered into the Waiver, Borrowing Base Redetermination and Ninth Amendment (the “Ninth Amendment”) to the credit agreement which provided for a $29.8 million conforming borrowing base, with an automatic reduction to $20.0 million on May 31, 2016, and waived the compliance with the trailing four quarter funded debt to EBITDA and EBITDA to interest expense financial ratio covenants or any other events of default under the credit facility for the quarters ended September 30, 2015 and December 31, 2015. On June 6, 2016 and effective as of May 31, 2016, Exploration entered into the Waiver and Tenth Amendment to the credit agreement (the “Tenth Amendment”), which maintains the borrowing base at $29.8 million and automatically reduces the borrowing base to $20.0 million on the earliest of (each a “Tenth Amendment Termination Date”) (i) August 15, 2016, if the registration statement on Form S-4 (the “Form S-4”) filed with the SEC pursuant to the pending agreement and plan of merger dated as of February 10, 2016 (the “merger agreement”) by and among the Company, two wholly owned subsidiaries of the Company, and Davis Petroleum Acquisition Corp. (“Davis”) has not been declared effective by such date; (ii) the date that is forty-seven days after the date the Form S-4 has been declared effective by the SEC; (iii) September 30, 2016; and (iv) in the event of the termination of the merger agreement. As of June 30, 2016, the Company had a working capital deficit of $32.1 million inclusive of the Company’s outstanding debt under its credit facility, which was fully drawn with no additional borrowing capacity available.

A breach of any of the terms and conditions or the financial covenants contained in the credit agreement could result in acceleration of the Company’s indebtedness, in which case the debt would become immediately due and payable. Given that the Company was in violation of the funded debt to EBITDA and EBITDA to interest expense ratio covenants as of March 31, 2016, and was out of compliance with the funded debt to EBITDA, EBITDA to interest expense and current asset to current liability ratio covenants as of June 30, 2016, the Company has classified its bank debt as a current liability in its financial statements. In the event the Form S-4 is not declared effective by August 15, 2016, the Company anticipates working with its lenders to obtain an extension of its waivers until the closing of the transaction. In the event that the Company does not obtain an extension or waiver of the violations, then the Company’s outstanding indebtedness would become immediately due and payable.

During 2015 and 2016, the Company initiated several strategic alternatives to remedy its debt covenant compliance issues and provide working capital to develop the Company’s existing assets. On February 10, 2016, the Company entered into the merger agreement. Upon completion of the transaction, which is subject to the approval of the stockholders of both companies and other conditions, Davis will become a wholly owned subsidiary of the Company. Subject to bank approval, it is anticipated that the Company will enter into another credit agreement amendment that will take into account the contemplated merger with Davis (see Note 15 – Agreement and Plan of Merger and Reorganization). However, the Company’s management can provide no assurance that the merger with Davis and the amendment to the credit agreement will actually occur.

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

NOTE 3 – ACCOUNTING STANDARDS

Not Yet Adopted

In March 2016, the Financial Accounting Standards Board (“FASB”) issued ASU 2016-09, “Improvements to Employee Share-Based Payment Accounting,” which seeks to simplify accounting for share-based payment transactions including income tax consequences, classification of awards as either equity or liabilities, and the classification on the statement of cash flows. The new standard requires the Company to recognize the income tax effects of awards in the income statement when the awards vest or are settled. The guidance is effective for fiscal years beginning after December 15, 2016. Early adoption is permitted and if an entity early adopts the guidance in an interim period, any adjustments must be reflected as of the beginning of the fiscal year that includes that interim period. The Company is currently evaluating the impact of adopting this standard on its Consolidated Financial Statements.

In February 2016, the FASB issued ASU 2016-02, “Leases,” a new lease standard requiring lessees to recognize lease assets and lease liabilities for most leases classified as operating leases under previous GAAP. The guidance is effective for fiscal years beginning after December 15, 2018 with early adoption permitted. The Company will be required to use a modified retrospective approach for leases that exist or are entered into after the beginning of the earliest comparative period in the financial statements. The Company is currently evaluating the impact of adopting this standard on its Consolidated Financial Statements.

In January 2016, the FASB issued ASU 2016-01, “Recognition and Measurement of Financial Assets and Financial Liabilities,” which changes certain guidance related to the recognition, measurement, presentation and disclosure of financial instruments. This update is effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years. Early adoption is not permitted for the majority of the update, but is permitted for two of its provisions. The Company is evaluating the new guidance and has not determined the impact this standard may have on its Consolidated Financial Statements.

In May 2014, the FASB issued ASU 2014-09, “Revenue from Contracts with Customers (Topic 606),” an update which removes inconsistencies in existing standards, changes the way companies recognize revenue from contracts with customers, and increases disclosure requirements. The guidance requires companies to recognize revenue to depict the transfer of goods or services to customers in amounts that reflect the consideration to which the company expects to be entitled in exchange for those goods or services. In March 2016, the FASB issued guidance which provides further clarification on the principal versus agent evaluation. The guidance is effective for annual and interim periods beginning after December 15, 2017. The standard is required to be adopted using either the full retrospective approach, with all prior periods presented adjusted, or the modified retrospective approach, with a cumulative adjustment to retained earnings on the opening balance sheet. The Company is currently evaluating the level of effort needed to implement the standard, the impact of adopting this standard on its Consolidated Financial Statements, and whether to use the full retrospective approach or the modified retrospective approach.

Recently Adopted

In April 2015, the FASB issued ASU 2015-03, “Interest – Imputation of Interest (Subtopic 835-30) – Simplifying the Presentation of Debt Issuance Costs,” an update that requires debt issuance costs to be presented in the balance sheet as a direct reduction from the associated debt liability. In August 2015, the FASB subsequently issued ASU 2015-15, “Interest – Imputation of Interest (Subtopic 835-30) – Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements,” a clarification as to the handling of debt issuance costs related to line-of-credit arrangements that allows the presentation of these costs as an asset. The standards update is effective for interim and annual periods beginning after December 15, 2015. The Company has debt costs associated with its line-of-credit only; therefore, this standard had no impact on its Consolidated Financial Statements. These costs remain an asset on the Company’s Balance Sheet.

In February 2015, the FASB issued ASU 2015-02, “Consolidation (Topic 810) – Amendments to the Consolidation Analysis,” an amendment to the guidance for determining whether an entity is a variable interest entity (“VIE”). The standard does not add or remove any of the five characteristics that determine if an entity is a VIE. However, it does change the manner in which a reporting entity assesses one of the characteristics. In particular, when decision-making over the entity’s most significant activities has been outsourced, the standard changes how a reporting entity assesses if the equity holders at risk lack decision making rights. This standard is effective for the Company for annual periods beginning after December 15, 2015 and early adoption is permitted, including in interim periods. The Company adopted this standard’s update, as required, effective January 1, 2016. The adoption of this standard’s update did not have a material impact on its Consolidated Financial Statements.

NOTE 4 – FAIR VALUE MEASUREMENTS

Certain financial instruments are reported at fair value on the Consolidated Balance Sheets. Under fair value measurement accounting guidance, fair value is defined as the amount that would be received from the sale of an asset or paid for the transfer of a liability in an orderly transaction between market participants, i.e., an exit price. To estimate an exit price, a three-level hierarchy is used. The fair value hierarchy prioritizes the inputs, which refer broadly to assumptions market participants would use in pricing an asset or a liability, into three levels. The Company uses a market valuation approach based on available inputs and the following methods and assumptions to measure the fair values of its assets and liabilities, which may or may not be observable in the market.

Fair Value of Financial Instruments (other than Commodity Derivatives, see below) – The carrying values of financial instruments, excluding commodity derivatives, comprising current assets and current liabilities approximate fair values due to the short-term maturities of these instruments and are considered Level 1.

Derivatives – The fair values of the Company’s commodity derivatives are considered Level 2 as their fair values are based on third-party pricing models which utilize inputs that are either readily available in the public market, such as natural gas and oil forward curves and discount rates, or can be corroborated from active markets or broker quotes. These values are then compared to the values given by the Company’s counterparties for reasonableness. The Company is able to value the assets and liabilities based on observable market data for similar instruments, which results in the Company using market prices and implied volatility factors related to changes in the forward curves. Derivatives are also subject to the risk that counterparties will be unable to meet their obligations. Because the Company’s commodity derivative counterparty was Société Générale (“SocGen”) at June 30, 2016, the Company considered non-performance risk in the valuation of its derivatives to be minimal.

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, 2016
		Significant
	Quoted prices	other	Significant
	in active	observable	unobservable
	markets	inputs	inputs
	(Level 1)	(Level 2)	(Level 3)	Total
Assets:
Commodity derivatives – oil	$-	$1,310,008	$-	$1,310,008

Liabilities:
Commodity derivatives – gas	$-	$153,991	$-	$153,991

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

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

Debt – The Company’s debt is recorded at the carrying amount on its Consolidated Balance Sheets. For further discussion of the Company’s debt, please see Note 10 – Debt and Interest Expense. The carrying amount of floating-rate debt approximates fair value because the interest rates are variable and reflective of market rates.

Asset Retirement Obligations (“AROs”) – The Company estimates the fair value of AROs based on discounted cash flow projections using numerous estimates, assumptions and judgments regarding such factors as the existence of a legal obligation for an ARO, amounts and timing of settlements, the credit-adjusted risk-free rate to be used and inflation rates.

NOTE 5 – COMMODITY DERIVATIVE INSTRUMENTS

Objective and Strategies for Using Commodity Derivative Instruments – In order to mitigate the effect of commodity price uncertainty and enhance the predictability of cash flows relating to the marketing of the Company’s crude oil and natural gas, the Company enters into crude oil and natural gas price commodity derivative instruments with respect to a portion of the Company’s expected production. The commodity derivative instruments used include variable to fixed price commodity swaps, two-way and three-way collars.

While these instruments mitigate the cash flow risk of future reductions in commodity prices, they may also curtail benefits from future increases in commodity prices.

The Company elected to discontinue hedge accounting for all commodity derivative instruments beginning with the 2013 financial year. The balance in other comprehensive income (“OCI”) at year-end 2012 remained in accumulated other comprehensive income (“AOCI”) until the original hedged forecasted transaction occurred. The last of these contracts expired in December 2015 and the Company’s AOCI balance is now zero. No mark-to-market adjustments for commodity derivative contracts are made to AOCI, but instead are recognized in earnings. As a result of discontinuing the application of hedge accounting, the Company’s earnings are potentially more volatile. See Note 4 – Fair Value Measurements for a discussion of methods and assumptions used to estimate the fair values of the Company’s commodity derivative instruments.

Counterparty Credit Risk – Commodity derivative instruments expose the Company to counterparty credit risk. The Company’s commodity derivative instruments are with SocGen whose long-term senior unsecured debt is rated “A” by Standard and Poor’s, “A2” by Moody’s, “A” by Fitch, “A” by R&I and “A(high)” by DBRS. Commodity derivative contracts are executed under master agreements which allow the Company, in the event of default, to elect early termination of all contracts. If the Company chooses to elect early termination, all asset and liability positions would be netted and settled at the time of election.

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

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

Commodity derivative instruments open as of June 30, 2016 are provided below. Natural gas prices are New York Mercantile Exchange (“NYMEX”) Henry Hub prices, 2016 crude oil prices are Argus Light Louisiana Sweet (“LLS”), and 2017 crude oil prices are NYMEX West Texas Intermediate (“WTI”).

	2016	2017
	Settlement	Settlement
NATURAL GAS (MMBtu):
Swaps
Volume	245,068	-
Price	$2.628*	-

3-way collars
Volume	-	248,023
Ceiling sold price (call)	-	$3.280*
Floor purchased price (put)	-	$2.946*
Floor sold price (short put)	-	$2.381*

CRUDE OIL (Bbls):
Put spread
Volume	64,333	-
Floor purchased price (put)	$62.27	-
Floor sold price (short put)	$40.00	-

3-way collars
Volume	23,449	113,029
Ceiling sold price (call)	$47.15	$77.00
Floor purchased price (put)	$40.00	$60.00
Floor sold price (short put)	$30.00	$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,
	2016	2015
Asset commodity derivatives:
Current assets	$1,433,402	$3,069,115
Noncurrent assets	661,835	1,841,120
	2,095,237	4,910,235

Liability commodity derivatives:
Current liabilities	(597,200)	(411,068)
Noncurrent liabilities	(342,020)	(770,579)
	(939,220)	(1,181,647)
Total commodity derivative instruments	$1,156,017	$3,728,588

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,
	2016	2015	2016	2015

Sales of natural gas and crude oil	$3,124,424	$5,534,894	$6,056,010	$10,107,573
Gain realized from sale of commodity
derivatives	-	-	-	4,030,000
Other gains (losses) realized on
commodity derivatives	557,693	(255,049)	1,716,807	651,785
Unrealized losses on
commodity derivatives	(1,784,395)	(1,441,930)	(2,572,571)	(5,308,196)
Total revenue from natural gas and crude oil	$1,897,722	$3,837,915	$5,200,246	$9,481,162

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

	Three Months Ended		Year Ended
	June 30, 2016		December 31, 2015
	Before tax	After tax	Before tax	After tax

Balance, beginning of period	$-	$-	$63,091	$38,801
Sale of unexpired contracts previously subject
to hedge accounting rules	-	-	(119,917)	(73,749)
Other reclassifications due to expired contracts
previously subject to hedge accounting rules	-	-	56,826	34,948
Balance, end of period	$-	$-	$-	$-

NOTE 6 – ASSET IMPAIRMENTS

Oil and natural gas prices have remained low in the first and second quarters of 2016 and, as a result, the Company recognized a non-cash asset impairment charge of $11,015,589 to write down oil and gas properties for the three months ended June 30, 2016. In addition, the Company recognized a non-cash asset impairment of $4,927,508 to write off goodwill for the three months ended June 30, 2015.

Potential for Future Impairments

If commodities prices remain at or below the current low levels, subject to numerous factors and inherent limitations, and all other factors remain constant, the Company expects to incur a non-cash full cost impairment of approximately $3.0 million during the third quarter of 2016, which will have an adverse effect on the Company’s results of operations.

NOTE 7 – PREFERRED STOCK

The Company’s shares of 9.25% Series A Cumulative Redeemable Preferred Stock, no par value per share, with a liquidation preference of $25.00 per share (the “Series A Preferred Stock”), trade on the NYSE MKT under the symbol “YUMAprA”. The Series A Preferred Stock cannot be converted into common stock (except upon a change in control and in the event the Company chooses not to redeem the Series A Preferred Stock), but may be redeemed by the Company, at the Company’s option, on or after October 23, 2017 (or in certain circumstances, prior to such date as a result of a change in control of the Company), at a redemption price of $25.00 per share plus any accrued and unpaid dividends. The Series A Preferred Stock has no stated maturity, is not subject to any sinking fund or mandatory redemption, and will remain outstanding indefinitely unless repurchased, redeemed or converted into common stock in connection with a change in control. Holders of the Series A Preferred Stock are entitled to receive, when, as and if declared by the Board of Directors, cumulative dividends at the rate of 9.25% per annum (the dividend rate) based on the liquidation price of $25.00 per share of the Series A Preferred Stock, payable monthly in arrears on each dividend payment date, with the first payment date of December 1, 2014. The Series A Preferred Stock is presented in the permanent equity section of the financial statements. Due to the current depressed commodity price environment, as well as other factors which have adversely affected the Company’s cash flows and liquidity, the monthly dividends on the Series A Preferred Stock were suspended beginning with the month ended November 30, 2015. Pursuant to the Company’s credit facility, the Company is precluded from making dividend payments on its Series A Preferred Stock. The Company’s articles of incorporation provide that any unpaid dividends will accumulate. While the accumulation does not result in presentation of a liability on the balance sheet, the accumulated dividends are deducted from the Company’s net income (or added to its net loss) in the determination of income (loss) attributable to common shareholders and, as appropriate, the corresponding computation of earnings (loss) per share. As of June 30, 2016, the Company had accumulated a total of $855,003 in unpaid preferred stock dividends, attributable to the Series A Preferred Stock. If the Company does not pay dividends on its Series A Preferred Stock for six quarterly periods, whether consecutive or non-consecutive, the holders of the shares of the Series A Preferred Stock, voting together as a single class, will have the right to elect two additional directors to serve on the Company’s board of directors until all accumulated and unpaid dividends are paid in full. The Company anticipates the Series A Preferred Stock will convert into common equity as part of the merger with Davis. See Note 15 – Agreement and Plan of Merger and Reorganization for additional information.

NOTE 8 – STOCK-BASED COMPENSATION

The Yuma Co. 2011 Stock Option Plan (the “Yuma Co. Plan”) was adopted on June 21, 2011. On September 10, 2014, the shareholders of Pyramid Oil Company (“Pyramid”) (see Note 11 – Merger With Pyramid Oil Company and Goodwill), adopted the 2014 Long-Term Incentive Plan (the “2014 Plan”). Under these plans, the Board of Directors is authorized to grant stock options, stock awards (including restricted stock and restricted stock unit awards) and performance awards to officers, directors, employees and consultants. At June 30, 2016, 4,584,075 shares of the 8,900,000 shares of Yuma common stock originally authorized under active share-based compensation plans remained available for future issuance. The Company generally issues new shares to satisfy awards under employee share-based payment plans. The number of shares available is reduced by awards granted.

Restricted Stock – The Company granted restricted stock awards (“RSAs”) under the Yuma Co. Plan and the 2014 Plan. These restricted stock awards granted to officers, directors and employees generally vest in one-third increments over a three-year period, and are contingent on the recipient’s continued employment.

A summary of the status of the RSAs for employees and non-employees and changes for the period ended June 30, 2016 is presented below.

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

Unvested shares as of January 1, 2016	2,514,434	$0.87 per share
Granted	132,244	$0.21 per share
Forfeited	(132,244)	$0.73 per share
Vested	(983,804)	$0.68 per share
Unvested shares as of June 30, 2016	1,530,630	$0.95 per share

At June 30, 2016, total unrecognized RSA compensation expense of $619,658 is expected to be recognized over a weighted average remaining service period of 1.33 years.

Stock Appreciation Rights – In 2015, the Company also granted Stock Appreciation Rights (“SARs”) to employees and non-employees under the 2014 Plan. A summary of the status of these SARs and changes for the six months ended June 30, 2016 is presented below.

		Weighted
	Number of	average
	unvested	grant-date
	SARs	fair value

Unvested shares as of January 1, 2016	1,912,419	$0.30 per share
Granted	103,745	$0.03 per share
Forfeited	(103,745)	$0.32 per share
Vested	(789,117)	$0.24 per share
Unvested shares as of June 30, 2016	1,123,302	$0.32 per share

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

At June 30, 2016, total unrecognized SAR compensation expense of $214,281 is expected to be recognized over a weighted average remaining service period of 1.49 years.

The SARs in the table above have a weighted average exercise price of $0.605 and an aggregate intrinsic value of zero. The Company intends to settle these SARs in equity, as opposed to cash.

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

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

			Weighted-
		Weighted-	average
		average	remaining	Aggregate
		exercise	contractual	intrinsic
	Options	price	life (years)	value

Outstanding at December 31, 2015	105,000	$5.17	2.65	$-
Granted	-	-	-	-
Exercised	-	-	-	-
Forfeited	(5,000)	$5.40	-	-
Outstanding at June 30, 2016	100,000	$5.16	2.27	$-

Vested at June 30, 2016	100,000	$5.16	2.27	$-
Exercisable at June 30, 2016	100,000	$5.16	2.27	$-

As of June 30, 2016, there were no unvested stock options or unrecognized stock option expenses. The exercise price for all options is $5.16.

Restricted Stock Units – On April 1, 2013, the Company granted 123,446 Restricted Stock Units or “RSUs” to employees under the Yuma Co. Plan. Each RSU represented a right to receive one share of the Company’s common stock upon vesting. The awards were liability-based and the booked valuation changed as the market value for common stock changed. Of the RSUs originally granted, 43,168 were forfeited prior to vesting, and the remaining RSUs vested on April 1, 2016 and were settled in cash for $16,858.

A summary of the status of the unvested RSUs and changes during the six months ended June 30, 2016 is presented below.

		Weighted
	Number of	average
	unvested	grant-date
	RSUs	fair value

Unvested shares as of January 1, 2016	80,278	$2.72 per share
Vested on April 1, 2016	(80,278)	$2.72 per share
Unvested shares as of June 30, 2016	-

NOTE 9 – EARNINGS (LOSS) PER COMMON SHARE

Earnings (loss) per common share is computed by dividing earnings or losses attributable to common stockholders by the weighted average number of shares of common stock outstanding during the period. Potential common stock equivalents are determined using the “if converted” method.

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

	Three Months Ended		Six Months Ended
	June 30,		June 30,
	2016	2015	2016	2015

Restricted Stock Awards	2,041,498	640,499	2,239,594	1,271,916
Restricted Stock Units	-	95,424	-	95,424
	2,041,498	735,923	2,239,594	1,367,340

For the three months ended June 30, 2016 and the three months ended June 30, 2015, adjusted earnings were losses, therefore common stock equivalents were excluded from the calculation of diluted net loss per share of common stock, as their effect was anti-dilutive. RSUs were settled in cash during April 2016 and are no longer considered potentially dilutive.

NOTE 10 – DEBT AND INTEREST EXPENSE

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

On December 30, 2015, Exploration entered into the Ninth Amendment pursuant to which Exploration agreed that on or before February 6, 2016, it would engage an investment bank to explore strategic options for its finances and, on or before March 31, 2016, would either enter into an underwritten commitment for additional capital in an aggregate amount sufficient to pay any borrowing base deficiency then existing or enter into a definitive agreement for the acquisition by a third party of all or substantially all of the assets of Exploration and its subsidiaries by merger, asset purchase, equity purchase or other structure acceptable to SocGen and the lenders. On February 10, 2016, the Company entered into the merger agreement with Davis (see Note 15 – Agreement and Plan of Merger and Reorganization).

On June 6, 2016 and effective as of May 31, 2016, Exploration entered into the Tenth Amendment which maintains the borrowing base at $29.8 million and automatically reduces the borrowing base to $20.0 million on the occurrence of a Tenth Amendment Termination Date.

Costs and fees paid to the banks in connection with the revolving credit facility were amortized through May 31, 2016, due to the possible accelerated maturity date pursuant to the Ninth Amendment.

Additional loan costs incurred during the second quarter of 2016 were $50,334, and are being amortized to August 15, 2016. SocGen, as Agent Bank, is also paid an annual administrative fee of $25,000 that is usually amortized over the year, but was also amortized through May 31, 2016.

The terms of the credit agreement require the Company to meet a specific current ratio, interest coverage ratio, and a funded debt to EBITDA ratio. The credit agreement also contains a covenant requiring ten percent availability under the current borrowing line in order to pay dividends on the Series A Preferred Stock. In addition, the credit agreement requires the guarantee of the Company. The Company was not in compliance with the loan covenants as of March 31, 2016; however, the Tenth Amendment provided a waiver of those violations until the occurrence of a Tenth Amendment Termination Date.

The Company was not in compliance with the funded debt to EBITDA, EBITDA to interest expense and current ratio covenants as of June 30, 2016. Accordingly, the Company anticipates working with its lenders to obtain an extension of its waivers until the closing of the merger. In the event that the Company does not obtain an extension or waiver of the violations, then the Company’s outstanding indebtedness would become immediately due and payable.

The following summarizes interest expense for the three and six months ended June 30, 2016 and 2015.

	Three Months Ended		Six Months Ended
	June 30,		June 30,
	2016	2015	2016	2015

Credit agreement	$259,649	$280,113	$517,377	$521,407
Credit agreement commitment fees	-	9,331	-	25,159
Amortization of
credit agreement loan costs	195,516	71,613	457,990	136,757
Insurance installment loan	291	3,471	1,961	5,197
Other interest charges	89	186	5,029	1,023
Capitalized interest	(129,149)	(250,336)	(253,313)	(483,158)
Total interest expense	$326,396	$114,378	$729,044	$206,385

NOTE 11 – MERGER WITH PYRAMID OIL COMPANY AND GOODWILL

On September 10, 2014, a wholly owned subsidiary of Pyramid merged with and into Yuma Energy, Inc., a Delaware corporation (“Yuma Co.”), in exchange for 66,336,701 shares of common stock and Pyramid changed its name to “Yuma Energy, Inc.” (the “merger”). As a result of the merger, the former Yuma Co. stockholders received approximately 93% of the then outstanding common stock of the Company and thus acquired voting control. Although the Company was the legal acquirer, for financial reporting purposes the merger was accounted for as a reverse acquisition of Pyramid by Yuma Co. The transaction qualified as a tax-deferred reorganization under Section 368(a) of the Internal Revenue Code of 1986, as amended (the “Code”).

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

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

NOTE 12 – INCOME TAXES

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

	Three Months Ended		Six Months Ended
	June 30,		June 30,
	2016	2015	2016	2015
Consolidated net income (loss)
before income taxes	$(15,766,990)	$(11,190,584)	$(19,973,009)	$(17,168,158)
Income tax expense (benefit)	(692,302)	(1,640,910)	(1,225,235)	(3,935,492)
Effective tax rate	4.4%	14.7%	6.1%	22.9%

The differences between the U.S. federal statutory rate of 34% and the Company’s effective tax rates for the three and six months ended June 30, 2016 and 2015 are due primarily to state taxes and nondeductible expenses. In addition, June 30, 2016 was impacted by the expected valuation allowance on our deferred tax asset at year-end, which affected our expected annual effective tax rate and the tax effect of nondeductible stock compensation.

The Company knows of no uncertain tax positions and has no unrecognized tax benefits for the six months ended June 30, 2016 or June 30, 2015. Valuation allowances are established when the Company determines it is more likely than not that some portion, or all, of the deferred tax assets will not be realized. As of June 30, 2016, the Company anticipates that it will have a net deferred tax asset at year-end 2016, for which a valuation allowance will be required. The Company has considered the effect of the valuation allowance in the current period in determining its expected annual effective tax rate to record tax expense for the period ending June 30, 2016. No valuation allowance was established as of June 30, 2015.

NOTE 13 – AT MARKET SECURITY SALES

The Company entered into an At Market Issuance Sales Agreement (“Sales Agreement”) with an investment banking firm (the “Agent”) on December 19, 2014. Under the Sales Agreement, the Company was able to 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, 2016, the Company sold the following securities for the net proceeds listed below (the Company has made no sales of securities since the second quarter of 2015). The Company may not sell any securities under the Sales Agreement pursuant to the merger agreement with Davis.

	Shares	Net Proceeds

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

NOTE 14 – CONTINGENCIES

Certain Legal Proceedings

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

Amanda Olivier, et al. v. Nabors Drilling USA, L.P., and Yuma Exploration and Production, Inc.

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

Ontiveros v. Pyramid Oil, LLC, Yuma Energy, Inc. et al.

In September 2015, a suit was filed against the Company and Pyramid Oil LLC styled Mark A. Ontiveros and Louise D. Ontiveros, Trustees of The Ontiveros Family Trust dated March 29, 2007 vs. Pyramid Oil, LLC, et al., Case Number 15CV02959 in the Superior Court of California, County of Santa Barbara, Cook Division. In the suit, the plaintiffs allege that the 1950 Community Oil and Gas Lease between them and Pyramid Oil LLC has expired by non-production. The Company claims that the lease is still in effect, as there is no cessation of production time frame set out in the lease; production had temporarily ceased, but was still profitable when measured over an appropriate time period; and the Company was conducting workover operations on a well on the lease in an effort to re-establish production when served with the quit claim deed demand from the plaintiff’s attorney. All present owners of the minerals covered by the 1950 Community Oil and Gas Lease, with the exception of the plaintiffs, have executed amendments signifying their concurrence that the 1950 Community Oil and Gas Lease is still in force and effect. On June 23, 2016, Pyramid Oil LLC filed a First Amended Cross Complaint against Texican Energy Corporation and Everett Lawley alleging interference with contractual relations and prospective economic relations, and violation of the California Uniform Trade Secrets Act. The parties are presently in the process of document discovery. Management intends to defend the plaintiffs’ claims and pursue the cross claim vigorously.

Yuma Energy, Inc. v. Cardno PPI Technology Services, LLC Arbitration

On May 20, 2015, counsel for Cardno PPI Technology Services, LLC (“Cardno PPI”) sent a notice of the filing of liens totaling $304,209 on the Company’s Crosby 14 No. 1 Well and Crosby 14 SWD No. 1 Well in Vernon Parish, Louisiana. The Company disputed the validity of the liens and of the underlying invoices, and notified Cardno PPI that applicable credits had not been applied. The Company invoked mediation on August 11, 2015 on the issues of the validity of the liens, the amount due pursuant to terms of the parties’ Master Service Agreement (“MSA”), and PPI Cardno’s breaches of the MSA. Mediation was held on April 12, 2016; no settlement was reached.

On May 12, 2016, Cardno filed a lawsuit in Louisiana state court to enforce the liens; the Court entered an Order Staying Proceeding on June 13, 2016, ordering that the lawsuit “be stayed pending mediation/arbitration between the parties.” On June 17, 2016, the Company served a Notice of Arbitration on Cardno PPI, stating claims for breach of the MSA billing and warranty provisions. On July 15, 2016, Cardno PPI served a Counterclaim for $304,209 plus attorneys’ fees. The parties are currently engaged in the arbitrator selection process. Management intends to pursue the Company’s claims and to defend the counterclaim vigorously.

Environmental Remediation Contingencies

As of June 30, 2016, there were no known environmental or other regulatory matters related to the Company’s operations that were reasonably expected to result in a material liability to the Company. The Company’s operations are subject to numerous laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection.

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

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

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

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

The Company tendered its defense to its liability insurance carriers, who are responding. On February 13, 2015, the federal judge adjudicating the matter granted defendants “Joint Motion to Dismiss for Failure to State a Claim Under Rule 12(b)(6)”, thereby dismissing plaintiff’s claims with prejudice in the matter. On February 20, 2015, the Board of Orleans filed a notice of appeal to the U.S. Fifth Circuit. On February 29, 2016, oral arguments were held regarding the appeal, but as of July 31, 2016, no ruling on the appeal has been made. The Company will continue to contest plaintiff’s legal arguments and factual assertions. At this point in the legal process, no evaluation of the likelihood of an unfavorable outcome or associated economic loss can be made; therefore no liability has been recorded on the Company’s books.

Escheat Audits

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

NOTE 15 – AGREEMENT AND PLAN OF MERGER AND REORGANIZATION

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

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

On June 17, 2016, Yuma Delaware Merger Subsidiary, Inc., a Delaware corporation and wholly-owned subsidiary of the Company (“Yuma Delaware”), filed a Registration Statement on Form S-4 (“Form S-4”) with the SEC to effectuate (i) the proposed reincorporation of the Company from California to Delaware through the merger of the Company with and into Yuma Delaware (the “reincorporation”), and (ii) the proposed merger of Yuma Merger Subsidiary, Inc., a Delaware corporation and wholly-owned subsidiary of Yuma Delaware (“Merger Subsidiary”), with and into Davis, with Davis becoming a wholly-owned subsidiary of Yuma Delaware (the “Davis merger”). In order to complete the Davis merger, the Company’s holders of common stock and preferred stock must vote to approve and adopt the reincorporation and the merger.

NOTE 16 – GREATER MASTERS CREEK FIELD AREA

During the first quarter of 2016, the Company shut-in 14 Austin Chalk wells in Beauregard, Rapides and Vernon Parishes, Louisiana due to low oil and natural gas prices. Since production was not restarted from these wells, the associated leases have expired, reducing the Company’s proved reserves from year-end 2015 by approximately 1,629 MBoe, acreage by 22,021 gross (18,140 net) acres, operated proved undeveloped locations by three, and operated non-proved undeveloped locations by seven.

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

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

On April 4, 2016, the Company entered into an amendment effective March 1, 2016 to an oil and gas lease in the Greater Masters Creek Field area with a certain mineral owner for acreage that was not held by production as of March 31, 2016. The total acreage is approximately 25,139 acres and, by virtue of the Company conducting certain location clean-up operations, the lease has now been extended until December 31, 2016. This extension is subject to certain additional performance criteria, including the posting of a bond to cover P&A costs for wells located on this mineral owner’s property, or plugging and abandoning six of the mineral owner’s wells by December 31, 2016 at an estimated net cost of $426,000. If the leased acreage expires, the Company’s proved reserves from year-end 2015 would be reduced by approximately 5,096 MBoe, the number of operated proved undeveloped locations and operated non-proved locations would be reduced by 13 and 16, respectively.

NOTE 17 – TEXAS SOUTHEASTERN GAS MARKETING COMPANY

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

NOTE 18 – SUBSEQUENT EVENTS

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.

Amendment to Form S-4

On August 4, 2016, Yuma Delaware filed Amendment No. 1 to the Form S-4 with the SEC in connection with the proposed reincorporation of the Company from California to Delaware and the proposed merger with Davis.

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

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

Cautionary Statement Regarding Forward-Looking Statements

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

●

our ability to repay outstanding loans when due;

●

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

●

reductions in the borrowing base under our credit facility;

●

our ability to complete the merger with Davis Petroleum Acquisition Corp.;

●

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

●

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

●

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

●

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

●

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

●

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

●

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

●

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

●

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

●

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

●

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

●

our ability to replace our oil and natural gas reserves;

●

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

●

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

●

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

●

environmental risks;

●

drilling and operating risks;

●

exploration and development risks;

●

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

●

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

●

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

●

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

●

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

●

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

●

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

●

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

●

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

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

Overview

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

Recent Developments

The prices of crude oil and natural gas have declined dramatically since mid-year 2014, having recently reached multiyear lows during the first quarter of 2016, as a result of robust supply growth, weakening demand in emerging markets, and OPEC’s decision to continue to produce at current levels. These market dynamics have led many to conclude that commodity prices are likely to remain lower for a prolonged period. In response to these developments, among other things, we have reduced our spending and plan to enter into a merger with Davis Petroleum Acquisition Corp. to increase our liquidity and improve our financial position (see Item 1. Unaudited Condensed Notes to the Consolidated Financial Statements, Note 15 – Agreement and Plan of Merger and Reorganization). In addition, we are continuing to actively explore and evaluate various strategic alternatives, including asset sales, to reduce the level of our debt and lower our future cash interest obligations. We believe that a reduction in our debt and cash interest obligations on a per barrel basis is needed to improve our financial position and flexibility and to position us to take advantage of opportunities that may arise out of the current industry downturn.

Full Cost Ceiling Test Impairment

Oil and natural gas prices have remained low in the first and second quarters of 2016 and, as a result, we recognized an $11.0 million non-cash asset impairment in the second quarter of 2016 which has negatively impacted our results of operations and equity. If prices remain at or below the current low levels, subject to numerous factors and inherent limitations, and all other factors remain constant, we expect to incur a non-cash full cost impairment of approximately $3.0 million during the third quarter of 2016, which will have an adverse effect on our results of operations.

There are numerous uncertainties inherent in the estimation of proved reserves and accounting for oil and natural gas properties in future periods. Our estimated third-quarter 2016 full cost ceiling calculation has been prepared by substituting (i) $41.73 per barrel for oil, and (ii) $2.24 per MMBtu for natural gas for the expected realized prices as of September 30, 2016. The forecasted average realized price was based on the average realized price for sales of crude oil, natural gas liquids and natural gas on the first calendar day of each month for the first 11 months and an estimate for the twelfth month based on a quoted forward price. Changes to our reserves and future production were made due to changing the effective date of the evaluation from June 30, 2016 to September 30, 2016. All other inputs and assumptions have been held constant. Accordingly, this estimate accounts for the impact of more current commodity prices in the third quarter of 2016 utilized in our full cost ceiling calculation.

Agreement and Plan of Merger and Reorganization

On February 10, 2016, the Company and privately held Davis Petroleum Acquisition Corp. (“Davis”) entered into a definitive merger agreement (the “merger agreement”) for an all-stock transaction. Upon completion of the transaction, we will reincorporate in Delaware, implement a one-for-ten reverse split of our common stock, and convert each share of our existing Series A Preferred Stock into 35 shares of common stock prior to giving effect for the reverse split (3.5 shares post reverse split). Following these actions, we will issue additional shares of common stock in an amount sufficient to result in approximately 61.1% of the common stock being owned by the current common stockholders of Davis, with an expected aggregate of approximately 23.7 million shares of our common stock then outstanding. In addition, we will issue approximately 3.3 million shares of a new Series D preferred stock to existing Davis preferred stockholders, which is estimated to have a conversion price of approximately $5.70 per share, after giving effect for the reverse split. The Series D preferred stock is estimated to have an aggregate liquidation preference of approximately $19.0 million at closing, and will be paid dividends in the form of additional shares of Series D preferred stock at a rate of 7% per annum. The transaction is expected to qualify as a tax-deferred reorganization under Section 368(a) of the Internal Revenue Code of 1986, as amended (the “Code”).

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

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

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

Critical Accounting Policies

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

Market Conditions

Prevailing prices for the crude oil, natural gas and natural gas liquids (“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 2016 compared to the same period in 2015; as a result, we experienced significant declines in our price realizations associated with those benchmarks. Additional detail on market conditions, including our average price realizations and benchmarks for crude oil, natural gas and NGLs relative to our operating segments, follows.

Liquidity Considerations

As discussed in Item 1. Unaudited Condensed Notes to the Consolidated Financial Statements, Note 2 – Liquidity Considerations and Going Concern, our credit agreement requires, among other things, compliance with certain financial ratios. Because of the current weak commodity price environment, we have sustained losses during recent quarters. As a result, we were not in compliance with the ratio of funded debt to EBITDA and the EBITDA to interest expense ratio under our senior credit facility at March 31, 2016 and we were not in compliance with these ratios as well as the current assets to current liabilities ratio as of June 30, 2016. On June 6, 2016 and effective as of May 31, 2016, we entered into the Waiver and Tenth Amendment to our credit agreement (the “Tenth Amendment”), which maintains our borrowing base at $29.8 million and automatically reduces our borrowing base to $20.0 million on the earliest of (each a “Tenth Amendment Termination Date”) (i) August 15, 2016, if the registration statement on Form S-4 (the “Form S-4”) filed with the SEC pursuant to the pending merger agreement has not been declared effective by such date; (ii) the date that is forty-seven days after the date the Form S-4 has been declared effective by the SEC; (iii) September 30, 2016; and (iv) in the event of the termination of the merger agreement. In the event that the SEC does not declare the Form S-4 effective by August 15, 2016, we expect to enter into discussions with our lenders participating in our revolving credit facility, and enter into a new amendment to the credit facility that will extend the waiver of these breaches until the closing of the merger. In the event that the lenders do not enter into a new amendment with us, then our outstanding indebtedness would be immediately due and payable.

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

During 2015, we initiated several strategic alternatives to remedy our debt covenant compliance issues and provide working capital to develop our existing assets. On February 10, 2016, we entered into the merger agreement. Upon completion of the transaction, which is subject to the approval of the stockholders of both companies and other conditions, Davis will become our wholly owned subsidiary. Subject to bank approval, it is anticipated that we will enter into another credit agreement amendment that will take into account the contemplated merger with Davis (see Item 1. Unaudited Condensed Notes to the Consolidated Financial Statements, Note 15 – Agreement and Plan of Merger and Reorganization), or enter into a new credit facility that will put us into compliance. However, our management can provide no assurance that the merger with Davis and the amendment to the credit agreement will actually occur.

Sales and Other Operating Revenues

The following table presents the net quantities of crude oil, natural gas and NGLs produced and sold by us for the three and six months ended June 30, 2016 and 2015, and the average sales price per unit sold.

	Three Months Ended June 30,		Six Months Ended June 30,
	2016	2015	2016	2015
Production volumes:
Crude oil and condensate (Bbl)	50,458	60,956	108,907	124,592
Natural gas (Mcf)	346,219	500,404	808,398	990,540
Natural gas liquids (Bbl)	12,979	17,767	29,158	33,939
Total (Boe) (1)	121,140	162,124	272,798	323,621

Average prices realized:
Excluding commodity derivatives:
Crude oil and condensate (per Bbl)	$41.85	$59.22	$35.36	$52.72
Natural gas (per Mcf)	$2.14	$2.85	$2.09	$2.80
Natural gas liquids (per Bbl)	$20.89	$22.71	$17.62	$19.57
Including commodity derivatives:
Crude oil and condensate (per Bbl)	$22.25	$52.00	$27.83	$73.62
Natural gas (per Mcf)	$1.46	$3.23	$2.05	$4.89
Natural gas liquids (per Bbl)	$20.89	$22.71	$17.62	$19.57

(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, 2016 and 2015.

	Three Months Ended June 30,		Six Months Ended June 30,
	2016	2015	2016	2015
Sales of natural gas and crude oil:
Crude oil and condensate	$2,111,468	$3,609,719	$3,850,862	$6,567,989
Natural gas	741,783	1,429,114	1,691,446	2,771,188
Natural gas liquids	271,173	403,544	513,702	664,110
Realized gain (loss) on commodity derivatives	557,693	(255,049)	1,716,807	4,681,785
Unrealized loss on commodity derivatives	(1,784,395)	(1,441,930)	(2,572,571)	(5,308,196)
Gas marketing sales	-	92,517	-	104,286

Total revenues	$1,897,722	$3,837,915	$5,200,246	$9,481,162

Sale of Crude Oil and Condensate

Crude oil and condensate are sold through month-to-month evergreen contracts. The price for Louisiana production is tied to an index or a weighted monthly average of posted prices with certain adjustments for gravity, Basic Sediment and Water (“BS&W”) and transportation. Generally, the index or posting is based on West Texas Intermediate (“WTI”) and adjusted to Light Louisiana Sweet (“LLS”) or Heavy Louisiana Sweet (“HLS”). Pricing for our California properties is based on an average of specified posted prices, adjusted for gravity, transportation, and for one field, a market differential.

Crude oil volumes sold were 17.2% lower for the three months ended June 30, 2016 than the crude oil volumes sold during the same period in 2015. This decrease was a result of reduced production levels at Bayou Hebert field while restoring salt water disposal capacity, continuing high levels of downtime in Main Pass 2 due to facility restrictions, and shutting in the Talbot 23-1. Production in Bayou Hebert field has been restored to previous levels and, although Main Pass 2 continues to produce at reduced levels, we anticipate restoring production to previous levels during the fourth quarter of 2016 once facility upgrades are made. The Talbot 23-1 well has been recompleted to the Marg Tex 1 zone and is anticipated to be placed back on production early in the third quarter of 2016. Realized crude oil prices decreased 29.3% from the three months ended June 30, 2015 compared to the three months ended June 30, 2016.

For the six months ended June 30, 2016, crude oil volumes sold were 12.6% lower than the same period in 2015. This decrease was the result of shut-in wells in both operated and non-operated wells in the Greater Masters Creek Field and the reasons listed above for the three months ended June 30, 2016. It is not anticipated that production will be restored from the operated and non-operated Greater Masters Creek Field wells due to low commodity prices. Realized crude oil prices were 32.9% lower for the six months ended June 30, 2016 compared to the same period in 2015.

Sale of Natural Gas and Natural Gas Liquids

Our natural gas is sold under multi-year contracts with pricing tied to either first of the month index or a monthly weighted average of purchaser prices received. NGLs 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, 2016 compared to the same period in 2015, we experienced a 30.8% decrease in natural gas volumes sold and a 26.9% decrease in NGLs sold primarily due to reduced production levels at Bayou Hebert field while restoring salt water disposal capacity and shutting in the Talbot 23-1. Production in Bayou Hebert field has been restored to previous levels and the Talbot 23-1 well has been recompleted to the Marg Tex 1 zone and is anticipated to be placed back on production early in the third quarter of 2016. During the same period, realized natural gas prices decreased by 24.9% and realized prices for NGLs decreased by 8.0%.

For the six months ended June 30, 2016, natural gas volumes sold decreased by 18.4% and volumes of NGLs sold decreased by 14.1% compared to the same period in 2015. This decrease was due primarily to the reasons stated above for the three months ended June 30, 2016 and natural declines in production from other gas wells. During the same period, realized natural gas prices decreased by 25.4% and realized prices for NGLs decreased by 10.0%.

Gas Marketing

Gas marketing sales are natural gas volumes purchased from certain of our operated wells and the aggregated volumes sold with a mark-up of $.03 per MMBtu. Our wholly owned subsidiary, Texas Southeastern Gas Marketing Company (“Marketing”), purchased and sold natural gas on our behalf and on behalf of our working interest partners. In early 2016, we discontinued Marketing due to a lack of volumes and the associated costs of running the company (see Item 1. Unaudited Condensed Notes to the Consolidated Financial Statements, Note 17 – Texas Southeastern Gas Marketing Company).

Lease Operating Expenses

Our lease operating expenses (“LOE”) and LOE per Boe for the three and six months ended June 30, 2016 and 2015, are set forth below:

	Three Months Ended June 30,		Six Months Ended June 30,
	2016	2015	2016	2015
Lease operating expenses	$1,248,620	$2,176,641	$2,579,367	$4,438,169
Severance, ad valorem taxes and marketing	631,440	1,049,584	1,313,842	2,011,172
Total LOE	$1,880,060	$3,226,225	$3,893,209	$6,449,341

LOE per Boe	$15.52	$19.90	$14.27	$19.93
LOE per Boe without severance, ad valorem taxes and marketing	$10.31	$13.43	$9.46	$13.71

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.

The 41.7% decrease in total LOE for the three months ended June 30, 2016 compared to the same period in 2015 was primarily due to our continued operating cost reduction initiatives implemented in our Greater Masters Creek Field, Main Pass 2 and 4, and California. LOE per Boe decreased by 22.0% for the same period generally due to enhancement projects that kept production stable and the cost reduction programs mentioned above.

For the six months ended June 30, 2016, total LOE decreased by 39.6% compared to the same period in 2015, due primarily to the reasons state above for the three months ended June 30, 2016 which led to a decrease in LOE per Boe of 28.4% for the same period.

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, 2016 and 2015 totaled $0 and $60,063, respectively. Workover expenses were incurred in the second quarter of 2015 to finish installing artificial lift in Livingston Field. All the 2015 re-engineered facilities upgrades and artificial lift optimization projects in our operated fields led to fewer workovers, down time, and fewer non-reoccurring operations overall. LOE per Boe, including re-engineering and workovers, for the three months ended June 30, 2016 and 2015 totaled $15.52 and $20.27, respectively, a 23.4% decrease.

For the six months ended June 30, 2016 and 2015, workover expenses totaled $0 and $554,492, respectively. High workover expenses were incurred in the first half of 2015 to restore facilities and salt water disposal at Main Pass 4 and artificial lift in Livingston Field. LOE per Boe, including re-engineering and workovers, for the six months ended June 30, 2016 and 2015 totaled $14.27 and $21.64, respectively, a 34.1% decrease.

General and Administrative Expenses

Our general and administrative (“G&A”) expenses for the three and six months ended June 30, 2016 and 2015 are summarized as follows:

	Three Months Ended June 30,		Six Months Ended June 30,
	2016	2015	2016	2015
General and administrative
Stock-based compensation	$315,715	$160,498	$746,567	$2,573,240
Capitalized stock-based compensation	13,907	26,577	26,469	700,909
Net stock-based compensation	301,808	133,921	720,098	1,872,331

Other G&A	2,413,411	2,473,362	5,019,111	4,787,278
Capitalized other G&A	409,692	629,199	857,906	1,270,903
Net other G&A	2,003,719	1,844,163	4,161,205	3,516,375

Net general and administrative	$2,305,527	$1,978,084	$4,881,303	$5,388,706

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

For the three months ended June 30, 2016, G&A expenses inclusive of amounts capitalized were $95,266 (3.6%) higher than the amount for the same period in 2015. This increase in G&A expenses was primarily attributed to $351,730 in non-recurring professional costs associated with the Davis merger during 2016. Additional variances for the three months ended June 30, 2016 compared to the same period in 2015 include a $219,474 increase in audit and accounting fees due to the restatement of our 2015 financial statements, offset by a $178,560 decrease in salary expenses due to a 25.6% staff reduction, and a $362,340 decrease in consulting fees.

For the six months ended June 30, 2016, G&A expenses inclusive of amounts capitalized were $1,594,840 (21.7%) lower than the same period in 2015. Costs for the Davis merger of $831,677 increased G&A costs for the current six-month period; however, this increase was offset by a $1,683,022 decrease in stock-based compensation, a $305,894 decrease in salaries due to staff reductions, and a $284,958 decrease in consulting fees.

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, 2016 and 2015 is summarized as follows:

	Three Months Ended June 30,		Six Months Ended June 30,
	2016	2015	2016	2015
Depreciation, Depletion and Amortization	$2,020,804	$3,755,446	$4,467,205	$7,896,466

DD&A per Boe	$16.68	$23.16	$16.38	$24.40

DD&A per Boe decreased by 28.0% and 32.9% for the three and six months ended June 30, 2016 compared to the same periods in 2015. Decreases in 2016 production compared to 2015 caused corresponding decreases to depletion (see preceding Sales discussion for production detail). In addition, future development costs, a component of the depletion base, are down from the June 30, 2015 projection. Depressed commodity prices are the primary cause for the reduction in projected future development costs.

Interest Expense

Our interest expense for the three and six months ended June 30, 2016 and 2015 is summarized as follows:

	Three Months Ended June 30,		Six Months Ended June 30,
	2016	2015	2016	2015
Interest expense	$455,545	$364,714	$982,357	$689,543
Interest capitalized	(129,149)	(250,336)	(253,313)	(483,158)
Net	$326,396	$114,378	$729,044	$206,385

Bank debt	$29,800,000	$29,900,000	$29,800,000	$29,900,000

Gross interest expense increased $90,831 and $292,814 for the three and six months ended June 30, 2016 over the same periods in 2015 due to the increased amortization of debt costs related to the acceleration of the maturity dates under our credit facility pursuant to the Ninth and Tenth Amendments. Capitalized interest decreased $121,187 and $229,845 for the three and six months ended June 30, 2016 from the same periods in 2015, driven by a decrease in our unevaluated properties since 2014, which is the basis of our capitalized interest calculation.

Income Tax Expense

We recorded an income tax benefit of $692,302 on a pre-tax net loss of $15,766,990 resulting in an effective tax rate of 6.1% for the six months ended June 30, 2016. For the six months ended June 30, 2015, we recorded an income tax benefit of $3,935,492 on a pre-tax loss of $17,168,158, resulting in an effective tax rate of 22.9%.

Differences between the U.S. federal statutory rate of 34% and our effective tax rates are due primarily to state taxes and nondeductible expenses. In addition, June 30, 2016 was impacted by the expected valuation allowance on our deferred tax asset at year-end, which affected our expected annual effective tax rate and the tax effect of nondeductible stock compensation.

Liquidity and Capital Resources

Cash Flows

The change in our cash for the six months ended June 30, 2016 and 2015 is summarized as follows:

	Six Months Ended June 30,
	2016	2015
Cash flows provided by (used in) operating activities	$(985,396)	$(3,401,231)
Cash flows used in investing activities	(1,871,931)	(8,099,724)
Cash flows provided by (used in) financing activities	(404,867)	8,225,636
Net increase (decrease) in cash	$(3,262,194)	$(3,275,319)

Cash Flows from Operating Activities

Cash flows from operations for the six months ended June 30, 2016 increased by $2,415,835, or 71.0%, over the same period in 2015 primarily due to changes in working capital and decreases in lease operating and G&A expenses, somewhat offset by lower revenue from decreased production and lower commodity prices as mentioned earlier.

Cash Flows from Investing Activities

Oil and natural gas investing activities decreased by $6,227,793 or 76.9% in the six months ended June 30, 2016 compared to the same period in 2015. The decrease was primarily due to a reduction in capital expenditures in 2016 compared to 2015.

During the six months ended June 30, 2016, we invested $1,873,671 in lease acquisition costs and capital expenditures related to a recompletion, workovers, P&A activity and software. Lease acquisition costs primarily included capitalized G&A and capitalized interest associated with the North Austin Chalk seismic and Cat Canyon prospects. Notable projects include the DS&B 121 well recompletion for a cost of $166,787 and P&A costs on the Crosby 29 #1 SWD well of $52,358, as well as the removal of various Greater Masters Creek Field facilities totaling $93,560. Software investment totaled $37,440 for additional accounting system modules and an accounts payable workflow system that enhanced controls and efficiency.

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 well 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.

Cash Flows from Financing Activities

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

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

At June 30, 2016, we had a $29.8 million borrowing base with $29.8 million advanced, leaving no available borrowing capacity. See Credit Facility section below.

	Six Months Ended June 30, 2016	Year EndedDecember 31, 2015
Credit Facility:
Balances outstanding, beginning of year	$29,800,000	$22,900,000
Activity	-	6,900,000
Balances outstanding, end of period	$29,800,000	$29,800,000

Other than the credit facility, we had debt of -0- and $263,635 at June 30, 2016 and December 31, 2015, respectively, from installment loans financing oil and natural gas property insurance premiums. We had a cash balance of $2,092,997 at June 30, 2016.

Credit Facility

We have a credit facility with a syndicate of banks that, as of June 30, 2016, had a borrowing base of $29.8 million, with borrowings of $29.8 million outstanding. The credit agreement governing our credit facility provides for interest-only payments until the credit agreement matures and any outstanding borrowings are due. The borrowing base under our credit agreement is subject to regular redeterminations in the spring and fall of each year, as well as special redeterminations described in the credit agreement, in each case which may reduce the amount of the borrowing base. On June 6, 2016 and effective as of May 31, 2016, we entered into the Tenth Amendment, which maintains the borrowing base at $29.8 million and automatically reduces the borrowing base to $20.0 million on the earliest of (i) August 15, 2016, if the registration statement on Form S-4 filed with the SEC pursuant to the merger agreement has not been declared effective by such date; (ii) the date that is forty-seven days after the date the registration statement has been declared effective by the SEC; (iii) September 30, 2016; and (iv) in the event of the termination of the merger agreement.

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

Our obligations under the credit agreement are guaranteed by our subsidiaries and are secured by liens on substantially all of our assets, including a mortgage lien on oil and natural gas properties having at least 98% of the proved developed reserve value and at least 60% of the proved undeveloped reserve value of the oil and natural gas properties included in the determination of the borrowing base.

Amounts borrowed under the credit agreement bear interest at either (a) the LIBOR rate plus 2.25% to 3.75% or (b) the prime rate plus 1.25% to 2.75%, depending on the amount borrowed under the credit facility. The credit facility contains a number of covenants that, among other things, restrict, subject to certain exceptions, our ability to incur additional indebtedness, create liens on assets, sell certain assets and engage in certain transactions with affiliates. Additionally, the credit agreement contains a covenant restricting the payment of dividends on preferred stock if there is less than ten percent availability on the borrowing base. See Part I, Item 1. Notes to the Consolidated Financial Statements, Note 2 – Liquidity Considerations and Going Concern, and Note 10 – Debt and Interest Expense.

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

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

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, 2016		December 31, 2015
	Oil	Gas	Oil	Gas
Assets
Current	$980,189	$-	$2,393,032	$265,015
Noncurrent	329,819	-	1,049,661	20,880

Liabilities
Current	$-	$(143,987)	$-	$-
Noncurrent	-	(10,004)	-	-

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

The fair market value of our commodity derivative contracts in place at June 30, 2016 and December 31, 2015 were net assets of $1,156,017 and $3,728,588, respectively. Please see Item 1. Unaudited Condensed Notes to the Consolidated Financial Statements, Note 5 – Commodity Derivative Instruments, for additional information on our commodity derivatives.

Commitments and Contingencies

We had the following contractual obligations and commitments as of June 30, 2016:

	Debt (1)	Commodity Derivatives (2)	Operating Leases	Asset Retirement Obligations
2016	$29,800,000	$475,306	$290,855	$435,936
2017	-	680,711	564,732	294,592
2018	-	-	2,264	3,672,829
2019	-	-	-	2,140,498
2020	-	-	-	155,730
Thereafter	-	-	-	2,205,366
Totals	$29,800,000	$1,156,017	$857,851	$8,904,951

(1)

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

(2)

Represents the estimated future receipts under our oil and natural gas derivative contracts based on the future market prices as of June 30, 2016. These amounts will change as oil and natural gas commodity prices change.

Off Balance Sheet Arrangements

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

Item 3. Quantitative and Qualitative Disclosures about Market Risk.

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

Item 4. Controls and Procedures.

Evaluation of disclosure controls and procedures.

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

As of June 30, 2016, we carried out an evaluation, under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)). Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were not effective as of June 30, 2016. Specifically, we did not have appropriate policies and procedures in place to properly evaluate the accuracy of certain of our financial accounts as more particularly described in our annual report on Form 10-K/A filed with the SEC on May 23, 2016.

Changes in internal control over financial reporting.

During the three month period ended June 30, 2016, there were no changes in our internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)), except for the changes described in the Remedial Action section below, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Remedial Action

We began our remediation plan with respect to improving our internal control over financial reporting to address the material weakness(es) that were disclosed in our annual report on Form 10-K/A filed with the SEC on May 23, 2016. Specifically as it relates to the presentation and accounting for our income taxes, in the three-month period ended June 30, 2016, we hired an internationally known accounting firm as our new tax consultants to assist management with its preparation of these items, and intend to hire additional accounting personnel in the third or fourth quarter of 2016. Additionally, we are in the process of implementing a more robust review, and increasing the supervision and monitoring of the financial reporting processes related to the preparation of our income tax provisions. We implemented these procedures in the second quarter of 2016, but believe that we require sufficient testing of these newly established procedures and controls prior to declaring that we have effective disclosure controls and procedures.

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 14 – Contingencies, and is incorporated herein by reference.

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

Item 1A. Risk Factors.

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

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

The following table sets forth information regarding our acquisition of shares of common stock for the periods presented.

	Total Number of Shares Purchased(1)	Average Price Paid Per Share	Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Maximum Number (or Approximate Dollar Value) of Shares that May Yet Be Purchased Under the Plans or Programs
April 2016	43,178	$0.21	-	-
May 2016	231,190	$0.26	-	-
June 2016	-	-	-	-

(1) All of the shares were surrendered by employees in satisfaction of tax obligations upon the vesting of restricted stock awards. The acquisition of the surrendered shares was not part of a publicly announced program to repurchase shares of our common stock, nor were they considered as or accounted for as treasury shares.

Item 3. Defaults upon Senior Securities.

We were in violation of three of the financial covenants under our credit facility at June 30, 2016. See Item 1. Unaudited Condensed Notes to the Consolidated Financial Statements, Note 2 – Liquidity Considerations and Going Concern.

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

Item 4. Mine Safety Disclosure.

Not Applicable.

Item 5. Other Information.

None.

Item 6. Exhibits.

EXHIBIT INDEX

FOR

Form 10-Q for the quarter ended June 30, 2016.

Incorporated by Reference

Exhibit No.

Description

Form

SEC File No.

Exhibit

Filing Date

Filed Herewith

Furnished Herewith

31.1

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

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 15, 2016	Title:	President and Chief Executive Officer (Principal Executive Officer)



	By:	/s/ James J. Jacobs
Date: August 15, 2016	Name:	James J. Jacobs
	Title:	Chief Financial Officer (Principal Financial Officer)

Yuma Energy, Inc. - FORM 10-Q - August 15, 2016

Attached files

Yuma Energy, Inc. Reports