UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C.  20549

FORM 10-Q

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

For the quarterly period ended June 30, 2019

☐ 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: 001-37932

Yuma Energy, Inc.

(Exact name of registrant as specified in its charter)

DELAWARE (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)

(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 ☒   No ☐

Indicate by check mark whether the registrant has submitted electronically 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 ☒   No ☐

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

Larger accelerated filer ☐	Accelerated filer ☐
Non-accelerated filer ☒	Smaller reporting company ☒
	Emerging growth company ☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

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

Securities registered pursuant to Section 12(b) of the Act:

Title of each class	Trading Symbol(s)	Name of each exchange on which registered
Common Stock, $0.001 par value per share	YUMA	NYSE American LLC

At August 16, 2019, 1,551,989 shares of the registrant’s common stock, $0.001 par value per share, were outstanding.

TABLE OF CONTENTS

	PART I – FINANCIAL INFORMATION
Item 1.	Financial Statements (unaudited)
		Consolidated Balance Sheets as of June 30, 2019 and December 31, 2018	5
		Consolidated Statements of Operations for the Three and Six Months Ended June 30, 2019 and 2018	7
		Consolidated Statement of Changes in Stockholders’ Equity for the Three and Six Months Ended June 30, 2019 and 2018	8
		Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2019 and 2018	9
		Notes to the Unaudited Consolidated Financial Statements	10
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		26
Item 3.	Quantitative and Qualitative Disclosures About Market Risk		33
Item 4.	Controls and Procedures		33
	PART II – OTHER INFORMATION
Item 1.	Legal Proceedings		34
Item 1A.	Risk Factors		34
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		34
Item 3.	Defaults Upon Senior Securities		34
Item 4.	Mine Safety Disclosures		34
Item 5.	Other Information		34
Item 6.	Exhibits		35
	Signatures		36

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. Actual results could differ materially from those anticipated in these forward-looking statements. Readers should consider carefully the risks described under the “Risk Factors” section included in our previously filed Annual Report on Form 10-K for the year ended December 31, 2018, and 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:

●

that the administrative agent under our credit agreement has declared us to be in default and has reserved all its rights and remedies under the credit agreement including the right to accelerate and declare our loans due and payable and to foreclose on the collateral pledged under the credit agreement in whole or in part;

●

substantial doubt about our ability to continue as a going concern;

●

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

●

reductions in the borrowing base under our credit facility;

●

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

●

volatility and weakness in prices for oil and natural gas and the effect of prices set or influenced by actions of the Organization of the Petroleum Exporting Countries (“OPEC”) and other oil and natural gas producing countries;

●

the possibility that divestitures may involve unexpected costs or delays, and that acquisitions, if any, may not achieve intended benefits;

●

risks in connection with the integration of potential acquisitions;

●

we may incur more debt and higher levels of indebtedness could further adversely impact our ability to continue as a going concern;

●

our ability to successfully develop our undeveloped reserves;

●

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 reserves and acreage positions;

●

the ability to meet our plugging and abandonment obligations in a timely manner;

●

our ability to replace our oil and natural gas production or increase our 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;

●

the potential for mechanical failures and loss of production in our wells and our inability to restore production due to the cost of remedial operations exceeding our financial ability;

●

our ability to retain or replace key members of management and 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 may decline 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, and acts of terrorism or sabotage in other areas of the world;

●

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 ability to participate in oil and natural gas derivative activities and the effect of our termination of such activities;

●

our insurance coverage may not adequately cover all losses that we may sustain;

●

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;

●

unfavorable outcomes relating to one or more of several litigation matters to which we are a party;

●

the cost and availability of goods and services; 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 section and elsewhere in this report. Other than as required under applicable 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. You should not place undue reliance on these forward-looking statements. All forward-looking statements speak only as of the date of this report or, if earlier, as of the date they were made. 

PART I. FINANCIAL INFORMATION

Item 1.                        Financial Statements.

Yuma Energy, Inc.

CONSOLIDATED BALANCE SHEETS

(Unaudited)

	June 30,	December 31,
	2019	2018
ASSETS
CURRENT ASSETS:
Cash	$967,915	$1,634,492
Accounts receivable, net of allowance for doubtful accounts:
Trade	3,137,013	3,183,806
Other	104,365	195,774
Commodity derivative instruments, current portion	-	751,158
Prepayments	987,106	1,152,126
Other current assets	256,261	256,261
Total current assets	5,452,660	7,173,617
OIL AND GAS PROPERTIES (full cost method):
Oil and gas properties - subject to amortization	504,260,484	504,139,740
Oil and gas properties - not subject to amortization	-	-
	504,260,484	504,139,740
Less: accumulated depreciation, depletion, amortization and impairment	(450,996,357)	(436,642,215)
Net oil and gas properties	53,264,127	67,497,525
OTHER PROPERTY AND EQUIPMENT:
Assets held for sale	-	1,691,588
Other property and equipment	1,793,252	1,793,397
	1,793,252	3,484,985
Less: accumulated depreciation, amortization and impairment	(1,443,543)	(1,355,639)
Net other property and equipment	349,709	2,129,346
OTHER ASSETS AND DEFERRED CHARGES:
Commodity derivative instruments	-	13,028
Deposits	497,592	467,592
Operating right-of-use leases	3,896,955	-
Other noncurrent assets	79,997	79,997
Total other assets and deferred charges	4,474,544	560,617
TOTAL ASSETS	$63,541,040	$77,361,105

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

5

Yuma Energy, Inc.

CONSOLIDATED BALANCE SHEETS– CONTINUED

(Unaudited)

	June 30,	December 31,
	2019	2018
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
Current maturities of debt	$33,890,030	$34,742,953
Accounts payable	8,758,660	8,008,017
Asset retirement obligations	128,539	128,539
Current operating lease liabilities	838,418	-
Other accrued liabilities	2,827,183	1,275,473
Total current liabilities	46,442,830	44,154,982
LONG-TERM DEBT	-	-
OTHER NONCURRENT LIABILITIES:
Asset retirement obligations	11,394,989	11,143,320
Long-term lease liability	3,297,355	-
Deferred rent	-	250,891
Employee stock awards	-	40,153
Total other noncurrent liabilities	14,692,344	11,434,364
COMMITMENTS AND CONTINGENCIES (Notes 2 and 15)
STOCKHOLDERS' EQUITY
Series D convertible preferred stock
($0.001 par value, 7,000,000 authorized, 2,112,710 issued and outstanding
as of June 30, 2019 with a liquidiation preference of $23.4 million,
and 2,041,240 issued and outstanding as of December 31, 2018)	2,113	2,041
Common stock
($0.001 par value, 100,000,000 authorized, 1,551,989 outstanding as of
June 30, 2019 and 1,558,772 outstanding as of December 31, 2018)	1,552	1,559
Additional paid-in capital	58,322,612	58,470,831
Treasury stock at cost (26,516 shares as of June 30, 2019 and
25,368 shares as of December 31, 2018)	(441,044)	(439,099)
Accumulated deficit	(55,479,367)	(36,263,573)
Total stockholders' equity	2,405,866	21,771,759
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$63,541,040	$77,361,105

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

6

Yuma Energy, Inc.

CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

	Three Months Ended June 30,		Six Months Ended June 30,
	2019	2018	2019	2018
REVENUES:
Sales of natural gas and crude oil	$1,669,416	$5,822,577	$5,648,093	$11,468,113
EXPENSES:
Lease operating and production costs	2,003,196	2,795,825	4,294,513	5,421,593
General and administrative expense	1,482,271	1,651,858	2,900,301	3,697,390
Depreciation, depletion and amortization	684,988	2,245,170	2,624,700	4,462,491
Asset retirement obligation accretion expense	114,549	140,161	251,669	283,101
Impairment of oil and gas properties	371,086	-	11,817,345	-
Impairment of long lived assets	-	176,968	-	176,968
Bad debt expense	-	261,659	-	327,467
Total expenses	4,656,090	7,271,641	21,888,528	14,369,010
LOSS FROM OPERATIONS	(2,986,674)	(1,449,064)	(16,240,435)	(2,900,897)
OTHER INCOME (EXPENSE):
Net losses from commodity derivatives	-	(2,095,570)	(1,840,683)	(3,346,830)
Interest expense	(578,537)	(567,635)	(1,134,805)	(1,033,927)
Other, net	119	81,884	129	78,348
Total other expense	(578,418)	(2,581,321)	(2,975,359)	(4,302,409)
LOSS BEFORE INCOME TAXES	(3,565,092)	(4,030,385)	(19,215,794)	(7,203,306)
Income tax expense - deferred	-	-	-	-
NET LOSS	(3,565,092)	(4,030,385)	(19,215,794)	(7,203,306)
PREFERRED STOCK:
Dividends paid in-kind	401,304	374,416	791,467	738,433
NET LOSS ATTRIBUTABLE TO
COMMON STOCKHOLDERS	$(3,966,396)	$(4,404,801)	$(20,007,261)	$(7,941,739)
LOSS PER COMMON SHARE:
Basic	$(2.55)	$(2.86)	$(12.87)	$(5.19)
Diluted	$(2.55)	$(2.86)	$(12.87)	$(5.19)
WEIGHTED AVERAGE NUMBER OF
COMMON SHARES OUTSTANDING:
Basic	1,552,549	1,538,822	1,554,120	1,529,898
Diluted	1,552,549	1,538,822	1,554,120	1,529,898

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

7

Yuma Energy, Inc.

CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS’ EQUITY

For the Three and Six Months Ended June 30, 2019 and 2018

(Unaudited)

	Preferred Stock		Common Stock		Additional Paid-in	Treasury	Accumulated	Stockholders'
	Shares	Value	Shares	Value	Capital	Stock	Deficit	Equity
March 31, 2019	2,076,472	$2,076	1,553,594	$1,554	$58,349,733	$(441,044)	$(51,914,275)	$5,998,044
Net loss	-	-	-	-	-	-	(3,565,092)	(3,565,092)
Payment of Series D dividends in-kind	36,238	37	-	-	(37)	-	-	-
Stock awards vested	-	-	-	-	-	-	-	-
Restricted stock awards forfeited	-	-	(1,605)	(2)	2	-	-	-
Restricted stock awards repurchased	-	-	-	-	-	-	-	-
Stock-based compensation	-	-	-	-	(27,086)	-	-	(27,086)
Treasury stock	-	-	-	-	-	-	-	-
June 30, 2019	2,112,710	$2,113	1,551,989	$1,552	$58,322,612	$(441,044)	$(55,479,367)	$2,405,866

	Preferred Stock		Common Stock		Additional Paid-in	Treasury	Accumulated	Stockholders'
	Shares	Value	Shares	Value	Capital	Stock	Deficit	Equity
March 31, 2018	1,937,262	$1,937	1,558,061	$1,558	$56,750,150	$(434,557)	$(22,730,239)	$33,588,849
Net loss	-	-	-	-	-	-	(4,030,385)	(4,030,385)
Payment of Series "D" dividends in-kind	33,810	34	-	-	374,382	-	(374,416)	-
Stock awards vested	-	-	2,076	2	(2)	-	-	-
Restricted stock awards forfeited	-	-	(501)	-	-	-	-	-
Restricted stock awards repurchased	-	-	(722)	(1)	1	-	-	-
Stock-based compensation	-	-	-	-	201,687	-	-	201,687
Treasury stock	-	-	-	-	-	(4,333)	-	(4,333)
June 30, 2018	1,971,072	$1,971	1,558,914	$1,559	$57,326,218	$(438,890)	$(27,135,040)	$29,755,818

	Preferred Stock		Common Stock		Additional Paid-in	Treasury	Accumulated	Stockholders'
	Shares	Value	Shares	Value	Capital	Stock	Deficit	Equity
December 31, 2018	2,041,240	$2,041	1,558,772	$1,559	$58,470,831	$(439,099)	$(36,263,573)	$21,771,759
Net loss	-	-	-	-	-	-	(19,215,794)	(19,215,794)
Payment of Series D dividends in-kind	71,470	72	-	-	(72)	-	-	-
Stock awards vested	-	-	-	-	-	-	-	-
Restricted stock awards forfeited	-	-	(5,636)	(6)	6	-	-	-
Restricted stock awards repurchased	-	-	(1,147)	(1)	-	-	-	(1)
Stock-based compensation	-	-	-	-	(148,153)	-	-	(148,153)
Treasury stock	-	-	-	-	-	(1,945)	-	(1,945)
June 30, 2019	2,112,710	$2,113	1,551,989	$1,552	$58,322,612	$(441,044)	$(55,479,367)	$2,405,866

	Preferred Stock		Common Stock		Additional Paid-in	Treasury	Accumulated	Stockholders'
	Shares	Value	Shares	Value	Capital	Stock	Deficit	Equity
December 31, 2017	1,904,391	$1,904	1,520,167	$1,520	$55,085,827	$(25,278)	$(19,193,301)	$35,870,672
Net loss	-	-	-	-	-	-	(7,203,306)	(7,203,306)
Payment of Series "D" dividends in-kind	66,681	67	-	-	738,366	-	(738,433)	-
Stock awards vested	-	-	64,138	64	(64)	-	-	-
Restricted stock awards forfeited	-	-	(942)	(1)	1	-	-	-
Restricted stock awards repurchased	-	-	(24,448)	(24)	24	-	-	-
Stock-based compensation	-	-	-	-	1,502,064	-	-	1,502,064
Treasury stock	-	-	-	-	-	(413,612)	-	(413,612)
June 30, 2018	1,971,072	$1,971	1,558,914	$1,559	$57,326,218	$(438,890)	$(27,135,040)	$29,755,818

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

8

Yuma Energy, Inc.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Six Months Ended June 30,
	2019	2018
CASH FLOWS FROM OPERATING ACTIVITIES:
Reconciliation of net loss to net cash provided by operating activities:
Net loss	$(19,215,794)	$(7,203,306)
Depreciation, depletion and amortization of property and equipment	2,624,700	4,462,491
Impairment of long lived assets	-	176,968
Amortization of debt issuance costs	-	260,803
Deferred rent liability, net	-	25,668
Stock-based compensation expense	(148,153)	360,524
Settlement of asset retirement obligations	-	(575,817)
Asset retirement obligation accretion expense	251,669	283,101
Impairment of oil and gas properties	11,817,345	-
Bad debt expense	-	327,467
Net loss from commodity derivatives	1,840,683	3,346,830
(Gain) loss on write-off of liabilities net of assets	-	(103,045)
Amortization of operating right of use lease	333,402	-
Changes in assets and liabilities:
(Increase) decrease in accounts receivable	138,202	1,339,227
(Increase) decrease in prepaids, deposits and other assets	135,020	297,321
(Decrease) increase in accounts payable and other current and
non-current liabilities	2,158,963	65,487
NET CASH (USED IN) PROVIDED BY OPERATING ACTIVITIES	(63,963)	3,063,719
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures for oil and gas properties	(308,464)	(6,928,684)
Proceeds from sale of oil and gas properties	1,691,588	1,000,000
Proceeds from sale of other fixed assets	-	-
Derivative settlements	(46,357)	(1,189,211)
NET CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES	1,336,767	(7,117,895)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings on senior credit facility	-	14,300,000
Repayment of borrowings on senior credit facility	(1,194,482)	(7,000,000)
Repayments of borrowings - insurance financing	(742,953)	(556,898)
Net proceeds (expenses) from common stock offering	-	(64,050)
Cash paid for repurchase of restricted stock	(1)	-
Treasury stock repurchases	(1,945)	(413,612)
NET CASH (USED IN) PROVIDED BY FINANCING ACTIVITIES	(1,939,381)	6,265,440
NET (DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS	(666,577)	2,211,264
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD	1,634,492	137,363
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$967,915	$2,348,627
Supplemental disclosure of cash flow information:
Interest payments (net of interest capitalized)	$1,134,806	$773,150
Interest capitalized	$-	$133,772
Supplemental disclosure of significant non-cash activity:
Change in capital expenditures financed by accounts payable	$187,864	$3,252,112

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

9

YUMA ENERGY, INC.

NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1 – Organization and Basis of Presentation

Organization

Yuma Energy, Inc., a Delaware corporation (“Yuma” and collectively with its subsidiaries, the “Company”), is an independent Houston-based exploration and production company focused on acquiring, developing and exploring for conventional and unconventional oil and natural gas resources. Historically, the Company’s operations have focused on onshore properties located in central and southern Louisiana and southeastern Texas where it has a long history of drilling, developing and producing both oil and natural gas assets. The Company also has acreage in the Permian Basin of West Texas (Yoakum County, Texas), with the potential for additional oil and natural gas reserves. Finally, the Company has non-operated positions in the East Texas Woodbine and had operated positions in Kern County, California, which were sold in April 2019.

Reverse Stock Split

Yuma filed a Certificate of Amendment to the Amended and Restated Certificate of Incorporation of Yuma with the Secretary of State of the State of Delaware, pursuant to which, effective on July 3, 2019, Yuma effected a one-for-fifteen reverse split of its issued and outstanding shares of common stock (the “Reverse Stock Split”). The number of authorized shares of common stock did not change from 100,000,000. The Company’s authorized shares of Preferred Stock did not change from 20,000,000. All share and per share information in these financial statements retroactively reflect this reverse stock split.

Basis of Presentation

The accompanying unaudited consolidated financial statements of the Company and its wholly owned subsidiaries have been prepared in accordance with Article 8-03 of Regulation S-X for interim financial statements required to be filed with the Securities and Exchange Commission (“SEC”). The information furnished herein reflects all adjustments that are, in the opinion of management, necessary for the fair presentation of the Company’s Consolidated Balance Sheet as of June 30, 2019; the Consolidated Statements of Operations for the three and six months ended June 30, 2019 and 2018; the Consolidated Statement of Changes in Stockholders’ Equity for the three and six months ended June 30, 2019 and 2018; and the Consolidated Statements of Cash Flows for the six months ended June 30, 2019 and 2018. The Company’s Consolidated Balance Sheet at December 31, 2018 is derived from the audited consolidated financial statements of the Company at that date.

The preparation of financial statements in conformity with the generally accepted accounting principles of the United States of America (“GAAP”) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. For further information, see Note 1 in the Notes to Consolidated Financial Statements contained in the Company’s Annual Report on Form 10-K for the year ended December 31, 2018.

Interim period results are not necessarily indicative of results of operations or cash flows for the full year and accordingly, certain information normally included in financial statements and the accompanying notes prepared in accordance with GAAP has been condensed or omitted. These financial statements should be read in conjunction with the Company’s Annual Report on Form 10-K for the year ended December 31, 2018. The Company has evaluated events or transactions through the date of issuance of these unaudited consolidated financial statements.

When required for comparability, reclassifications are made to the prior period financial statements to conform to the current year presentation.

The consolidated financial statements have been prepared on a going concern basis; however, see Note 2 – Liquidity and Going Concern for additional information.

10

Recently Issued Accounting Pronouncements

The accounting standard-setting organizations frequently issue new or revised accounting rules. The Company regularly reviews new pronouncements to determine their impact, if any, on the financial statements.

Accounting Pronouncement Recently Adopted

In February 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2016-02, Leases (Topic 842): Amendments to the FASB Accounting Standards Codification (“ASU 2016-02”). In January 2018, the FASB issued ASU No. 2018-01, Leases (Topic 842): Land Easement Practical Expedient for Transition to Topic 842 (“ASU 2018-01”). In July 2018, the FASB issued ASU No. 2018-11, Leases (Topic 842): Targeted Improvements (“ASU 2018-11”). Together, these related amendments to GAAP represent ASC Topic 842, Leases (“ASC Topic 842”). ASC Topic 842 requires an entity to recognize an asset and lease liability for all qualifying leases. Classification of leases as either a finance or operating lease determines the recognition, measurement and presentation of expenses. This accounting standards update also requires certain quantitative and qualitative disclosures about leasing arrangements.

The new standard was effective for the Company in the first quarter of 2019 and the Company adopted the new standard using a modified retrospective approach, with the date of initial application on January 1, 2019. Consequently, upon transition, the Company recognized an asset and a lease liability with no retained earnings impact. The Company is applying the following practical expedients as provided in ASC Topic 842 which provide elections to:

●

not apply the recognition requirements to short-term leases (a lease that at commencement date has a lease term of 12 months or less and does not contain a purchase option);

●

not reassess whether a contract contains a lease, lease classification and initial direct costs; and

●

not reassess certain land easements in existence prior to January 1, 2019.

Through the Company’s implementation process, it evaluated each of its lease arrangements and enhanced its systems to track and calculate additional information required upon adoption of this standards update. The Company’s adoption did not have a material impact on its consolidated balance sheet as of January 1, 2019, with the primary impact relating to the recognition of assets and operating lease liabilities for operating leases which represented less than a 5% change to total assets and total liabilities at the time of adoption.

Adoption of the new standard did not materially impact the Company’s consolidated statements of operations or stockholders’ equity. Leases acquired to explore for or use minerals, oil or natural gas resources, including the right to explore for those natural resources and rights to use the land in which those natural resources are contained, are not within the scope of the standards update (see Note 15 – Commitments and Contingencies).

NOTE 2 – Liquidity and Going Concern

The factors and uncertainties described below, as well as other factors which include, but are not limited to, declines in the Company’s production, the Company’s failure to establish commercial production on its Permian properties, no available capital to maintain and develop its properties, and its substantial working capital deficit of approximately $41 million, raise substantial doubt about the Company’s ability to continue as a going concern for the twelve months following the issuance of these financial statements. 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.

On October 26, 2016, the Company and three of its subsidiaries, as the co-borrowers, entered into a credit agreement providing for a $75.0 million three-year senior secured revolving credit facility (the “Credit Agreement”) with Société Générale (“SocGen”), as administrative agent, SG Americas Securities, LLC, as lead arranger and bookrunner, and the lenders signatory thereto (collectively with SocGen, the “Lender”).

The credit facility was $32.8 million as of June 30, 2019, and the Company was, and is, fully drawn, leaving no availability on the line of credit. All of the obligations under the Credit Agreement, and the guarantees of those obligations, are secured by substantially all of the Company’s assets.

11

The Credit Agreement contains a number of covenants that, among other things, restrict, subject to certain exceptions, the Company’s ability to incur additional indebtedness, create liens on assets, make investments, enter into sale and leaseback transactions, pay dividends and distributions or repurchase its capital stock, engage in mergers or consolidations, sell certain assets, sell or discount any notes receivable or accounts receivable, and engage in certain transactions with affiliates.

The Credit Agreement contains customary financial and affirmative covenants and defines events of default for credit facilities of this type, including failure to pay principal or interest, breach of covenants, breach of representations and warranties, insolvency, judgment default, and a change of control. Upon the occurrence and continuance of an event of default, the Lender has the right to accelerate repayment of the loans and exercise its remedies with respect to the collateral.

The Company is not in compliance under the credit facility with its (i) total debt to EBITDAX covenant for the trailing four quarter period, (ii) current ratio covenant, (iii) EBITDAX to interest expense covenant for the trailing four quarter period, (iv) the liquidity covenant requiring the Company to maintain unrestricted cash and borrowing base availability of at least $4.0 million, and (v) obligation to make interest only payments. The Company currently is not making any payments of interest under the credit facility and anticipates future non-compliance under the credit facility for the foreseeable future until the Company effects a restructuring of its debt obligations. Due to this non-compliance, as well as the credit facility maturity in 2019, the Company classified its entire bank debt as a current liability in its financial statements as of June 30, 2019. On October 9, 2018, the Company received a notice and reservation of rights from the administrative agent under the Credit Agreement advising that an event of default had occurred and continues to exist by reason of the Company’s noncompliance with the liquidity covenant requiring the Company to maintain cash and cash equivalents and borrowing base availability of at least $4.0 million. As a result of the default, the Lender may accelerate the outstanding balance under the Credit Agreement, increase the applicable interest rate by 2.0% per annum or commence foreclosure on the collateral securing the loans. As of the date of this filing, the Lender has not accelerated the outstanding amount due and payable on the loans, increased the applicable interest rate or commenced foreclosure proceedings, but may exercise one or more of these remedies in the future. As required under the Credit Agreement, the Company previously entered into hedging arrangements with SocGen and BP Energy Company (“BP”) pursuant to International Swaps and Derivatives Association Master Agreements (“ISDA Agreements”).

On March 14, 2019, the Company received a notice of an event of default under its ISDA Agreement with SocGen (the “SocGen ISDA”). Due to the default under the ISDA Agreement, SocGen unwound all of the Company’s hedges with them. The notice provides for a payment of $335,252 to settle the Company’s outstanding obligations thereunder related to SocGen’s hedges, which is included in current maturities of debt at June 30, 2019. On March 19, 2019, the Company received a notice of an event of default under its ISDA Agreement with BP (the “BP ISDA”). Due to the default under the ISDA Agreement, BP also unwound all of the Company’s hedges with them. The notice provides for a payment of $749,240 to settle the Company’s outstanding obligations thereunder related to BP’s hedges, which is included in current maturities of debt at June 30, 2019.

During the first quarter of 2019, the Company agreed to sell its Kern County, California properties, and closed on the sale in April 2019 for net proceeds of approximately $1.7 million. As additional consideration for the sale of the assets, if WTI Index for oil equals or exceeds $65 in the six months following closing and maintains that average for twelve consecutive months then the buyer agreed to pay the Company an additional $250,000. Net proceeds of approximately $1.2 million were used for the repayment of borrowings under the credit facility, and approximately $500,000 was retained by the Company for working capital purposes.

The Company has initiated several strategic alternatives to mitigate its limited liquidity (defined as cash on hand and undrawn borrowing base), its financial covenant compliance issues, and to provide it with additional working capital to develop its existing assets.

On October 22, 2018, the Company retained Seaport Global Securities LLC, an investment banking firm, to advise the Company on its strategic and tactical alternatives, including possible acquisitions and divestitures. On March 1, 2019, the Company hired a Chief Restructuring Officer, and subsequently on March 28, 2019, appointed that person as Interim Chief Executive Officer.

The Company continues to reduce its operating and general and administrative costs and has curtailed its planned 2019 capital expenditures.

The Company plans to take further steps to mitigate its limited liquidity, which may include, but are not limited to, restructuring its existing debt; selling additional assets; further reducing general and administrative expenses; seeking merger and acquisition related opportunities; and potentially raising proceeds from capital markets transactions, including the sale of debt or equity securities. There can be no assurance that the exploration of strategic alternatives will result in a transaction or otherwise improve the Company’s limited liquidity and that the Company will continue as a going concern.

12

NOTE 3 – Revenue Recognition

Sales of crude oil, condensates, natural gas and natural gas liquids (“NGLs”) are recognized at the point where control of the product is transferred to the customer and collectability is reasonably assured.

The Company records revenue in the month production is delivered to the purchaser. However, settlement statements for certain natural gas and NGL sales may not be received for 30 to 90 days after the date production is delivered, and as a result, the Company is required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. The Company records the differences between its estimates and the actual amounts received for product sales in the month that payment is received from the purchaser. Any identified differences between its revenue estimates and actual revenue received historically have not been significant. For the three and six months ended June 30, 2019 and 2018, revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material.

Gain or loss on derivative instruments is not considered revenue from contracts with customers. The Company may use financial or physical contracts accounted for as derivatives as economic hedges to manage price risk associated with normal sales, or in limited cases may use them for contracts the Company intends to physically settle but do not meet all of the criteria to be treated as normal sales.

The following table presents the Company’s revenues disaggregated by product source. Sales taxes are excluded from revenues.

	Three Months Ended June 30,		Six Months Ended June 30,
	2019	2018	2019	2018
Sales of natural gas and crude oil:
Crude oil and condensate	$1,081,674	$3,203,260	$3,280,696	$6,269,517
Natural gas	395,494	1,775,919	1,575,903	3,567,170
Natural gas liquids	192,248	843,398	791,494	1,631,426
Total revenues	$1,669,416	$5,822,577	$5,648,093	$11,468,113

Transaction Price Allocated to Remaining Performance Obligations

A significant number of the Company’s product sales are short-term in nature with a contract term of one year or less. For those contracts, the Company has utilized the practical expedient exempting the Company from disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less.

For the Company’s product sales that have a contract term greater than one year, it has utilized the practical expedient which states that the Company is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under these sales contracts, each unit of product generally represents a separate performance obligation; therefore, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required.

Contract Balances

Receivables from contracts with customers are recorded when the right to consideration becomes unconditional, generally when control of the product has been transferred to the customer. Receivables from contracts with customers were $1,460,825 and $2,282,200 as of June 30, 2019 and December 31, 2018, respectively, and are reported in trade accounts receivable, net on the Consolidated Balance Sheets. The Company currently has no other assets or liabilities related to its revenue contracts, including no upfront or rights to deficiency payments.

13

NOTE 4 – Asset Impairments

The Company’s oil and natural gas properties are accounted for using the full cost method of accounting, under which all productive and nonproductive costs directly associated with property acquisition, exploration and development activities are capitalized. These capitalized costs (net of accumulated DD&A and deferred income taxes) of proved oil and natural gas properties are subject to a full cost ceiling limitation. The full cost ceiling limitation limits these costs to an amount equal to the present value, discounted at 10%, of estimated future cash flows from estimated proved reserves less estimated future operating and development costs, abandonment costs (net of salvage value) and estimated related future deferred income taxes. In accordance with SEC rules, prices used are the 12-month average prices, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12 month period prior to the end of the reporting period, unless prices are defined by contractual arrangements. Prices are adjusted for “basis” or location differentials. Prices are held constant over the life of the reserves. The Company’s second quarter of 2019 full cost ceiling calculation was prepared by the Company using (i) $61.45 per barrel for oil, and (ii) $3.02 per MMBTU for natural gas as of June 30, 2019. If unamortized costs capitalized within the cost pool exceed the ceiling, the excess is charged to expense and separately disclosed during the period in which the excess occurs. Amounts thus required to be written off are not reinstated for any subsequent increase in the cost center ceiling.

Based on a thorough analysis of the Company’s assets, the major contribution for an impairment for the second quarter of fiscal year 2019 is the decrease in the 12 month rolling SEC prices used at June 30, 2019. As a result of this review, the Company recorded a full cost ceiling impairment charge of $0.4 million during the three-month period ended June 30, 2019. The Company recorded a full cost ceiling impairment charge of $11.8 million for the six-month period ended June 30, 2019. During the three and six month periods ended June 30, 2018, the Company did not record any full cost ceiling impairments.

NOTE 5 – Asset Retirement Obligations

The Company has asset retirement obligations (“AROs”) associated with the future plugging and abandonment of oil and natural gas properties and related facilities. The accretion of the ARO is included in the Consolidated Statements of Operations. Revisions to the liability typically occur due to changes in the estimated abandonment costs, well economic lives and the discount rate.

The following table summarizes the Company’s ARO transactions recorded during the six months ended June 30, 2019 in accordance with the provisions of FASB ASC Topic 410, “Asset Retirement and Environmental Obligations”:

	Six Months Ended
	June 30, 2019
Asset retirement obligations at December 31, 2018	$11,271,859
Liabilities incurred	-
Liabilities settled	-
Accretion expense	251,669
Revisions in estimated cash flows	-
Asset retirement obligations at June 30, 2019	$11,523,528

Based on expected timing of settlements, $128,539 of the ARO is classified as current at June 30, 2019.

NOTE 6 – Fair Value Measurements

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

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

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.

14

As previously disclosed, there were no outstanding commodity derivatives as of June 30, 2019.

	Fair value measurements at December 31, 2018
		Significant
	Quoted prices	other	Significant
	in active	observable	unobservable
	markets	inputs	inputs
	(Level 1)	(Level 2)	(Level 3)	Total
Assets:
Commodity derivatives – oil	$-	$922,562	$-	$922,562
Commodity derivatives – gas	-	(158,376)	-	$(158,376)
Total assets	$-	$764,186	$-	$764,186

Derivative instruments listed above are related to swaps (see Note 7 – Commodity Derivative Instruments).

Debt – The Company’s debt is recorded at the carrying amount on its Consolidated Balance Sheets (see Note 10 – Debt and Interest Expense), which approximates fair value.

Asset Retirement Obligations – The Company estimates the fair value of AROs upon initial recording 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 (see Note 5 – Asset Retirement Obligations). Therefore, the Company has designated the initial recording of these liabilities as Level 3.

Assets Held for Sale – The fair values of property, plant and equipment, classified as assets held for sale, and related impairments, which are calculated using Level 3 inputs, are discussed in Note 14 – Divestitures and Oil and Gas Asset Sales.

NOTE 7 – Commodity Derivative Instruments

As required under the Credit Agreement, the Company previously entered into hedging arrangements with SocGen and BP pursuant to ISDA Agreements. On March 14, 2019, the Company received a notice of an event of default under the SocGen ISDA. Due to the default under the SocGen ISDA, SocGen unwound all of the Company’s hedges with them. The notice provides for a payment of $335,252 to settle the Company’s outstanding obligations thereunder related to SocGen’s hedges which is included in current maturities of debt at June 30, 2019. On March 19, 2019, the Company received a notice of an event of default under its BP ISDA. Due to the default under the BP ISDA, BP also unwound all of the Company’s hedges with them. The notice provides for a payment of $749,240 to settle the Company’s outstanding obligations thereunder related to BP’s hedges which is included in current maturities of debt at June 30, 2019.

Counterparty Credit Risk – Commodity derivative instruments expose the Company to counterparty credit risk. The Company did not have any commodity derivative instruments at June 30, 2019. Commodity derivative contracts are executed under ISDA 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.

Derivatives for each commodity are netted on the Consolidated Balance Sheets. The following table presents the fair value and balance sheet location of each classification of commodity derivative contracts on a gross basis without regard to same-counterparty netting:

	Fair value as of
	June 30, 2019	December 31, 2018
Asset commodity derivatives:
Current assets	$-	$1,031,614
Noncurrent assets	-	98,530
Total asset commodity derivatives	-	1,130,144
Liability commodity derivatives:	-
Current liabilities	-	(280,456)
Noncurrent liabilities	-	(85,502)
Total liability commodity derivatives	-	(365,958)
Total commodity derivative instruments	$-	$764,186

15

Net losses from commodity derivatives on the Consolidated Statements of Operations are comprised of the following:

	Three Months Ended June 30,		Six Months Ended June 30,
	2019	2018	2018	2018
Derivative settlements	$-	$(659,847)	$(1,076,497)	$(1,189,211)
Mark to market on commodity derivatives	-	(1,435,723)	(764,186)	(2,157,619)
Net gains (losses) from commodity derivatives	$-	$(2,095,570)	$(1,840,683)	$(3,346,830)

NOTE 8 – Preferred Stock

Each share of the Company’s Series D Convertible Preferred Stock, $0.001 par value per share (the “Series D Preferred Stock”), is convertible into a number of shares of common stock determined by dividing the original issue price, which was $11.0741176, by the conversion price, which is currently $98.7571635 as adjusted for the Reverse Stock Split. The conversion price is subject to adjustment for stock splits, stock dividends, reclassification, and certain issuances of common stock for less than the conversion price. As of June 30, 2019, the Series D Preferred Stock had a liquidation preference of approximately $23.4 million. The Series D Preferred Stock provides for cumulative dividends of 7.0% per annum, payable in-kind. In payment of the dividend, the Company issued 36,238 and 71,470 shares of Series D Preferred Stock during the three and six months ended June 30, 2019, respectively. The Company does not have any dividends in arrears at June 30, 2019.

NOTE 9 – Stock-Based Compensation

2014 Long-Term Incentive Plan

On October 26, 2016, Yuma assumed the Yuma Energy, Inc., a California corporation (“Yuma California”), 2014 Long-Term Incentive Plan (the “2014 Plan”), which was approved by the shareholders of Yuma California. Under the 2014 Plan, Yuma could grant stock options, restricted stock awards (“RSAs”), restricted stock units (“RSUs”), stock appreciation rights (“SARs”), performance units, performance bonuses, stock awards and other incentive awards to employees of Yuma and its subsidiaries and affiliates.

At June 30, 2019, 10,905 shares of the 166,334 shares of common stock originally authorized under the 2014 Plan remained available for future issuance. However, upon adoption of the Company’s 2018 Long-Term Incentive Plan on June 7, 2018, none of these remaining shares will be issued.

2018 Long-Term Incentive Plan

The Company’s Board adopted the Yuma Energy, Inc. 2018 Long-Term Incentive Plan (the “2018 Plan”), and its stockholders approved the 2018 Plan at the Annual Meeting on June 7, 2018. The 2018 Plan will replace the 2014 Plan; however, the terms and conditions of the 2014 Plan and related award agreements will continue to apply to all awards granted under the 2014 Plan.

The 2018 Plan expires on June 7, 2028, and no awards may be granted under the 2018 Plan after that date. However, the terms and conditions of the 2018 Plan will continue to apply after that date to all 2018 Plan awards granted prior to that date until they are no longer outstanding.

Under the 2018 Plan, the Company may grant stock options, RSAs, RSUs, SARs, performance units, performance bonuses, stock awards and other incentive awards to employees or those of the Company’s subsidiaries or affiliates, subject to the terms and conditions set forth in the 2018 Plan. The Company may also grant nonqualified stock options, RSAs, RSUs, SARs, performance units, stock awards and other incentive awards to any persons rendering consulting or advisory services and non-employee directors, subject to the conditions set forth in the 2018 Plan. Generally, all classes of the Company’s employees are eligible to participate in the 2018 Plan.

16

The 2018 Plan provides that a maximum of 266,667 shares of the Company’s common stock may be issued in conjunction with awards granted under the 2018 Plan. Shares of common stock cancelled, settled in cash, forfeited, withheld, or tendered by a participant to satisfy exercise prices or tax withholding obligations will be available for delivery pursuant to other awards. At June 30, 2019, all of the 266,667 shares of common stock authorized under the 2018 Plan remain available for future issuance.

The Company accounts for stock-based compensation in accordance with FASB ASC Topic 718, “Compensation – Stock Compensation”.The guidance requires that all stock-based payments to employees and directors, including grants of RSUs, be recognized over the requisite service period in the financial statements based on their fair values.

RSAs, SARs and stock options granted to officers and employees generally vest in one-third increments over a three-year period, or with three-year cliff vesting, and are contingent on the recipient’s continued employment. RSAs granted to directors generally vest in quarterly increments over a one-year period.

Equity Based Awards – During the three months ended June 30, 2019, the Company did not grant any RSAs under the 2014 Plan or the 2018 Plan. As of June 30, 2019, there were a total of 10,402 stock options outstanding and exercisable, with a weighted average exercise price of $38.40 per share, a contractual life of approximately 7.80 years, and an aggregate intrinsic value of $0.00 per share.

At June 30, 2019, there were a total of 319 unvested RSAs, with a weighted average grant-date fair value of $38.40 per share.

Liability Based Awards – During the three months ended June 30, 2019, the Company did not grant any liability-based awards under the 2014 Plan or the 2018 Plan. As of June 30, 2019, there were 3,090 unvested cash-settled SARs with a weighted average fair value of $0.60 per share.

Share Buy-back – During the three months ended June 30, 2019, the Company did not purchase any common shares from employees. During the six months ended June 30, 2019, the Company purchased 1,148 common shares from employees at a cost of $1,945 in satisfaction of employee tax obligations upon the vesting of RSAs. 

Total share-based compensation expenses recognized for the three months ended June 30, 2019 and 2018 were ($27,086), due primarily to liability-based SARs declining in value and significant forfeitures of equity-based RSAs and stock options, and $64,230, respectively. Total share-based compensation expenses recognized for the six months ended June 30, 2019 and 2018 were ($148,153) and $360,524, respectively. No share-based compensation was capitalized during 2019 or 2018.

NOTE 10 – Debt and Interest Expense

Long-term debt consisted of the following:

	June 30,	December 31,
	2019	2018
Senior credit facility	$32,805,518	$34,000,000
Commodity debt payable	1,084,512	-
Installment loan due 6/23/19 originating from the financing of
insurance premiums at 6.14% interest rate	-	742,953
Total debt	33,890,030	34,742,953
Less: current maturities	(33,890,030)	(34,742,953)
Total long-term debt	$-	$-

17

Senior Credit Facility

The Company is currently in default under its Credit Agreement due to non-compliance with the financial covenants and failure to pay interest. As of June 30, 2019, the credit facility had a borrowing base of $32.8 million and the Company was fully drawn under the credit facility leaving no availability.

On October 26, 2016, the Company and three of its subsidiaries, as the co-borrowers, entered into the Credit Agreement with the Lender. The Company’s obligations under the Credit Agreement are guaranteed by its subsidiaries and are secured by liens on substantially all of the Company’s assets, including a mortgage lien on oil and natural gas properties covering at least 95% of the PV-10 value of the proved oil and gas properties included in the determination of the borrowing base.

The borrowing base is generally subject to redetermination on April 1st and October 1st of each year, as well as special redeterminations described in the Credit Agreement (no redetermination occurred on April 1, 2019 due to the default under the Credit Agreement). The amounts borrowed under the Credit Agreement bear annual interest rates at either (a) the London Interbank Offered Rate (“LIBOR”) plus 3.00% to 4.00% or (b) the prime lending rate of SocGen plus 2.00% to 3.00%, depending on the amount borrowed under the credit facility and whether the loan is drawn in U.S. dollars or Euro dollars. The interest rate for the credit facility at December 31, 2018 was 6.53% for LIBOR-based debt and 8.50% for prime-based debt. Principal amounts outstanding under the credit facility are due and payable in full at maturity on October 26, 2019. All of the obligations under the Credit Agreement, and the guarantees of those obligations, are secured by substantially all of the Company’s assets. Additional payments due under the Credit Agreement include paying a commitment fee to the Lender in respect of the unutilized commitments thereunder. The commitment rate is 0.50% per year of the unutilized portion of the borrowing base in effect from time to time. The Company is also required to pay customary letter of credit fees.

The Credit Agreement contains a number of covenants that, among other things, restrict, subject to certain exceptions, the Company’s ability to incur additional indebtedness, create liens on assets, make investments, enter into sale and leaseback transactions, pay dividends and distributions or repurchase the Company’s capital stock, engage in mergers or consolidations, sell certain assets, sell or discount any notes receivable or accounts receivable, and engage in certain transactions with affiliates.

In addition, the Credit Agreement requires the Company to maintain the following financial covenants: a current ratio of not less than 1.0 to 1.0 on the last day of each quarter, a ratio of total debt to earnings before interest, taxes, depreciation, depletion, amortization and exploration expenses (“EBITDAX”) ratio of not greater than 3.5 to 1.0 for the four fiscal quarters ending on the last day of the fiscal quarter immediately preceding such date of determination, and a ratio of EBITDAX to interest expense of not less than 2.75 to 1.0 for the four fiscal quarters ending on the last day of the fiscal quarter immediately preceding such date of determination, and cash and cash equivalent investments together with borrowing availability under the Credit Agreement of at least $4.0 million. The Credit Agreement contains customary affirmative covenants and defines events of default for credit facilities of this type, including failure to pay principal or interest, breach of covenants, breach of representations and warranties, insolvency, judgment default, and a change of control. Upon the occurrence and continuance of an event of default, the Lender has the right to accelerate repayment of the loans and exercise its remedies with respect to the collateral.

At June 30, 2019, the Company was not in compliance under the credit facility, as more fully described in Note 2 – Liquidity and Going Concern.

The Company incurred commitment fees in connection with the Credit Agreement of $-0- and $4,735 during the three months ended June 30, 2019 and 2018, respectively, and $-0- and $19,170 during the six months ended June 30, 2019 and 2018, respectively.

NOTE 11 – Stockholders’ Equity

Yuma is authorized to issue up to 100,000,000 shares of common stock, $0.001 par value per share, and 20,000,000 shares of preferred stock, $0.001 par value per share. The holders of common stock are entitled to one vote for each share of common stock, except as otherwise required by law. The Company has designated 7,000,000 shares of preferred stock as Series D Preferred Stock.

See Note 8 - Preferred Stock, which describes the issuance of dividends in-kind, and Note 9 – Stock-Based Compensation, which describes outstanding stock options, RSAs and SARs granted under the 2014 Plan and the provisions of the 2018 Plan adopted on June 7, 2018.

18

NOTE 12 – Loss Per Common Share

Loss per common share – Basic is calculated by dividing net loss attributable to common stockholders by the weighted average number of shares of common stock outstanding during the period. Loss per common share – Diluted assumes the conversion of all potentially dilutive securities, and is calculated by dividing net loss attributable to common stockholders by the sum of the weighted average number of shares of common stock outstanding plus potentially dilutive securities. Loss per common share – Diluted considers the impact of potentially dilutive securities except in periods where their inclusion would have an anti-dilutive effect.

A reconciliation of loss per common share is as follows: 

	Three Months Ended June 30,		Six Months Ended June 30,
	2019	2018	2019	2018
Net income (loss) attributable to common stockholders	$(3,966,396)	$(4,404,801)	$(20,007,261)	$(7,941,739)
Weighted average common shares outstanding
Basic	1,552,549	1,538,822	1,554,120	1,529,898
Add potentially dilutive securities:
Unvested restricted stock awards	-	-	-	-
Stock appreciation rights	-	-	-	-
Stock options	-	-	-	-
Series D preferred stock	-	-	-	-
Diluted weighted average common shares outstanding	1,552,549	1,538,822	1,554,120	1,529,898
Net income (loss) per common share:
Basic	$(2.55)	$(2.86)	$(12.87)	$(5.19)
Diluted	$(2.55)	$(2.86)	$(12.87)	$(5.19)

For the three and six months ended June 30, 2019, the Company excluded 319 shares of unvested restricted stock awards, 10,133 stock appreciation rights, 10,402 stock options, and 2,112,710 shares of Series D Preferred Stock in calculating diluted earnings per share, as the effect was anti-dilutive. For the three and six months ended June 30, 2018, the Company excluded 9,904 shares of unvested restricted stock awards, 113,852 stock appreciation rights, 59,911 stock options, and 1,971,072 shares of Series D Preferred Stock in calculating diluted earnings per share, as the effect was anti-dilutive.

NOTE 13 – Income Taxes

The Company’s effective tax rate was 0.00% for the three and six months ended June 30, 2019 and 2018. Differences between the U.S. federal statutory rate of 21% in 2019 and 2018 and the Company’s effective tax rates are due to the tax effects of valuation allowances recorded against the deferred tax assets.

As of June 30, 2019, the Company had federal net operating loss carryforwards of approximately $187.8 million, of which $173.2 million expire between 2022 and 2038. Of this amount, approximately $59.5 million is subject to limitation under Section 382 of the Internal Revenue Code of 1986, as amended (the “Code”), which could result in some amounts expiring prior to being utilized. The remaining $14.6 million of federal net operating loss may be carried forward indefinitely. The Company has $87.6 million of state net operating losses which expire between 2019 and 2038.

The Company provides for deferred income taxes on the difference between the tax basis of an asset or liability and its carrying amount in the financial statements in accordance FASB ASC Topic 740, “Income Taxes”. This difference will result in taxable income or deductions in future years when the reported amount of the asset or liability is recovered or settled, respectively. In recording deferred tax assets, the Company considers whether it is more likely than not that some portion or all of the deferred income tax asset will be realized. The ultimate realization of deferred income tax assets, if any, is dependent upon the generation of future taxable income during the periods in which those deferred income tax assets would be deductible. Based on the available evidence, the Company has recorded a full valuation allowance against its net deferred tax assets.

19

NOTE 14 – Divestitures and Oil and Gas Asset Sales

In April of 2019, the Company closed on the sale of its Kern County, California properties for approximately $1.7 million in net proceeds. As additional consideration for the sale of the assets, if the WTI index for oil equals or exceeds $65 in the six months following closing and maintains that average for twelve consecutive months, then the buyer shall pay to the Company an additional $250,000. Under the full cost method of accounting, no gain or loss was recognized on the sale. The net proceeds were used for the repayment of borrowings under the credit facility and working capital.

NOTE 15 – Commitments and Contingencies

Joint Development Agreement

On March 27, 2017, the Company entered into a Joint Development Agreement (“JDA”) with two privately held companies, both unaffiliated entities, covering an area of approximately 52 square miles (33,280 acres) in the Permian Basin of Yoakum County, Texas. In connection with the JDA, the Company now holds a 62.5% working interest in approximately 4,626 acres (3,192 net acres) as of June 30, 2019. As the operator of the property covered by the JDA, the Company is committed as of June 30, 2019 to spend an additional $241,104 by March 2020.

Throughput Commitment Agreement

On August 1, 2014, Crimson Energy Partners IV, LLC, as operator of the Company’s Chalktown properties, in which the Company has a working interest, entered into a throughput commitment (the “Commitment”) with ETC Texas Pipeline, Ltd. effective April 1, 2015 for a five-year throughput commitment. In connection with the Commitment, the operator and the Company failed to reach the volume commitments in year two, and the Company anticipates that a shortfall will exist through the expiration of the five-year term, which expires in March 2020. Accordingly, the Company is accruing the expected volume commitment shortfall amounts of approximately $29,000 per month to lease operating expense (“LOE”) based on production, which represents the maximum amounts that could be owed based upon the Commitment. As of June 30, 2019, $86,082 has been recorded in accrued expense for the volume commitment shortfall.

Lease Agreements

The Company determines if an arrangement is a lease at inception of the arrangement. To the extent that the Company determines an arrangement represents a lease, that lease is classified as an operating lease or a finance lease. The Company currently does not have any finance leases. In accordance with ASC Topic 842, operating leases are capitalized on the Company’s Consolidated Balance Sheet through an asset and a corresponding lease liability. Recorded assets represent the Company’s right to use an underlying asset for the lease term and lease liabilities represent its obligation to make lease payments arising from the lease. Short-term leases that have an initial term of one year or less are not capitalized.

The Company’s operating leases are reflected as right-of-use lease assets, accrued liabilities-current and operating lease liabilities on its Consolidated Balance Sheet. Operating lease assets and liabilities are recognized at the commencement date of an arrangement based on the present value of lease payments over the lease term. In addition to the present value of lease payments, the operating lease asset also includes any lease payments made to the lessor prior to lease commencement, less any lease incentives and initial direct costs incurred. Lease expense for operating lease payments is recognized on a straight-line basis over the lease term.

Nature of Leases

The Company leases certain office space, field and other equipment under cancelable and non-cancelable leases to support its operations. A more detailed description of significant lease types is included below.

Office Agreements

The Company rents office space from third parties, structured with non-cancelable terms. The Company has concluded its office agreements represent operating leases with a lease term that equals the primary non-cancelable contract term. Upon completion of the primary term, both parties have substantive rights to terminate the lease. As a result, enforceable rights and obligations do not exist under the rental agreements subsequent to the primary term.

20

Field Equipment and Compressors

The Company rents compressors and other equipment from third parties in order to facilitate the downstream movement of its production from its drilling operations to market, typically structured with a non-cancelable primary term of one to two years, and continuing thereafter on a month-to-month basis subject to termination by either party. These compressors and other equipment are critical to the Company’s ability to sell its production. The Company has therefore concluded that its compressor and other equipment rental agreements represent operating leases with a lease term that extends through the expected life of the field reserves (as opposed to the primary non-cancelable contract term).

The Company enters into daywork contracts for drilling/completion/workover rigs with third parties to support its activities. The Company has concluded that these arrangements represent short-term operating leases. The accounting guidance requires the Company to make an assessment at contract commencement if it is reasonably certain that it will exercise the option to extend the term. The Company has determined that it cannot conclude with reasonable certainty if it will choose to extend the contract beyond its original term.

Significant Judgments

Discount Rate

The Company’s leases typically do not provide an implicit rate. Accordingly, it is required to use its incremental borrowing rate in determining the present value of lease payments based on the information available at commencement date. The Company’s incremental borrowing rate reflects the estimated rate of interest that it would pay to borrow on a collateralized basis over a similar term an amount equal to the lease payments in a similar economic environment.

Practical Expedients and Accounting Policy Elections

Certain of the Company’s lease agreements include lease and non-lease components. For all existing asset classes with multiple component types, the Company has utilized the practical expedient that exempts it from separating lease components from non-lease components. Accordingly, the Company accounts for the lease and non-lease components in an arrangement as a single lease component.

In addition, for all of its existing asset classes, the Company has made an accounting policy election not to apply the lease recognition requirements to its short-term leases (that is, a lease that, at commencement, has a lease term of twelve months or less and does not include an option to purchase the underlying asset that the Company is reasonably certain to exercise). Accordingly, the Company recognizes lease payments related to its short-term leases in its statement of operations on a straight-line basis over the lease term, which has not changed from the prior recognition. To the extent that there are variable lease payments, the Company recognizes those payments in its Statement of Operations in the period in which the obligation for those payments is incurred.

The total lease expense for the three and six months ended June 30, 2019, which is included in general and administrative expense and lease operating expense, was $232,922 and $454,895, respectively.

Supplemental cash flow information related to the Company’s operating leases is included in the table below:

	Six Months Ended
	June 30, 2019
Cash paid for amounts included in the measurement of lease liabilities	$454,895

Supplemental balance sheet information related to operating leases is included in the table below:

	June 30, 2019
Right-of-use lease assets	$4,135,773
Accrued liabilities - current	(838,418)
Operating lease liabilities - long-term	$3,297,355

21

The weighted average remaining lease term for the Company’s operating leases is 6.8 years as of June 30, 2019, with a weighted average discount rate of 10.5%.

Lease liabilities with enforceable contract terms that are greater than one-year mature as follows:

	Operating
	Right-of-use
	Leases
Remainder of 2019	$443,946
2020	865,350
2021	839,613
2022	847,208
2023	751,701
Thereafter	2,344,570
Total lease payments	6,092,388
Less imputed interest	(1,956,615)
Total lease liability	$4,135,773

Certain Legal Proceedings

From time to time, the Company is party to various legal proceedings arising in the ordinary course of business. The Company expenses or accrues legal costs as incurred. A summary of the Company’s legal proceedings is as follows:

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

On May 20, 2015, counsel for Cardno PPI Technology Services, LLC (“Cardno”) 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 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, stating claims for breach of the MSA billing and warranty provisions. On July 15, 2016, Cardno served a Counterclaim for $304,209 plus attorneys’ fees. The parties selected an arbitrator, and the arbitration hearing was held on March 29, April 12 and April 13, 2018. The parties submitted closing statements on April 30, 2018, and the arbitrator issued Final Arbitration Award (the “Award”) on April 4, 2019.

The Award granted the Company a $62,923 credit for Cardno’s improper billing of insurance charges, and a $127,100 credit for Cardno’s billing in excess of the contractual prices. After the credits were applied, Cardno was awarded $114,186 on its claim. The arbitrator also awarded Cardno $23,676 in prejudgment interest. On June 29, 2019, Cardno filed its First Amended Petition to Enforce Liens and on Open Account in the Louisiana proceeding. The amended pleading seeks, among other things, a judgment on the arbitration award.

22

The Parish of St. Bernard v. Atlantic Richfield Co., et al

On October 13, 2016, two subsidiaries of the Company, Yuma Exploration and Production Company, Inc. (“Exploration”) and Yuma Petroleum Company (“YPC”), were named as defendants, among several other defendants, in an action by the Parish of St. Bernard in the Thirty-Fourth Judicial District of Louisiana. The petition alleges violations of the State and Local Coastal Resources Management Act of 1978, as amended, in the St. Bernard Parish.  The Company has notified its insurance carrier of the lawsuit.  Management intends to defend the plaintiffs’ claims vigorously.  The case was removed to federal district court for the Eastern District of Louisiana. A motion to remand was filed and the Court officially remanded the case on July 6, 2017. Exceptions for Exploration, YPC and the other defendants were filed; however, the hearing for such exceptions was continued from the original date of October 6, 2017 to November 22, 2017. The November 22, 2017 hearing was continued without date because the parties agreed the case will be de-cumulated into subcases, but the details of this are yet to be determined. The case was removed again on other grounds on May 23, 2018. On May 25, 2018, a Motion was filed on behalf of certain defendants with the United States Judicial Panel for Multi District Litigation (“JPMDL”) for consolidated proceedings for all 41 pending cases filed in Louisiana with claims that are substantially the same as those in this case. A 42nd case has been added as a “tag-along”. In the interim, plaintiffs timely filed their Motion to Remand in the case. Hearing on the Motion before the JPMDL was held on July 26, 2018 in Santa Fe, New Mexico, and the JPMDL denied centralization by Order dated July 31, 2018. The Order indicates Plaintiffs may be willing to consolidate all cases pending in the Western District with those in the Eastern District, although Defendants may not be amenable to same. That did not occur and this case remained stayed. In the interim, an Order was issued in another of the coastal cases pending in the Eastern District of Louisiana lifting the stay and setting a schedule for briefing for plaintiffs’ motion to remand (Parish of Plaquemines v. Riverwood Production Company, et al., No. 2:18-cv-05217, Eastern District of Louisiana). Judge Martin L. C. Feldman is assigned to the Riverwood case and he will be the first Judge in the Eastern District to decide on the remand, and presumably the Judges assigned to other cases, including this one, will follow his decision as relevant and appropriate. Oral argument on the motion to remand in the Riverwood case has been repeatedly continued, and was finally held on April 10, 2019. Judge Feldman ruled on May 28, 2019, remanding the case. His opinion is 64 pages long and towards the end of the opinion, he notes Defendants have the right to appeal the federal officer issues. Defendants filed a motion to stay the remand pending the appeal and Judge Feldman granted the stay. The Company learned that one of the other Judges in the Eastern District issued an Order administratively closing his cases, and then Judge Barbier issued an Order on June 14, 2019 administratively closing this case pending further Order of the Court. On June 19, 2019, Plaintiffs filed a motion to reopen this case, for lifting of the stay and requesting that the Court set a briefing schedule and a submission date for the motion. Defendants filed an opposition. Judge Barbier summarily denied Plaintiffs’ motion. The Riverwood case is now with the United States Fifth Circuit Court of Appeals, and Defendants/Appellants’ brief is due August 28, 2019. In the interim Plaintiffs/Appellees are fighting the lower court’s stay in the appellate court. It is impossible to predict at this time whether this second removal will keep the case in federal court. At this point in the legal process, no evaluation of the likelihood of an unfavorable outcome or associated economic loss can be made; therefore no liability has been recorded on the Company’s consolidated financial statements.

Cameron Parish vs. BEPCO LP, et al & Cameron Parish vs. Alpine Exploration Companies, Inc., et al

The Parish of Cameron, Louisiana, filed a series of lawsuits against approximately 190 oil and gas companies alleging that the defendants, including Davis Petroleum Acquisition Corp. (“Davis”), have failed to clear, revegetate, detoxify, and restore the mineral and production sites and other areas affected by their operations and activities within certain coastal zone areas to their original condition as required by Louisiana law, and that such defendants are liable to Cameron Parish for damages under certain Louisiana coastal zone laws for such failures; however, the amount of such damages has not been specified. Two of these lawsuits, originally filed February 4, 2016 in the 38th Judicial District Court for the Parish of Cameron, State of Louisiana, name Davis as defendant, along with more than 30 other oil and gas companies. Both cases have been removed to federal district court for the Western District of Louisiana. The Company denies these claims and intends to vigorously defend them. Davis has become a party to the Joint Defense and Cost Sharing Agreements for these cases. Motions to remand were filed and the Magistrate Judge recommended that the cases be remanded. The Company was advised that the new District Judge assigned to these cases is Judge Terry A. Doughty, and on May 9, 2018, Judge Doughty agreed with the Magistrate Judge’s recommendation and the cases were remanded to the 38th Judicial District Court, Cameron Parish, Louisiana. The cases were removed again on other grounds on May 23, 2018. On May 25, 2018, a Motion was filed on behalf of certain defendants with the United States Judicial Panel for Multi District Litigation (“JPMDL”) for consolidated proceedings for all 41 pending cases filed in Louisiana with claims that are substantially the same as those in these cases. A 42nd case has been added as a “tag-along”. In the interim, plaintiffs timely filed their Motion to Remand in the cases. Hearing on the Motion before the JPMDL was held on July 26, 2018 in Santa Fe, New Mexico, and the JPMDL denied centralization by Order dated July 31, 2018. The Order indicates Plaintiffs may be willing to consolidate all cases pending in the Western District with those in the Eastern District, although Defendants may not be amenable to same. That did not occur. On October 1, 2018, all of the coastal cases pending in the Western District of Louisiana, including these cases, were re-assigned to the newly appointed District Judge, Judge Robert R. Summerhays. On August 29, 2018, Magistrate Judge Kay signed an Order providing for staged briefing on the plaintiffs’ motion(s) to remand in all the coastal cases pending in the Western District, with the lowest numbered case (Parish of Cameron v. Auster, No. 18-677, Western District of Louisiana) to proceed first. In response to Defendants’ request for oral argument in the Auster case, Judge Kay issued an electronic Order on October 18, 2018, denying that request and further stating, “The issues have been thoroughly briefed and we do not find at this time that oral argument would be helpful.” As noted above, Magistrate Judge Kay previously recommended remand of these cases, which recommendation was adopted by the District Judge then assigned to the cases. Magistrate Judge Kay issued her Report and Recommendations recommending remand based on the timeliness of the second removal. Objections and replies were filed to the same and the District Judge now assigned to the cases granted and held oral argument on the objections to Magistrate Judge Kay’s Report and Recommendations on January 16, 2019. The District Judge has not yet ruled. In the interim, this Court was apprised by Plaintiffs of Judge Feldman’s Opinion remanding the Riverwood case, and by the relevant Defendants of Judge Feldman’s grant of a stay pending the appeal. It is impossible to predict at this time whether this second removal will keep the cases in federal court. At this point in the legal process, no evaluation of the likelihood of an unfavorable outcome or associated economic loss can be made; therefore no liability has been recorded on the Company’s consolidated financial statements.

23

Louisiana, et al Escheat Tax Audits

During 2015, 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 and is related to the years 2000 through 2015. The Company has engaged Ryan, LLC and is related to the years 2000 through 2015 to represent it in this matter. The exposure related to the audits is not currently determinable and therefore, no liability has been recorded on the Company’s consolidated financial statements.

Louisiana Severance Tax Audit

The State of Louisiana, Department of Revenue, notified Exploration that it was auditing Exploration’s calculation of its severance tax relating to Exploration’s production from November 2012 through March 2016. The audit relates to the Department of Revenue’s recent interpretation of long-standing oil purchase contracts to include a disallowable “transportation deduction,” and thus to assert that the severance tax paid on crude oil sold during the contract term was not properly calculated.  The Department of Revenue sent a proposed assessment in which they sought to impose $476,954 in additional state severance tax plus associated penalties and interest.   Exploration engaged legal counsel to protest the proposed assessment and request a hearing.  Exploration then entered a Joint Defense Group of operators challenging similar audit results.  Since the Joint Defense Group is challenging the same legal theory, the Board of Tax Appeals proposed to hear a motion brought by one of the taxpayers (Avanti) that would address the rule for all through a test case.  Exploration’s case has been stayed pending adjudication of the test case. The hearing for the Avanti test case was held on November 7, 2017, and on December 6, 2017, the Board of Tax Appeals rendered judgment in favor of the taxpayer in the first of these cases. The Department of Revenue filed an appeal to this decision on January 5, 2018. The Board of Tax Appeals case record has been lodged at the Louisiana Third Circuit Court of Appeal in the Avanti test case. Oral argument was held at the Third Circuit on February 26, 2019. On April 17, 2019, the Louisiana Third Circuit Court of Appeal rendered a unanimous decision in the Avanti case affirming the Board of Tax Appeals decision for the taxpayer. The Louisiana Department of Revenue did not appeal the Avanti case, which is now a final decision. The Department of Revenue has dropped its opposition to the normal standard methodology crude oil producers were using in reporting their Louisiana severance taxes. This assessment for Exploration, to the extent it involves only the crude oil pricing issue (i.e., the transportation deduction issue), is expected to be vacated, and the appeal by Exploration can be dismissed.

Louisiana Department of Wildlife and Fisheries

The Company received notice from the Louisiana Department of Wildlife and Fisheries (“LDWF”) in July 2017 stating that Exploration has open Coastal Use Permits (“CUPs”) located within the Louisiana Public Oyster Seed Grounds dating back from as early as November 1993 and through a period ending in November 2012.  The majority of the claims relate to permits that were filed from 2000 to 2005.  Pursuant to the conditions of each CUP, LDWF is alleging that damages were caused to the oyster seed grounds and that compensation of an aggregate amount of approximately $500,000 is owed by the Company.  The Company is currently evaluating the merits of the claim, is reviewing the LDWF analysis, and has now requested that the LDWF revise downward the amount of area their claims of damages pertain to. At this point in the regulatory process, no evaluation of the likelihood of an unfavorable outcome or associated economic loss can be made; therefore no liability has been recorded on the Company’s consolidated financial statements.

Miami Corporation – South Pecan Lake Field Area P&A

The Company, along with several other exploration and production companies in the chain of title, received letters in June 2017 from representatives of Miami Corporation demanding the performance of well plugging and abandonment, facility removal and restoration obligations for wells in the South Pecan Lake Field Area, Cameron Parish, Louisiana. Apache is one of the other companies in the chain of title, and after taking a field tour of the area, has sent to the Company, along with BP and other companies in the chain of title, a proposed work plan to comply with the Miami Corporation demand. The Company is currently evaluating the merits of the claim and awaiting further information. At this point in the process, no evaluation of the likelihood of an unfavorable outcome or associated economic loss can be made; therefore no liability has been recorded on the Company’s consolidated financial statements.

John Hoffman v. Yuma Exploration & Production Company, Inc., et al

This lawsuit, filed on June 15, 2018 in Livingston Parish, Louisiana, against the Company, Precision Drilling and Dynamic Offshore relates to a slip and fall injury to Mr. Hoffman that occurred on August 28, 2017. Mr. Hoffman was apparently an employee of a subcontractor of a contractor performing services for the Company. Precision has made demand for defense and indemnity against the Company based on a contract entered into between the parties. The defense and indemnity demand is being contested, primarily on the grounds that the defense and indemnity obligation is barred by the Louisiana Anti-Indemnity Act. The Company believes that its contractor is responsible for injuries to employees of the contractor or subcontractor and that their insurance coverage, or insurance coverage maintained by the Company, should cover damages awarded to Mr. Hoffman. The Company has notified its insurance carrier of the lawsuit. Counsel believes that the claim will be successfully defended, but even if the defense and indemnity claim is legally enforceable, there is sufficient insurance in place to cover the exposure. Accordingly, the defense and indemnity claim does not represent any direct material exposure to the Company.

24

Hall-Degravelles, L.L.C. v. Cockrell Oil Corporation, et al

Avalon Plantation, Inc., et al v. Devon Energy Production Company, L.P., et al

Avalon Plantation, Inc., et al v. American Midstream, et al

The Company, as a successor in interest from another company years ago, along with 41 other companies in the chain of title, was named as a defendant in these lawsuits brought in St. Mary Parish, Louisiana. The substance of each of the petitions is virtually identical. In each case, the plaintiff(s) are seeking to recover damages to their property resulting from “oil and gas exploration and production activities.” The cited grounds for these actions include La. R.S. 30:29 (providing for restoration of property affected by oilfield contamination) and C.C. art. 2688 (notification by the lessee to the lessor when leased property is damaged). The plaintiffs have attempted to have these three cases consolidated. A hearing on motion to consolidate was held on January 15, 2019. At that time, Judge Sigur stated from the bench that he did not have sufficient information to order consolidation. A judgment to that effect has been signed by the judge. These cases are in the very early stages. At this point, not all of the named defendants have filed responsive pleadings. All of the defendants who have responded at this point have, inter alia, filed exceptions of vagueness due to the lack of specificity in the petitions which makes it impossible to determine what action(s) any individual defendant may have performed which would result in liability to the plaintiffs. None of these exceptions are currently set for hearing. The plaintiffs recently filed amended petitions which do not change the substance of their claims. The plaintiffs requested that service of these amended petitions be withheld. The Company sold the leases that appear to be involved in this litigation to Hilcorp Energy I, L.P. (“Hilcorp”), with an effective date of September 1, 2016. The conveyance includes an indemnity provision which appears to transfer liability for this type of damage to Hilcorp, and at some point it may be necessary to invoke this indemnity. The Company has notified its insurance carrier of the claim but believes that the suit is without merit. No evaluation of the likelihood of an unfavorable outcome or associated economic loss can be made at this early stage, therefore no liability has been recorded on the Company’s consolidated financial statements.

Vintage Assets, Inc. v. Tennessee Gas Pipeline, L.L.C., et al

On September 10, 2018, the Company received a Demand for Defense and Indemnity from High Point Gas Gathering, L.P. (HPGG) pursuant to the 2010 Purchase and Sale Agreement between Texas Southeastern Gas Gathering Company, et al and HPGG, et al. The demand related to a judgment and permanent injunction entered against HPGG and three other defendants on May 4, 2018 in the above referenced matter in the U.S. District Court in the Eastern District of Louisiana. The Company received a letter dated October 30, 2018 from HPGG informing it that the May 4, 2018 judgment had been vacated. No evaluation of the likelihood of an unfavorable outcome or associated economic loss can be made at this early stage, therefore, no liability has been recorded on Company’s consolidated financial statements.

Texas General Land Office (“GLO”)

On February 21, 2019, the GLO notified the Company that it would be conducting an audit of oil and gas production and royalty revenue for the period of September 2012 to August 2017 related to three of the Company’s leases located in Chambers County, Texas and four of the Company’s leases located in Jefferson County, Texas. The exposure related to the audit is not currently determinable and therefore, no liability has been recorded on the Company’s consolidated financial statements.

Sam Banks v. Yuma Energy, Inc.

By letter dated March 27, 2019, the Company’s Board of Directors notified Sam L. Banks that it was terminating him as Chief Executive Officer of the Company pursuant to the terms of his amended and restated employment agreement dated April 20, 2017 (the “Employment Agreement”). On April 22, 2019, Mr. Banks submitted his resignation from the board of directors of the Company. On March 28, 2019, Mr. Banks, through his legal counsel, filed a petition (the “Petition”) in the 189th Judicial District Court of Harris County, Texas, naming the Company as defendant. The Petition alleges a breach of the Employment Agreement and seeks severance benefits in the amount of approximately $2.15 million. The Company denies his allegations. The Company’s retained counsel has engaged in early settlement discussions with Plaintiff’s counsel, but at this time, a settlement has not been reached. Counsel for the Company has filed an answer in response to Mr. Banks’ lawsuit, and discovery is proceeding. The Company intends to vigorously defend the lawsuit. No evaluation of the likelihood of an unfavorable outcome or associated economic loss can be made at this early stage; therefore, no liability has been recorded on the Company’s consolidated financial statements.

Allison Renee Romero and M.A. Domatti Management Trust v. Yuma Energy, Inc. and Davis Petroleum Corp.

This lawsuit, filed on May 21, 2019 in Cameron Parish, Louisiana against Yuma and Davis Petroleum Corp. (“DPC”), alleges that Yuma and DPC contaminated and otherwise damaged two 80-acre parcels owned by the plaintiffs as the result of Yuma’s and DPC’s activities related to an oil and gas intrastate field flowline located on the parcels. The suit alleges that Yuma’s and DPC’s operation of the flowline, and its ruptures, caused extensive soil and groundwater contamination of the two parcels. The suit asks for the costs of restoration, damages for diminution of the properties’ value and punitive damages, among other things.

This matter has been referred to the Company’s insurance company. The Company believes, and has so informed the insurance company’s counsel handling the case, that it has already remediated the contamination complained of, in accordance with the State of Louisiana regulations. Because the matter is in a very preliminary stage, the Company cannot evaluate the likelihood of an unfavorable outcome or whether any liability would be covered by its insurance policy; as a result, no liability has been recorded on the Company’s consolidated financial statements.

25

NOTE 16 – Subsequent Events

The Company is not aware of any subsequent events which would require recognition or disclosure in its consolidated financial statements, except as disclosed in the Company’s filings with the SEC.

Item 2.

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

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with the accompanying unaudited consolidated financial statements and related notes thereto, included in Part I, Item 1 of this Quarterly Report on Form 10-Q and should further be read in conjunction with our Annual Report on Form 10-K for the year ended December 31, 2018.

Statements in this discussion may be forward-looking. These forward-looking statements involve risks and uncertainties, including those discussed below, which cause actual results to differ from those expressed. For more information, see “Cautionary Statement Regarding Forward-Looking Statements” in Item 1 above.

Overview

Yuma Energy, Inc., a Delaware corporation (“Yuma” and collectively with its subsidiaries, the “Company,” “we,” “us” and “our”), is an independent Houston-based exploration and production company focused on acquiring, developing and exploring for conventional and unconventional oil and natural gas resources. Historically, our operations have focused on onshore properties located in central and southern Louisiana and southeastern Texas where we have a long history of drilling, developing and producing both oil and natural gas assets. We also have acreage in the Permian Basin of West Texas (Yoakum County, Texas), with the potential for additional oil and natural gas reserves. Finally, we have non-operated positions in the East Texas Woodbine. Our common stock is listed on the NYSE American under the trading symbol “YUMA.”

Reverse Stock Split

On July 3, 2019, we effected a reverse stock split where one share of common stock, $0.001 par value per share, was issued for fifteen shares of common stock, $0.001 par value per share. The reverse stock split resulted in 1,551,989 shares of common stock, $0.001 par value per share, issued and outstanding and this change has been retroactively stated in the financial statements for the quarter ended June 30, 2019.

Senior Credit Agreement and Going Concern

The factors and uncertainties described below, as well as other factors which include, but are not limited to, declines in our production, reduction of personnel, our failure to establish commercial production on our Permian properties, and our substantial working capital deficit of approximately $41.0 million, raise substantial doubt about our ability to continue as a going concern for the twelve months following the issuance of these financial statements. 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.

On October 26, 2016, the Company and three of its subsidiaries, as the co-borrowers, entered into a credit agreement providing for a $75.0 million three-year senior secured revolving credit facility (the “Credit Agreement”) with Société Générale (“SocGen”), as administrative agent, SG Americas Securities, LLC, as lead arranger and bookrunner, and the lenders signatory thereto (collectively with SocGen, the “Lender”).

26

The borrowing base of the credit facility was $32.8 million as of June 30, 2019, and the Company was, and is, fully drawn under the credit facility leaving no availability on the line of credit. All of the obligations under the Credit Agreement, and the guarantees of those obligations, are secured by substantially all of our assets.

The Credit Agreement contains a number of covenants that, among other things, restrict, subject to certain exceptions, our ability to incur additional indebtedness, create liens on assets, make investments, enter into sale and leaseback transactions, pay dividends and distributions or repurchase our capital stock, engage in mergers or consolidations, sell certain assets, sell or discount any notes receivable or accounts receivable, and engage in certain transactions with affiliates.

In addition, the Credit Agreement requires us to maintain certain financial covenants and contains customary affirmative covenants and defines events of default for credit facilities of this type. At June 30, 2019, we were not in compliance with these covenants under the credit facility, as fully described in Note 2 – Liquidity and Going Concern in the Notes to the Unaudited Consolidated Financial statements included in Part I of this report.

Sale of California Properties

On April 26, 2019 and effective April 1, 2019, we sold all of our properties in Kern County, California for net proceeds of approximately $1.7 million. As additional consideration for the sale of the assets, if the WTI Index for oil equals or exceeds $65 in the six months following the closing and maintains that average for twelve consecutive months then the buyer agrees to pay us an additional $250,000. The net proceeds were applied to the repayment of borrowings under the credit facility and working capital.

Preferred Stock

As of June 30, 2019, we had 2,112,710 shares of our Series D preferred stock outstanding with an aggregate liquidation preference of approximately $23.4 million and a conversion price of $98.7571635 per share. If all of our outstanding shares of Series D preferred stock were converted into common stock, we would need to issue approximately 236,900 shares of common stock. The Series D preferred stock is paid dividends in the form of additional shares of Series D preferred stock at a rate of 7% per annum (cumulative).

Results of Operations

Production

The following table presents the net quantities of oil, natural gas and natural gas liquids produced and sold by us for the three and six months ended June 30, 2019 and 2018, and the average sales price per unit sold.

	Three Months Ended June 30,		Six Months Ended June 30,
	2019	2018	2019	2018
Production volumes:
Crude oil and condensate (Bbls)	15,683	47,322	52,342	94,479
Natural gas (Mcf)	179,396	538,241	557,699	1,171,681
Natural gas liquids (Bbls)	8,291	28,974	31,879	54,217
Total (Boe) (1)	53,873	166,003	177,171	343,976
Average prices realized:
Crude oil and condensate (per Bbl)	$68.97	$67.69	$62.68	$66.36
Natural gas (per Mcf)	$2.20	$3.30	$2.83	$3.04
Natural gas liquids (per Bbl)	$23.19	$29.11	$24.83	$30.09

(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).

27

Revenues

The following table presents our revenues for the three and six months ended June 30, 2019 and 2018.

	Three Months Ended June 30,		Six Months Ended June 30,
	2019	2018	2019	2018
Sales of natural gas and crude oil:
Crude oil and condensate	$1,081,674	$3,203,260	$3,280,696	$6,269,517
Natural gas	395,494	1,775,919	1,575,903	3,567,170
Natural gas liquids	192,248	843,398	791,494	1,631,426
Total revenues	$1,669,416	$5,822,577	$5,648,093	$11,468,113

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 customary industry spot prices. Pricing for our California properties (sold in April 2019) is based on an average of specified posted prices, adjusted for gravity and transportation.

Crude oil volumes sold were 66.9%, or 31,6391 Bbls, lower for the three months ended June 30, 2019, compared to crude oil volumes sold during the three months ended June 30, 2018, due primarily to decreases from the Livingston Field (2,700 Bbls) due to a malfunctioning ESP pump which was replaced with a jet pump in June 2019, the La Posada Field (5,200 Bbls) due to the shut in of Thibodeaux #1 and salt water disposal issues that were corrected in July 2019, the Lac Blanc Field (4,100 Bbls) due to a hole in production tubing in LP well #2 and a reduced rate from the LP #1, the Cameron Canal Field (3,000 Bbls) due to sanding up and the subsequent shut in of EE Broussard, and the Main Pass 4 Field (1,500 Bbls) due to the shut in of SL 18194 #1 to repair a hole in the casing. Realized crude oil prices experienced a 1.9% increase for the three months ended June 30, 2019, compared to the three months ended June 30, 2018.

Crude oil volumes sold were 44.6%, or 42,137 Bbls, lower for the six months ended June 30, 2019, compared to crude oil volumes sold during the six months ended June 30, 2018, due primarily to decreases from the Livingston Field (5,100 Bbls) due to a malfunctioning ESP pump which was replaced with a jet pump in June 2019, the La Posada Field (7,400 Bbls) due to the shut in of Thibodeaux #1 and salt water disposal issues that were corrected in July 2019, the Lac Blanc Field (5,100 Bbls) due to a hole in production tubing in LP well #2, the Cameron Canal Field (4,100 Bbls) due to sanding up and the subsequent shut in of EE Broussard, and the Main Pass 4 Field (1,500 Bbls) due to the shut in of SL 18194 #1 to repair a hole in the casing. Realized crude oil prices experienced a 5.5% decrease for the six months ended June 30, 2019, compared to the six months ended June 30, 2018.

Sale of Natural Gas and Natural Gas Liquids

Our natural gas is sold under month-to-month contracts with pricing tied to either first of the month index or a monthly weighted average of purchaser prices received. Natural gas liquids are sold under month-to-month or year-to-year contracts usually tied to the related natural gas contract. Pricing is based on published prices for each product or a monthly weighted average of purchaser prices received.

For the three months ended June 30, 2019 compared to the three months ended June 30, 2018, we experienced a 66.7%, or 358,845 Mcf, decrease in natural gas volumes sold, and a decrease in natural gas liquids sold of 71.4%, or 20,683 Bbls. The decreases were due primarily to decreases from the La Posada Field (219,000 Mcf), the Lac Blanc Field (40,000 Mcf), and the Cameron Canal Field (65,000 Mcf) due to the reasons listed above. During the same period, realized natural gas prices decreased by 33.3%, and realized natural gas liquids prices decreased by 20.3%.

For the six months ended June 30, 2019 compared to the six months ended June 30, 2018, we experienced a 52.4%, or 613,982 Mcf, decrease in natural gas volumes sold, and a decrease in natural gas liquids sold of 41.2%, or 22,338 Bbls. The decreases were due primarily to decreases from the La Posada Field (341,000 Mcf), the Lac Blanc Field (104,000 Mcf), and the Cameron Canal Field (105,000 Mcf) due to the reasons listed above. During the same period, realized natural gas prices decreased by 6.9%, and realized natural gas liquids prices decreased by 17.5%.

28

Expenses

Lease Operating Expenses

Our lease operating expenses (“LOE”) and LOE per Boe for the three and six months ended June 30, 2019 and 2018, are set forth below:

	Three Months Ended June 30,		Six Months Ended June 30,
	2019	2018	2019	2018
Lease operating expenses	$1,585,564	$1,890,809	$3,093,039	$3,556,129
Severance, ad valorem taxes and
marketing	417,632	905,016	1,201,474	1,865,464
Total LOE	$2,003,196	$2,795,825	$4,294,513	$5,421,593
LOE per Boe	$37.18	$16.84	$24.24	$15.76
LOE per Boe without severance,
ad valorem taxes and marketing	$29.43	$11.39	$17.46	$10.34

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.

The 28.4% decrease in total LOE for the three months ended June 30, 2019, compared to the three months ended June 30, 2018 was due to a $487,384 decrease in severance, ad valorem, and marketing, and a $305,245 decrease in lease operating expense. The decreases in marketing and operating costs were primarily due to lower natural gas and NGL sales. LOE per barrel of oil equivalent increased by 120.8% from the same period of the prior year generally due to the decrease in volumes noted above.

The 20.8% decrease in total LOE for the six months ended June 30, 2019, compared to the six months ended June 30, 2018 was due to a $663,989 decrease in severance, ad valorem, and marketing, and a $463,090 decrease in lease operating expense. The decreases in marketing and operating costs were primarily due to lower natural gas and NGL sales. LOE per barrel of oil equivalent increased by 53.9% from the same period of the prior year generally due to the decrease in volumes noted above.

General and Administrative Expenses

Our general and administrative (“G&A”) expenses for the three and six months ended June 30, 2019 and 2018, are summarized as follows:

	Three Months Ended June 30,		Six Months Ended June 30,
	2019	2018	2019	2018
General and administrative:
Stock-based compensation	$(27,086)	$64,230	$(143,153)	$360,524
Other	1,509,357	1,853,316	3,048,454	3,980,513
Capitalized	-	(265,688)	-	(643,647)
Net other	1,509,357	1,587,628	3,048,454	3,336,866
Net general and administrative expenses	$1,482,271	$1,651,858	$2,900,301	$3,697,390

29

G&A Other primarily consists of overhead expenses, employee remuneration and professional and consulting fees. We capitalize certain G&A expenditures relating to oil and natural gas acquisition, exploration and development activities following the full cost method of accounting. During the second half of 2018, we stopped capitalizing overhead due to the departure of our exploration staff and a lack of development activity.

For the three months ended June 30, 2019, net G&A expenses were 10.3%, or $169,587, lower than the amount for the same period in 2018. Variances include a decrease in salaries and stock-based compensation of $381,047 and $104,871, respectively, and a decrease in termination benefits of $169,825, offset by an increase in consulting fees of $467,765. The decrease in stock-based compensation was primarily a result of the reevaluation of liability-based Stock Appreciation Rights and the forfeiture of various stock awards since the prior period.

For the six months ended June 30, 2019, net G&A expenses were 21.6%, or $797,089, lower than the amount for the same period in 2018. Variances include a decrease in accounting and audit fees of $121,233, a decrease in directors’ fees of $127,500, a decrease in salaries and stock-based compensation of $540,919 and $553,203, respectively, and a decrease in termination benefits of $169,825, offset by an increase in consulting fees of $627,189. The decrease in stock-based compensation was primarily a result of the reevaluation of liability-based Stock Appreciation Rights and the forfeiture of various stock awards since the prior period.

Depreciation, Depletion and Amortization

Our depreciation, depletion and amortization (“DD&A”) for oil and gas properties (excluding DD&A related to other property, plant and equipment) for the three and six months ended June 30, 2019 and 2018, is summarized as follows:

	Three Months Ended June 30,		Six Months Ended June 30,
	2019	2018	2019	2018
DD&A	$666,576	$2,204,936	$2,536,797	$4,382,023
DD&A per Boe	$12.37	$13.28	$14.32	$12.74

DD&A decreased by 69.8% and 42.1%, respectively, for the three and six months ended June 30, 2019 compared to the same periods in 2018, primarily as a result of the decrease in the net quantities of crude oil and natural gas sold.

Impairment of Oil and Natural Gas Properties

We utilize the full cost method of accounting to account for our oil and natural gas exploration and development activities. Under this method of accounting, we are required on a quarterly basis to determine whether the book value of our oil and natural gas properties (excluding unevaluated properties) is less than or equal to the “ceiling,” based upon the expected after tax present value (discounted at 10%) of the future net cash flows from our proved reserves, excluding gains or losses from derivatives. Any excess of the net book value of our oil and natural gas properties over the ceiling must be recognized as a non-cash impairment expense. Based on a thorough analysis of the Company’s assets, the major contribution for an impairment for the second quarter of fiscal year 2019 is the decrease in the 12 month rolling SEC prices used at June 30, 2019. As a result of this review, the Company recorded a full cost ceiling impairment charge of $0.4 million during the three-month period ended June 30, 2019. The Company recorded a full cost ceiling impairment charges of $11.8 million for the six-month period ended June 30, 2019. During the three and six-month periods ended June 30, 2018, the Company did not record any full cost ceiling impairments. Changes in production rates, levels of reserves, future development costs, transfers of unevaluated properties, and other factors will determine our actual ceiling test calculation and impairment analyses in future periods.

Interest Expense

Our interest expense for the three and six months ended June 30, 2019 and 2018, is summarized as follows:

	Three Months Ended June 30,		Six Months Ended June 30,
	2019	2018	2019	2018
Interest expense	$578,537	$585,866	$1,134,805	$1,167,699
Interest capitalized	-	(18,231)	-	(133,772)
Net	$578,537	$567,635	$1,134,805	$1,033,927
Bank debt	$32,805,518	$35,000,000	$32,805,518	$35,000,000

Interest expense (net of amounts capitalized) decreased $7,329 and $32,893, respectively, for the three and six months ended June 30, 2019 over the same periods in 2018 as a result of lower amounts outstanding under our credit facility during the three and six months ended June 30, 2019, and no capitalized interest in the three and six months ended June 30, 2019, compared to the same period in 2018.

For a more complete narrative of interest expense, and terms of our credit agreement, refer to Note 10 – Debt and Interest Expense in the Notes to the Unaudited Consolidated Financial Statements included in Part I of this report.

30

Income Tax Expense

The following summarizes our income tax expense (benefit) and effective tax rates for the three and six months ended June 30, 2019 and 2018:

	Three Months Ended June 30,		Six Months Ended June 30,
	2019	2018	2019	2018
Consolidated net income (loss)
before income taxes	$(3,564,986)	$(4,030,385)	$(19,215,688)	$(7,203,306)
Income tax expense (benefit)	$-	$-	$-	$-
Effective tax rate	0.00%	0.00%	0.00%	0.00%

Differences between the U.S. federal statutory rate of 21% in 2019 and 2018 and our effective tax rates are due to the tax effects of valuation allowances recorded against our deferred tax assets and state income taxes. Refer to Note 13 – Income Taxes in the Notes to the Unaudited Consolidated Financial Statements included in Part I of this report.

Liquidity and Capital Resources

The factors and uncertainties described below raise substantial doubt about our ability to continue as a going concern. Our primary and potential sources of liquidity include cash on hand, cash from operating activities, proceeds from the sales of assets, and potential proceeds from capital market transactions, including the sale of debt and equity securities. Our cash flows from operating activities are subject to significant volatility due to changes in commodity prices, as well as variations in our production and we are currently unhedged on our oil and gas production. We incurred net losses attributable to common shareholders for the years ended December 31, 2018 and 2017 and for the first two quarters of 2019. At June 30, 2019, our total current liabilities exceed our total current assets. Additionally, we are in violation of our debt covenants, have suspended paying interest under our credit facility to conserve cash, have extremely limited liquidity and have suffered recurring losses from operations. In addition, we are subject to a number of factors that are beyond our control, including commodity prices, production declines and other factors that could affect our liquidity and ability to continue as a going concern.

We have recently experienced a number of mechanical issues on well sites including the Lac Blanc #2, and others that are impacting our rates of production and hence having a negative impact on our operating cash flow. Field level operating cash flows prior to these issues were approximately $750,000 per month and currently projected to be approximately $400,000 assuming no repairs take place. We are planning on certain repairs costing an estimated $500,000 that, if successful, should return positve field level operating cash flows. While we anticipate returning a number of these wells to production, for others, like the Lac Blanc LP #2, repair cost estimates could be significant and there is no assurance we can fund the work based on our current severe liquidity constraints, which will result in a loss of an estimated $150,000 per month of field level cash flow. Actual results could differ from these estimates, and the differences could be significant, as we continue to evaluate.

We are currently in default under our credit facility due to non-compliance with our financial covenants and failure to pay interest. As of June 30, 2019, we had fully drawn the $32.8 million available under our credit facility. On October 9, 2018, we received a notice and reservation of rights from the administrative agent under our Credit Agreement advising that an event of default has occurred and continues to exist by reason of our noncompliance with the liquidity covenant requiring us to maintain cash and cash equivalents and borrowing base availability of at least $4.0 million. As a result of the default, the Lender may accelerate the outstanding balance under the Credit Agreement, increase the applicable interest rate by 2.0% per annum or commence foreclosure on the collateral securing the loans. As of the date of this report, the Lender has not accelerated the outstanding amount due and payable on the loans, increased the applicable interest rate or commenced foreclosure proceedings, but they may exercise one or more of these remedies in the future. We have commenced discussions with the Lender under the Credit Agreement concerning a forbearance agreement or waiver of the events of default; however, there can be no assurance that we and the Lender will come to any agreement regarding a forbearance or waiver of the events of default.

During the first quarter of 2019, we agreed to sell our Kern County, California properties for $2.1 million in gross proceeds and the buyer’s assumption of certain plugging and abandonment liabilities of approximately $864,000. We closed this sale on April 26, 2019 and received net proceeds of approximately $1.7 million. As additional consideration for the sale of the assets, if WTI Index for oil equals or exceeds $65 in the six months following closing and maintains that average for twelve consecutive months then buyer agreed to pay us an additional $250,000. The net proceeds were applied to the repayment of borrowings under the credit facility and working capital.

We have initiated several strategic alternatives to mitigate our limited liquidity (defined as cash on hand and undrawn borrowing base), our financial covenant compliance issues, and to provide us with additional working capital to develop our existing assets.

During the last quarter of 2018, we retained Seaport Global Securities LLC (“Seaport”) as our exclusive financial advisor and investment banker in connection with identifying and potentially implementing various strategic alternatives to improve our liquidity issues and the possible disposition, acquisition or merger of the Company or our assets. In addition, prior to the retention of Seaport, we retained Energy Advisors Group to sell select properties of the Company. On March 1, 2019, we hired a Chief Restructuring Officer, and subsequently on March 28, 2019, appointed that person Interim Chief Executive Officer.

31

We plan to take further steps to mitigate our limited liquidity, which may include, but are not limited to, restructuring our existing debt; selling additional assets; further reducing general and administrative expenses; seeking merger and acquisition related opportunities; and potentially raising proceeds from capital markets transactions, including the sale of debt or equity securities. There can be no assurance that the exploration of strategic alternatives will result in a transaction or otherwise improve our limited liquidity.

The factors and uncertainties described in Note 2 – Liquidity and Going Concern in the Notes to the Unaudited Consolidated Financial Statements included in Part I of this report raise substantial doubt about our ability to continue as a going concern.

Cash Flows from Operating Activities

Net cash used in operating activities was $63,963 for the six months ended June 30, 2019, compared to net cash provided by operating activities of $3,063,719 during the same period in 2018. This decrease was primarily caused by a decrease in revenue as a result of decreased production.

One of the primary sources of variability in our cash flows from operating activities is fluctuations in volumes and commodity prices. Sales volume changes also impact cash flow. Our cash flows from operating activities are also dependent on the costs related to continued operations.

Cash Flows from Investing Activities

During the six months ended June 30, 2019, cash provided by investing activities totaled $1,336,767, primarily from the proceeds from the sale of certain oil and gas facilities of $1,691,588, offset by the payment of net capital expenditures of $308,464.

Cash Flows from Financing Activities

We expect to finance future development activities through available working capital, cash flows from operating activities, sale of non-strategic assets, and the possible issuance of additional equity/debt securities. In addition, we may slow or accelerate the development of our properties to more closely match our projected cash flows.

During the six months ended June 30, 2019, we had net cash used in financing activities of $1,939,381. Of that amount, $1,945 of treasury stock was repurchased in connection with the satisfaction of tax obligations upon the vesting of employees’ restricted stock awards, and $742,953 was used for payments on our insurance financing. In addition, we had repayments of long-term debt of $1,194,482, from proceeds from the sale of our Kern County, California properties.

As of June 30, 2019, we had no remaining availability on our credit facility. We had a cash balance of $967,915 at June 30, 2019.

Hedging Activities

Current Commodity Derivative Contracts

Historically, we have sought to reduce our sensitivity to oil and natural 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. There are no commodity derivative instruments open as of June 30, 2019.

As required under the Credit Agreement, we previously entered into hedging arrangements with SocGen and BP pursuant to ISDA Agreements. On March 14, 2019, we received a notice of an event of default under our SocGen ISDA. Due to the default under the SocGen ISDA, SocGen unwound all of our hedges with them. The notice provides for a payment of $335,252 to settle our outstanding obligations thereunder related to SocGen’s hedges. On March 19, 2019, we received a notice of an event of default under our BP ISDA. Due to the default under the ISDA Agreement, BP also unwound all of our hedges with them. The notice provides for a payment of $749,240 to settle our outstanding obligations thereunder related to BP’s hedges. These amounts are included in current maturities of debt at June 30, 2019.

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).

32

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 Interim Chief Executive Officer and Interim Chief Financial Officer, 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, 2019, we carried out an evaluation, under the supervision and with the participation of our management, including our Interim Chief Executive Officer and Interim Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Exchange Act Rule 13a-15(e)). Based on that evaluation, our Interim Chief Executive Officer and Interim Chief Financial Officer concluded that, as of June 30, 2019 our disclosure controls and procedures were effective.

Changes in internal control over financial reporting.

During the three month period ended June 30, 2019, there were no changes in our internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

33

PART II. OTHER INFORMATION

Item 1.    Legal Proceedings.

From time to time, we are a party to various legal proceedings arising in the ordinary course of business. While the outcome of these matters cannot be predicted with certainty, we are not currently a party to any proceeding that we believe, if determined in a manner adverse to us, could have a potential material adverse effect on our financial condition, results of operations, or cash flows. See Note 15 – Commitments and Contingencies in the Notes to the Unaudited Consolidated Financial Statements under Part I, Item 1 of this report, which is incorporated herein by reference, for a discussion of our legal proceedings.

Item 1A.    Risk Factors.

In addition to the other information set forth in this report, you should carefully consider the factors discussed in Part 1, “Item 1A – Risk Factors” in our Annual Report for the year ended December 31, 2018 on Form 10-K, which could materially affect our business, financial condition or future results. The risks described in our 2018 Annual Report on Form 10-K may not be the only risks facing our Company. There are no material changes to the risk factors as disclosed in our Annual Report on Form 10-K for the year ended December 31, 2018, except as set forth below. 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.

The Consolidated Financial Statements included herein contain disclosures that express substantial doubt about our ability to continue as a going concern, indicating the possibility that we may not be able to operate in the future.

The consolidated financial statements included herein have been prepared on a going concern basis, which assumes that we will continue to operate in the future in the normal course of business. Recently, our liquidity and ability to maintain compliance with certain financial ratios and covenants in our Credit Agreement have been negatively impacted by several factors, including drilling activities and other factors. Due to operating losses we sustained during recent quarters, at June 30, 2019 we were not in compliance under our credit facility with the (i) total debt to EBITDAX covenant for the trailing four quarter period, (ii) current ratio covenant, (iii) EBITDAX to interest expense covenant for the trailing four quarter period, (iv) the liquidity covenant requiring us to maintain unrestricted cash and borrowing base availability of at least $4.0 million, and (v) obligation to make an interest only payment for the quarters ended December 31, 2018 and June 30, 2019. Due to this non-compliance, we classified our entire bank debt as a current liability in our Consolidated Financial Statements as of June 30, 2019. On October 9, 2018, we received a notice and reservation of rights from the administrative agent under our Credit Agreement advising that an event of default has occurred and continues to exist by reason of our noncompliance with the liquidity covenant requiring us to maintain cash and cash equivalents and borrowing base availability of at least $4.0 million. As a result of the default, the Lender may accelerate the outstanding balance under the Credit Agreement, increase the applicable interest rate by 2.0% per annum or commence foreclosure on the collateral securing the loans. As of the date of this report, the Lender has not accelerated the outstanding amount due and payable on the loans, increased the applicable interest rate or commenced foreclosure proceedings, but they may exercise one or more of these remedies in the future. We have commenced discussions with the Lender under the Credit Agreement concerning a forbearance agreement or waiver of the event of default; however, there can be no assurance that we and the Lender will come to any agreement regarding a forbearance or waiver of the event of default.

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

None.

Item 3.    Defaults upon Senior Securities.

None.

Item 4.     Mine Safety Disclosures.

Not Applicable.

Item 5.     Other Information.

None.

34

Item 6.       Exhibits.

EXHIBIT INDEX

FOR

Form 10-Q for the quarter ended June 30, 2019.
		Incorporated by Reference
Exhibit No.	Description	Form	SEC File No.	Exhibit	Filing Date	Filed Herewith	Furnished Herewith
10.1	Letter Agreement dated July 1, 2019 between Yuma Energy, Inc. and Anthony C. Schnur.					X
31.1	Certification of the Principal Executive Officer and Principal Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act.					X
32.1	Certification of the Interim Chief Executive Officer and Interim Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act.						X
101.INS	XBRL Instance Document.					X
101.SCH	XBRL Schema Document.					X
101.CAL	XBRL Calculation Linkbase Document.					X
101.DEF	XBRL Definition Linkbase Document.					X
101.LAB	XBRL Label Linkbase Document.					X
101.PRE	XBRL Presentation Linkbase Document.					X

35

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/ Anthony C. Schnur
	Name:	Anthony C. Schnur
Date: August 16, 2019	Title:	Interim Chief Executive Officer (Principal Executive Officer), Interim Chief Financial Officer (Principal Accounting Officer) and Chief Restructuring Officer

36