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, 2018

☐ 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 and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ☒   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.

Large accelerated filer	☐	Accelerated filer	☐
Non-accelerated filer	☐ (Do not check if a smaller reporting company)	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 ☒

At August 9, 2018, 23,243,763 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)		5
		Consolidated Balance Sheets as of June 30, 2018 and December 31, 2017	5
		Consolidated Statements of Operations for the Three and Six Months Ended June 30, 2018 and 2017	7
		Consolidated Statement of Changes in Equity for the Six Months Ended June 30, 2018	8
		Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2018 and 2017	9
		Notes to the Unaudited Consolidated Financial Statements	10
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		27
Item 3.	Quantitative and Qualitative Disclosures About Market Risk		36
Item 4.	Controls and Procedures		36
	PART II – OTHER INFORMATION
Item 1.	Legal Proceedings		37
Item 1A.	Risk Factors		37
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		37
Item 3.	Defaults Upon Senior Securities		37
Item 4.	Mine Safety Disclosures		37
Item 5.	Other Information		37
Item 6.	Exhibits		38
	Signatures		39

2

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, 2017, 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:

●

our ability to repay outstanding loans when due;

●

our limited liquidity gives substantial doubt about our ability to continue as a going concern and our 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 acquisitions and divestitures may involve unexpected costs or delays, and that acquisitions may not achieve intended benefits and will divert management’s time and energy, which could have an adverse effect on our financial position, results of operations, or cash flows;

●

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

●

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

●

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

●

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

●

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

●

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

●

our ability to replace our oil and natural gas reserves;

●

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

●

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

●

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

●

environmental risks;

3

●

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 effect of our oil and natural gas derivative 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;

●

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

●

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

All forward-looking statements are expressly qualified in their entirety by the cautionary statements in this 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.

4

PART I. FINANCIAL INFORMATION

Item 1. 

Financial Statements.

Yuma Energy, Inc.

CONSOLIDATED BALANCE SHEETS

(Unaudited)

	June 30,	December 31,
	2018	2017
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$2,348,627	$137,363
Accounts receivable, net of allowance for doubtful accounts:
Trade	3,522,107	4,496,316
Officer and employees	7,781	53,979
Other	441,795	1,004,479
Prepayments	622,843	976,462
Other deferred charges	387,108	347,490
Total current assets	7,330,261	7,016,089
OIL AND GAS PROPERTIES (full cost method):
Proved properties	504,060,185	494,216,531
Unproved properties - not subject to amortization	534,627	6,794,372
	504,594,812	501,010,903
Less: accumulated depreciation, depletion and amortization	(425,547,424)	(421,165,400)
Net oil and gas properties	79,047,388	79,845,503
OTHER PROPERTY AND EQUIPMENT:
Assets held for sale	2,309,243	-
Land, buildings and improvements	-	1,600,000
Other property and equipment	1,793,397	2,845,459
	4,102,640	4,445,459
Less: accumulated depreciation and amortization	(1,324,152)	(1,409,535)
Net other property and equipment	2,778,488	3,035,924
OTHER ASSETS AND DEFERRED CHARGES:
Deposits	467,592	467,592
Other noncurrent assets	79,997	270,842
Total other assets and deferred charges	547,589	738,434
TOTAL ASSETS	$89,703,726	$90,635,950

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

5

Yuma Energy, Inc.

CONSOLIDATED BALANCE SHEETS– CONTINUED

(Unaudited)

	June 30,	December 31,
	2018	2017
LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Current maturities of debt	$35,094,226	$651,124
Accounts payable, principally trade	8,904,037	11,931,218
Commodity derivative instruments	2,613,690	903,003
Asset retirement obligations	88,722	277,355
Other accrued liabilities	1,555,117	2,295,438
Total current liabilities	48,255,792	16,058,138
LONG-TERM DEBT	-	27,700,000
OTHER NONCURRENT LIABILITIES:
Asset retirement obligations	10,492,311	10,189,058
Commodity derivative instruments	783,338	336,406
Deferred rent	272,506	290,566
Employee stock awards	143,961	191,110
Total other noncurrent liabilities	11,692,116	11,007,140
COMMITMENTS AND CONTINGENCIES (Notes 2 and 15)
EQUITY
Series D convertible preferred stock
($0.001 par value, 7,000,000 authorized, 1,971,072 issued and outstanding
as of June 30, 2018, and 1,904,391 issued and outstanding as of
December 31, 2017)	1,971	1,904
Common stock
($0.001 par value, 100 million shares authorized, 23,242,969 outstanding as of
June 30, 2018 and 22,661,758 outstanding as of December 31, 2017)	23,243	22,662
Additional paid-in capital	57,304,534	55,064,685
Treasury stock at cost (380,069 shares as of June 30, 2018 and 13,343 shares
as of December 31, 2017)	(438,890)	(25,278)
Accumulated earnings (deficit)	(27,135,040)	(19,193,301)
Total equity	29,755,818	35,870,672
TOTAL LIABILITIES AND EQUITY	$89,703,726	$90,635,950

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

6

Yuma Energy, Inc.

CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

	Three Months Ended June 30,		Six Months Ended June 30,
	2018	2017	2018	2017
REVENUES:
Sales of natural gas and crude oil	$5,822,577	$6,554,704	$11,468,113	$13,699,128
EXPENSES:
Lease operating and production costs	2,795,825	3,059,124	5,421,593	5,720,388
General and administrative – stock-based
compensation	64,230	385,097	360,524	436,832
General and administrative – other	1,587,628	1,906,629	3,336,866	4,082,631
Depreciation, depletion and amortization	2,245,170	2,763,444	4,462,491	5,904,384
Asset retirement obligation accretion expense	140,161	141,454	283,101	280,023
Impairment of long lived assets	176,968	-	176,968	-
Bad debt expense	261,659	73,513	327,467	73,513
Total expenses	7,271,641	8,329,261	14,369,010	16,497,771
LOSS FROM OPERATIONS	(1,449,064)	(1,774,557)	(2,900,897)	(2,798,643)
OTHER INCOME (EXPENSE):
Net gains (losses) from commodity derivatives	(2,095,570)	2,138,080	(3,346,830)	5,694,863
Interest expense	(567,635)	(482,285)	(1,033,927)	(978,376)
Gain (loss) on other property and equipment	-	(70,874)	-	484,768
Other, net	81,884	5,659	78,348	42,067
Total other income (expense)	(2,581,321)	1,590,580	(4,302,409)	5,243,322
INCOME (LOSS) BEFORE INCOME TAXES	(4,030,385)	(183,977)	(7,203,306)	2,444,679
Income tax expense (benefit)	-	(20,581)	-	5,950
NET INCOME (LOSS)	(4,030,385)	(163,396)	(7,203,306)	2,438,729
PREFERRED STOCK:
Dividends paid in kind	374,416	349,300	738,433	688,910
NET INCOME (LOSS) ATTRIBUTABLE TO
COMMON STOCKHOLDERS	$(4,404,801)	$(512,696)	$(7,941,739)	$1,749,819
INCOME (LOSS) PER COMMON SHARE:
Basic	$(0.19)	$(0.04)	$(0.35)	$0.14
Diluted	$(0.19)	$(0.04)	$(0.35)	$0.14
WEIGHTED AVERAGE NUMBER OF
COMMON SHARES OUTSTANDING:
Basic	23,082,334	12,235,286	22,948,475	12,223,337
Diluted	23,082,334	12,235,286	22,948,475	12,407,996

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

7

Yuma Energy, Inc.

CONSOLIDATED STATEMENT OF CHANGES IN EQUITY

(Unaudited)

	Preferred Stock		Common Stock		Additional Paid-in Capital	Treasury Stock	Accumulated Deficit	Stockholders' Equity
	Shares	Value	Shares	Value
December 31, 2017	1,904,391	$1,904	22,661,758	$22,662	$55,064,685	$(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	-	-	962,063	962	(962)	-	-	-
Restricted stock awards forfeited	-	-	(14,126)	(14)	14	-	-	-
Restricted stock awards repurchased	-	-	(366,726)	(367)	367	-	-	-
Amortization of stock-based
compensation	-	-	-	-	1,502,064	-	-	1,502,064
Treasury stock (surrendered to
settle employee tax liabilities)	-	-	-	-	-	(413,612)	-	(413,612)
June 30, 2018	1,971,072	$1,971	23,242,969	$23,243	$57,304,534	$(438,890)	$(27,135,040)	$29,755,818

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

8

Yuma Energy, Inc.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Six Months Ended June 30,
	2018	2017
CASH FLOWS FROM OPERATING ACTIVITIES:
Reconciliation of net income (loss) to net cash provided by (used in)
operating activities:
Net income (loss)	$(7,203,306)	$2,438,729
Depreciation, depletion and amortization of property and equipment	4,462,491	5,904,384
Impairment of long lived assets	176,968	-
Amortization of debt issuance costs	260,803	172,826
Deferred rent liability, net	25,668	-
Stock-based compensation expense	360,524	436,832
Settlement of asset retirement obligations	(575,817)	(227,346)
Asset retirement obligation accretion expense	283,101	280,023
Bad debt expense	327,467	73,513
Net (gains) losses from commodity derivatives	3,346,830	(5,694,863)
Gain on sales of fixed assets	-	(556,141)
Loss on write-off of abandoned facilities	-	71,373
(Gain) loss on write-off of liabilities net of assets	(103,045)	(34,835)
Changes in assets and liabilities:
(Increase) decrease in accounts receivable	1,339,227	426,945
Decrease in prepaids, deposits and other assets	297,321	521,167
(Decrease) increase in accounts payable and other current and
non-current liabilities	65,487	(923,200)
NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES	3,063,719	2,889,407
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures for oil and gas properties	(6,928,684)	(4,526,587)
Proceeds from sale of oil and gas properties	1,000,000	5,400,563
Proceeds from sale of other fixed assets	-	641,556
Derivative settlements	(1,189,211)	550,675
NET CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES	(7,117,895)	2,066,207
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings on senior credit facility	14,300,000	-
Repayment of borrowings on senior credit facility	(7,000,000)	(7,500,000)
Repayments of borrowings - insurance financing	(556,898)	(512,783)
Debt issuance costs	-	(2,152)
Shelf registration costs	(64,050)	-
Treasury stock repurchases	(413,612)	(23,270)
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES	6,265,440	(8,038,205)
CHANGE IN CASH AND CASH EQUIVALENTS	2,211,264	(3,082,591)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD	137,363	3,625,686
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$2,348,627	$543,095
Supplemental disclosure of cash flow information:
Interest payments (net of interest capitalized)	$773,150	$811,042
Interest capitalized	$133,772	$112,136
Supplemental disclosure of significant non-cash activity:
(Increase) decrease in capital expenditures financed by accounts payable	$3,252,112	$(386,337)

The accompanying notes are an integral part of these 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. In addition, during 2017 the Company began acquiring acreage in Yoakum County, Texas, with plans to explore and develop additional oil and natural gas assets in the Permian Basin of West Texas. Finally, the Company has operated positions in Kern County, California, and non-operated positions in the East Texas Woodbine and the Bakken Shale in North Dakota.

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, 2018; the Consolidated Statements of Operations for the three and six months ended June 30, 2018 and 2017; the Consolidated Statement of Changes in Equity for the six months ended June 30, 2018; and the Consolidated Statements of Cash Flows for the six months ended June 30, 2018 and 2017. The Company’s Consolidated Balance Sheet at December 31, 2017 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 2 in the Notes to Consolidated Financial Statements contained in the Company’s Annual Report on Form 10-K for the year ended December 31, 2017.

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, 2017. 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.

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.

10

In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2014-09, “Revenue from Contracts with Customers,” which will supersede most of the existing revenue recognition requirements in GAAP and will require entities to recognize revenue at an amount that reflects the consideration to which it expects to be entitled in exchange for transferring goods or services to a customer. The new standard also requires disclosures that are sufficient to enable users to understand an entity’s nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. In March 2016, the FASB issued ASU 2016-08, Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations (Reporting Revenue Gross versus Net). This update provides clarifications in the assessment of principal versus agent considerations in the new revenue standard. In May 2016, the FASB issued ASU 2016-12, Revenue from Contracts with Customers (Topic 606): Narrow Scope Improvements and Practical Expedients. The update reduces the potential for diversity in practice at initial application of Topic 606 and the cost and complexity of applying Topic 606. In December 2016, the FASB issued ASU 2016-20, Technical Corrections and Improvements to Topic 606, Revenue from Contracts with Customers. The update was issued to increase stakeholders’ awareness of the proposals for technical corrections and to expedite improvements. These ASUs are effective for annual and interim periods beginning after December 15, 2017. The Company adopted these standards effective January 1, 2018 using the full retrospective method. The Company finalized the detailed analysis of the impact of the standard on its contracts. The Company found that there was no significant impact on its financial position or results of operations. With the adoption of these standards, the Company was not required to record a cumulative effect adjustment due to the new standards not having a quantitative impact compared to existing GAAP (see Note 3 – Revenue Recognition – Adoption of ASC 606, “Revenue from Contracts with Customers”).

In February 2016, the FASB issued ASU 2016-02, “Leases,” a new lease standard requiring lessees to recognize lease assets and lease liabilities for most leases classified as operating leases under previous GAAP. The codification was amended through additional ASUs. The guidance is effective for fiscal years beginning after December 15, 2018 with early adoption permitted. The Company will be required to use a modified retrospective approach for leases that exist or are entered into after the beginning of the earliest comparative period in the financial statements. The Company is currently evaluating the impact of the adoption of this standard on its consolidated financial statements, and plans to adopt it no later than January 1, 2019.

In March 2016, the FASB issued ASU 2016-09, “Compensation—Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting,”whichsimplifies the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, classification on the statement of cash flows, and accounting for forfeitures. This ASU is effective for annual and interim periods beginning after December 15, 2017. The Company adopted this ASU on January 1, 2017. The adoption of this standard did not have a material impact on the Company’s consolidated financial statements.

In August 2016, the FASB issued ASU 2016-15, “Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments,” which provides clarification on how certain cash receipts and cash payments are presented and classified on the statement of cash flows. This ASU is effective for annual and interim periods beginning after December 15, 2017 and is required to be adopted using a retrospective approach if practicable, with early adoption permitted. The Company adopted this ASU in the first quarter of 2018, and the adoption did not have a material impact on its consolidated financial statements.

In January 2017, the FASB issued ASU 2017-01, “Business Combinations (Topic 805): Clarifying the Definition of a Business,” which assists in determining whether a transaction should be accounted for as an acquisition or disposal of assets or as a business. This ASU is effective for annual and interim periods beginning in 2018 and is required to be adopted using a prospective approach, with early adoption permitted for transactions not previously reported in issued financial statements. The Company adopted this ASU on January 1, 2017. The adoption of this ASU did not have a material impact on the Company’s consolidated financial statements, however, the Company will apply the provisions of ASU 2017-01 to future acquisitions.

11

NOTE 2 – Liquidity and Going Concern

The Company has borrowings under its credit facility which require, among other things, compliance with certain financial ratios and covenants.  Due to operating losses the Company sustained during recent quarters, at June 30, 2018 the Company was 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, and (iv) the liquidity covenant requiring the Company to maintain unrestricted cash and borrowing base availability of at least $4.0 million. In addition, due to this non-compliance, the Company classified its entire bank debt as a current liability in its financial statements as of June 30, 2018. On July 31, 2018, the Borrowers entered into the Waiver and Third Amendment to Credit Agreement (the “Third Amendment”) with the Lender. Pursuant to the Third Amendment, effective as of June 30, 2018, the Borrowers were granted a waiver for non-compliance from the liquidity covenant to have cash and cash equivalent investments together with borrowing base availability under the Credit Agreement of at least $4.0 million. In addition, as part of the Third Amendment, the Lenders requested that the Borrowers provide weekly cash flow forecasts and a monthly accounts payable report to the Lenders. The Third Amendment also provides for a redetermination of the borrowing base on August 15, 2018.

As of June 30, 2018, the Company had outstanding borrowings of $35.0 million under its credit facility, and its total borrowing base was $35.0 million, leaving no undrawn borrowing base. Due to drilling activities and other factors, the Company had a working capital deficit of $40.93 million (inclusive of the Company's outstanding debt under its credit facility) and a loss from operations of $2.90 million for the six months ended June 30, 2018. See Note 11 – Debt and Interest Expense.

These breaches of the terms and conditions of the Credit Agreement could result in acceleration of the Company’s indebtedness, in which case the debt would become immediately due and payable thereby giving our lenders various rights and remedies, including foreclosure.

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

The Company initiated several strategic alternatives to remedy 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. During the second quarter, the Company entered into an Asset Purchase and Sale Agreement on May 21, 2018 regarding its Kern County, California properties, including the sale of all of the Company’s oil and gas properties, fee properties, land, buildings, and other property and equipment in consideration of $4.7 million in gross proceeds and the buyer’s assumption of certain plugging and abandonment liabilities. The transaction is scheduled to close by August 31, 2018. Upon the closing of the transaction, it is anticipated that the majority of the proceeds will be applied to the repayment of borrowings under the credit facility. In addition, the Company has reduced its personnel by eight employees since December 31, 2017, a 24% decrease, including five positions that were eliminated on June 30, 2018. This brings the Company’s headcount to 26 employees at June 30, 2018. It should also be noted that, during the second quarter of 2018, the Company took additional steps to further reduce its general and administrative costs by reducing subscriptions, consultants and other non-essential services, as well as eliminating certain of its capital expenditures planned for 2018.

Additionally, the Company plans to take further steps to remedy its limited liquidity, which may include, but are not limited to, further reducing or eliminating capital expenditures; entering into additional commodity derivatives for a portion of the Company’s anticipated production; further reducing general and administrative expenses; selling certain non-core assets; 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 remedy the Company’s limited liquidity.

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NOTE 3 – Revenue Recognition – Adoption of ASC 606, “Revenue from Contracts with Customers”

The Company recognizes revenues to depict the transfer of control of promised goods or services to its customers in an amount that reflects the consideration to which it expects to be entitled to in exchange for those goods or services.

On January 1, 2018, the Company adopted Accounting Standards Codification (“ASC”) 606 using the full retrospective method applied to those contracts which were not completed as of December 31, 2016. As a result of electing the full retrospective adoption approach as described above, results for reporting periods beginning after December 31, 2016 are presented under ASC 606.

There was no material impact upon the adoption of ASC 606, and the Company did not record any adjustments to opening retained earnings as of January 1, 2017, because its revenue is primarily products sales revenue accounted for at a point in time.

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 the Company’s California properties is based on an average of specified posted prices, adjusted for gravity and transportation. The Company’s 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.

Sales of crude oil, condensates, natural gas and natural gas liquids (“NGLs”) are recognized at the point control of the product is transferred to the customer. Virtually all of the Company’s contracts’ pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality of the oil or natural gas, and prevailing supply and demand conditions. As a result, the price of the crude oil, condensate, natural gas, and NGLs fluctuates to remain competitive with other available crude oil, natural gas, and NGLs supplies.

Revenue is measured based on consideration specified in the contract with the customer, and excludes any amounts collected on behalf of third parties. The Company recognizes revenue in the amount that reflects the consideration it expects to be entitled to in exchange for transferring control of those goods to the customer. The contract consideration in the Company’s variable price contracts is typically allocated to specific performance obligations in the contract according to the price stated in the contract. Amounts allocated in the Company’s fixed price contracts are based on the stand-alone selling price of those products in the context of long-term, fixed price contracts, which generally approximates the contract price.

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 period from January 1, 2017 through December 31, 2017, 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 outside the scope of ASC 606 and is not considered revenue from contracts with customers subject to ASC 606. 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.

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Natural Gas and Natural Gas Liquids Sales

Under the Company’s natural gas processing contracts, it delivers natural gas to a midstream processing entity at the wellhead or the inlet of the midstream processing entity’s system. The midstream processing entity gathers and processes the natural gas and remits proceeds to the Company for the resulting sales of NGLs and residue gas. In these scenarios, the Company evaluates whether it is the principal or the agent in the transaction. For those contracts where the Company has concluded it is the principal and the ultimate third party is its customer, the Company recognizes revenue on a gross basis, with transportation, gathering, processing and compression fees presented as an expense in its lease operating and production costs in the Consolidated Statements of Operations.

In certain natural gas processing agreements, the Company may elect to take its residue gas and/or NGLs in-kind at the tailgate of the midstream entity’s processing plant and subsequently market the product. Through the marketing process, the Company delivers product to the ultimate third-party purchaser at a contractually agreed-upon delivery point and receives a specified index price from the purchaser. In this scenario, the Company recognizes revenue when control transfers to the purchaser at the delivery point based on the index price received from the purchaser. The gathering, processing and compression fees attributable to the gas processing contract, as well as any transportation fees incurred to deliver the product to the purchaser, are presented as lease operating and production costs in the Consolidated Statements of Operations.

Crude Oil and Condensate Sales

The Company sells oil production at the wellhead and collects an agreed-upon index price, net of pricing differentials. In this scenario, revenue is recognized when control transfers to the purchaser at the wellhead at the net price received.

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,
	2018	2017	2018	2017
Sales of natural gas and crude oil:
Crude oil and condensate	$3,203,260	$3,122,848	$6,269,517	$6,938,780
Natural gas	1,775,919	2,587,968	3,567,170	5,141,410
Natural gas liquids	843,398	843,888	1,631,426	1,618,938
Total revenues	$5,822,577	$6,554,704	$11,468,113	$13,699,128

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 in ASC 606-10-50-14 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 in ASC 606-10-50-14(a) 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.

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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 $2,367,596 and $2,636,867 as of June 30, 2018 and December 31, 2017, 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.

Practical Expedients 

The Company has made use of certain practical expedients in adopting the new revenue standard, including not disclosing the value of unsatisfied performance obligations for (i) contracts with an original expected length of one year or less, (ii) contracts for which the Company recognizes revenue at the amount to which the Company has the right to invoice, (iii) variable consideration which is allocated entirely to a wholly unsatisfied performance obligation and meets the variable allocation criteria in the standard and (iv) only contracts that are not completed at transition.

The Company has not adjusted the promised amount of consideration for the effects of a significant financing component if the Company expects, at contract inception, that the period between when the Company transfers a promised good or service to the customer and when the customer pays for that good or service will be one year or less.

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 net cash flows from estimated proved reserves less estimated future operating and development costs, abandonment costs (net of salvage value) and estimated related future 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 2018 full cost ceiling calculation was prepared by the Company using (i) $57.67 per barrel for oil, and (ii) $2.92 per MMBTU for natural gas as of June 30, 2018. 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. During the three and six month periods ended June 30, 2018 and 2017, 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.

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The following table summarizes the Company’s ARO transactions recorded during the six months ended June 30, 2018 in accordance with the provisions of FASB ASC Topic 410, “Asset Retirement and Environmental Obligations”.

	Six Months Ended
	June 30, 2018
Asset retirement obligations at December 31, 2017	$10,466,413
Liabilities incurred	25,940
Liabilities settled	(194,421)
Accretion expense	283,101
Revisions in estimated cash flows	-
Asset retirement obligations at June 30, 2018	$10,581,033

Based on expected timing of settlements, $88,722 of the ARO is classified as current at June 30, 2018.

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.

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	Fair value measurements at June 30, 2018
		Significant
	Quoted prices	other	Significant
	in active	observable	unobservable
	markets	inputs	inputs
	(Level 1)	(Level 2)	(Level 3)	Total
Liabilities:
Commodity derivatives – oil	$-	$3,317,684	$-	$3,317,684
Commodity derivatives – gas	-	79,344	-	79,344
Total liabilities	$-	$3,397,028	$-	$3,397,028

	Fair value measurements at December 31, 2017
		Significant
	Quoted prices	other	Significant
	in active	observable	unobservable
	markets	inputs	inputs
	(Level 1)	(Level 2)	(Level 3)	Total
Liabilities:
Commodity derivatives – oil	$-	$1,517,410	$-	$1,517,410
Commodity derivatives – gas	-	(278,001)	-	$(278,001)
Total liabilities	$-	$1,239,409	$-	$1,239,409

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 11 – Debt and Interest Expense). The carrying amount of floating-rate debt approximates fair value because the interest rates are variable and reflective of market rates.

Asset Retirement Obligations – 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

Objective and Strategies for Using Commodity Derivative Instruments – In order to mitigate the effect of commodity price uncertainty and enhance the predictability of cash flows relating to the marketing of the Company’s crude oil and natural gas, the Company enters into crude oil and natural gas price commodity derivative instruments with respect to a portion of the Company’s expected production. The commodity derivative instruments used include futures, swaps, and options to manage exposure to commodity price risk inherent in the Company’s oil and natural gas operations.

Futures contracts and commodity price swap agreements are used to fix the price of expected future oil and natural gas sales at major industry trading locations such as Henry Hub, Louisiana for natural gas and Cushing, Oklahoma for oil. Basis swaps are used to fix or float the price differential between product prices at one market location versus another. Options are used to establish a floor price, a ceiling price, or a floor and ceiling price (collar) for expected future oil and natural gas sales.

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A three-way collar is a combination of three options: a sold call, a purchased put, and a sold put. The sold call establishes the maximum price that the Company will receive for the contracted commodity volumes. The purchased put establishes the minimum price that the Company will receive for the contracted volumes unless the market price for the commodity falls below the sold put strike price, at which point the minimum price equals the reference price (e.g., NYMEX) plus the excess of the purchased put strike price over the sold put strike price.

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

The Company does not apply hedge accounting to any of its derivative instruments. As a result, gains and losses associated with derivative instruments are recognized currently in earnings.

Counterparty Credit Risk – Commodity derivative instruments expose the Company to counterparty credit risk. The Company’s commodity derivative instruments are with Société Générale (“SocGen”) and BP Energy Company. Commodity derivative contracts are executed under master agreements which allow the Company, in the event of default, to elect early termination of all contracts. If the Company chooses to elect early termination, all asset and liability positions would be netted and settled at the time of election.

Commodity derivative instruments open as of June 30, 2018 are provided below. Natural gas prices are New York Mercantile Exchange (“NYMEX”) Henry Hub prices, and crude oil prices are NYMEX West Texas Intermediate (“WTI”).

	2018	2019	2020
	Settlement	Settlement	Settlement
NATURAL GAS (MMBtu):
Swaps
Volume	887,533	1,660,297	1,095,430
Price	$2.97	$2.75	$2.68
CRUDE OIL (Bbls):
Swaps
Volume	89,995	156,320
Price	$53.17	$53.77

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, 2018	December 31, 2017
Asset commodity derivatives:
Current assets	$52,439	$295,304
Noncurrent assets	69,622	118
Total asset commodity derivatives	122,061	295,422
Liability commodity derivatives:
Current liabilities	(2,666,129)	(1,198,307)
Noncurrent liabilities	(852,960)	(336,524)
Total liability commodity derivatives	(3,519,089)	(1,534,831)
Total commodity derivative instruments	$(3,397,028)	$(1,239,409)

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Net gains (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,
	2018	2017	2018	2017
Derivative settlements	$(659,847)	$451,975	$(1,189,211)	$550,675
Mark to market on commodity derivatives	(1,435,723)	1,686,105	(2,157,619)	5,144,188
Net gains (losses) from commodity derivatives	$(2,095,570)	$2,138,080	$(3,346,830)	$5,694,863

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 $6.5838109. 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, 2018, the Series D Preferred Stock had a liquidation preference of approximately $21.8 million. The Series D Preferred Stock provides for cumulative dividends of 7.0% per annum, payable in-kind. The Company issued 33,810 shares of Series D Preferred Stock during the three months ended June 30, 2018. The Company does not have any dividends in arrears at June 30, 2018.

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, 2018, 14,126 shares of the 2,495,000 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.

The 2018 Plan provides that a maximum of 4,000,000 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, 2018, all of the 4,000,000 shares of common stock authorized under the 2018 Plan remain available for future issuance.

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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, 2018, the Company did not grant any RSAs under the 2014 Plan or the 2018 Plan.

Liability Based Awards – During the three months ended June 30, 2018, the Company did not grant any liability based awards under the 2014 Plan or the 2018 Plan.

Share Buy-back – During the three months ended June 30, 2018, the Company purchased 10,831 common shares from employees at a cost of $4,332 in satisfaction of employee tax obligations upon the vesting of RSAs. During the six months ended June 30, 2018, the Company purchased 366,726 common shares from employees at a cost of $413,612 in satisfaction of employee tax obligations of vested RSAs.

Total share-based compensation expenses recognized for the three months ended June 30, 2018 and 2017 were $64,230 (none capitalized) and $385,097 (none capitalized), respectively. Total share-based compensation expenses recognized for the six months ended June 30, 2018 and 2017 were $360,524 (none capitalized) and $436,832 (none capitalized), respectively.

NOTE 10 – Net Income (Loss) Per Common Share

Net Income (Loss) per common share – Basic is calculated by dividing net income (loss) attributable to common stockholders by the weighted average number of shares of common stock outstanding during the period. Net Income (Loss) per common share – Diluted assumes the conversion of all potentially dilutive securities, and is calculated by dividing net income (loss) attributable to common stockholders by the sum of the weighted average number of shares of common stock outstanding plus potentially dilutive securities. Net Income (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 earnings (loss) per common share is as follows: 

	Three Months Ended June 30,		Six Months Ended June 30,
	2018	2017	2018	2017
Net income (loss) attributable to common stockholders	$(4,404,801)	$(512,696)	$(7,941,739)	$1,749,819
Weighted average common shares outstanding
Basic	23,082,334	12,235,286	22,948,475	12,223,337
Add potentially dilutive securities:
Unvested restricted stock awards	-	-	-	184,659
Stock appreciation rights	-	-	-	-
Stock options	-	-	-	-
Series D preferred stock	-	-	-	-
Diluted weighted average common shares outstanding	23,082,334	12,235,286	22,948,475	12,407,996
Net income (loss) per common share:
Basic	$(0.19)	$(0.04)	$(0.35)	$0.14
Diluted	$(0.19)	$(0.04)	$(0.35)	$0.14

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NOTE 11 – Debt and Interest Expense

Long-term debt consisted of the following:

	June 30,	December 31,
	2018	2017
Senior credit facility	$35,000,000	$27,700,000
Installment loan due 7/22/18 originating from the financing of
insurance premiums at 5.14% interest rate	94,226	651,124
Total debt	35,094,226	28,351,124
Less: current maturities	(35,094,226)	(651,124)
Total long-term debt	$-	$27,700,000

Senior Credit Facility

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

As of June 30, 2018, the credit facility had a borrowing base of $35.0 million. On July 31, 2018, the Borrowers entered into the Waiver and Third Amendment to Credit Agreement (the “Third Amendment”) with the Lender. Pursuant to the Third Amendment, effective as of June 30, 2018, the Borrowers were granted a waiver for non-compliance from the liquidity covenant to have cash and cash equivalent investments together with borrowing base availability under the Credit Agreement of at least $4.0 million. In addition, as part of the Third Amendment, the Lenders requested that the Borrowers provide weekly cash flow forecasts and a monthly accounts payable report to the Lenders. The Third Amendment also provides for a redetermination of the borrowing base on August 15, 2018.

On May 8, 2018, the Borrowers entered into the Limited Waiver and Second Amendment to Credit Agreement and Borrowing Base Redetermination (the “Second Amendment”) with the Lender. Pursuant to the Second Amendment, which was effective as of March 31, 2018, the Borrowers were required to enter into additional hedging arrangements with respect to a substantial portion of the Borrowers projected production, which the Company complied with in the second quarter. In addition, in the Second Amendment the terms of the covenant related to the current ratio were revised to exclude the current portion of long-term indebtedness outstanding under the Credit Agreement from current liabilities, and Yuma was required to provide monthly production and lease operating expense statements to the Lender. The Second Amendment also provided a waiver of the financial covenant related to the maximum ratio of total debt to EBITDAX for the four fiscal quarter period ended March 31, 2018. The Second Amendment also reduced the borrowing base under the credit facility to $35.0 million as of May 8, 2018.

The Credit Agreement governing the Company’s credit facility provides for interest-only payments until October 26, 2019, when the Credit Agreement matures and any outstanding borrowings are due. The borrowing base under the Credit Agreement is subject to redetermination on April 1st and October 1st of each year, as well as special redeterminations described in the Credit Agreement, in each case which may reduce the amount of the borrowing base.

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 PV10 value of the proved oil and gas properties included in the determination of the borrowing base.

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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 June 30, 2018 was 6.10% for LIBOR-based debt and 8.00% for prime-based debt. Principal amounts outstanding under the credit facility are due and payable in full at maturity on October 26, 2019. 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.

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.

As of June 30, 2018, the Company was 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, and (iv) the liquidity covenant requiring the Company to maintain unrestricted cash and borrowing base availability of at least $4.0 million. Due to this non-compliance, the Company classified its entire bank debt as a current liability in its financial statements as of June 30, 2018. On July 31, 2018, the Company received a waiver from its lenders to its lack of compliance with its liquidity covenant requiring unrestricted cash and borrowing base availability of at least $4.0 million. The Borrowers’ bank covenant calculations for the second quarter ended June 30, 2018 are due by August 29, 2018. Upon submission of these covenant calculations the Borrower intends to seek a waiver for the covenant violations related to the i) total debt to EBITDAX covenant, (ii) current ratio covenant, and (iii) EBITDAX to interest expense covenant for the second quarter. There can be no assurance that the Lenders will grant these waivers, as they represent breaches of the terms and conditions of the Credit Agreement and could result in acceleration of the Company’s indebtedness, in which case the debt would become immediately due and payable thereby giving the Lenders various rights and remedies, including foreclosure. The Company currently anticipates non-compliance with various financial covenants at September 30, 2018. See Note 2 – Liquidity and Going Concern.

The Company incurred commitment fees in connection with our Credit Agreement of $4,735 and $6,751 during the three months ended June 30, 2018 and 2017, respectively, and $19,170 and $12,376 during the six months ended June 30, 2018 and 2017, respectively.

NOTE 12 – 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 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.

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NOTE 13 – Income Taxes

The Company’s effective tax rate for the three months ended June 30, 2018 and 2017 was 0.00% and 11.19%, respectively. The difference between the statutory federal income taxes calculated using a U.S. Federal statutory corporate income tax rate of 21% and the Company’s effective tax rate of 0.00% for the three months ended June 30, 2018 was primarily related to the valuation allowance on the deferred tax assets and state income taxes. The difference between the statutory federal income taxes calculated using a U.S. Federal statutory corporate income tax rate of 35% and the Company’s effective tax rate of 11.19% for the three months ended June 30, 2017 was primarily related to the valuation allowance on the deferred tax assets and state income taxes.

The Company’s effective tax rate for the six months ended June 30, 2018 and 2017 was 0.00% and 0.24%, respectively. The difference between the statutory federal income taxes calculated using a U.S. Federal statutory corporate income tax rate of 21% and the Company’s effective tax rate of 0.00% for the six months ended June 30, 2018 was primarily related to the valuation allowance on the deferred tax assets and state income taxes. The difference between the statutory federal income taxes calculated using a U.S. Federal statutory corporate income tax rate of 35% and the Company’s effective tax rate of 0.24% for the six months ended June 30, 2017 was primarily related to the valuation allowance on the deferred tax assets and state income taxes.

As of June 30, 2018, the Company had federal and state net operating loss carryforwards of approximately $176.9 million which 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. Realization of a deferred tax asset is dependent, in part, on generating sufficient taxable income prior to expiration of the loss carryforwards.

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.

NOTE 14 – Divestitures and Oil and Gas Asset Sales

The Company entered into an Asset Purchase and Sale Agreement on May 21, 2018 regarding its Kern County, California properties, including the sale of all of the Company’s oil and gas properties, fee properties, land, buildings, and other property and equipment for gross proceeds of $4.7 million and the buyer’s assumption of certain plugging and abandonment liabilities. The transaction is scheduled to close by August 31, 2018. In relation to the sale, the Company classified its land, buildings and other property and equipment located in Kern County as Held for sale in the second quarter, which required valuation of these assets at the lower of carrying value or fair value less costs to sell. Valuation of these assets resulted in an impairment charge of $176,968. The assets held for sale consist of land and building and other property and equipment with estimated fair values less costs to sell of $1,511,884 and $797,359, respectively, at June 30, 2018.

In January 2018, the Company sold a 12.5% working interest in ten sections of the project in Yoakum County, Texas, known as Mario, for $500,000. Additionally, the December 2017 sale of a 12.5% working interest under the same terms was settled in January 2018 for $500,000, bringing the total sales proceeds received to $1,000,000.

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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 held a 75% working interest in approximately 3,669 acres (2,752 net acres) as of December 31, 2017. As the operator of the property covered by the JDA, the Company was committed as of June 30, 2018 to spend an additional $276,708 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.

Lease Agreements

On July 26, 2017, the Company entered into a tenth amendment to its office lease whereby the term of the lease was extended to August 31, 2023.  The lease amendment covers a period of 68 calendar months and went into effect on January 1, 2018.  In addition, the lease amendment included seven months of abated rent and operating expenses from June 1, 2017 through February 1, 2018, as well as other incentives, including abated parking cost and tenant lease improvement allowances.  The base rent amount (which began on January 1, 2018) starts at $258,060 per annum and escalates to $288,420 per annum during the final 19 months of the lease extension.  In addition to the base rent amount, the Company will also be responsible for additional operating expenses of the building as well as parking charges once the abatement period ends.  The Company accounts for the lease as an operating lease under GAAP. 

The Company also currently leases approximately 3,200 square feet of office space at an off-site location as a storage facility. The current lease expires on April 30, 2020.

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

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

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. It is impossible to predict at this time how this case will now proceed other than that there will be a schedule set for opposition to the Motion to Remand and eventually a decision will be made as to 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. It is impossible to predict at this time how these cases will now proceed other than that there will be a schedule set for opposition to the Motions to Remand and eventually a decision will be made as to 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.

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Louisiana, et al. Escheat Tax Audits

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

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 the proposed work plan. 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.

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

This lawsuit, filed on June 15, 2018 in Livingston Parish, Louisiana, 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 Exploration. 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, if any. The Company has notified its insurance carrier of the lawsuit.

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

Exploration, 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 this lawsuit brought in St. Mary’s Parish, Louisiana on July 9, 2018. The plaintiff alleges that it owns property in St. Mary’s Parish and that it has acquired rights from former owners of the property to pursue claims for monetary and punitive damages, property remediation and other relief against the defendants for alleged contamination and damage to the property from their oil and gas exploration and production activities over the years. 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.

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 noted below or disclosed in the Company’s filings with the SEC.

On July 31, 2018, the Company entered into the Waiver and Third Amendment to its Credit Agreement with its lender (see Note 2 – Liquidity and Going Concern and Note 11 – Debt and Interest Expense).

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, 2017.

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. In addition, during 2017 we began acquiring acreage in an extension of the San Andres formation in Yoakum County, Texas, with plans to explore and develop additional oil and natural gas assets in the Permian Basin of West Texas. Finally, we have operated positions in Kern County, California, and non-operated positions in the East Texas Woodbine and the Bakken Shale in North Dakota. Our common stock is listed on the NYSE American under the trading symbol “YUMA.”

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Permian Basin

In 2017, we entered the Permian Basin through a joint venture with two privately held energy companies and established an Area of Mutual Interest (“AMI”) covering approximately 33,280 acres in Yoakum County, Texas, located in the Northwest Shelf of the Permian Basin. The primary target within the AMI is the San Andres formation, which has been one of the largest producing formations in Texas to date. As of June 30, 2018, we held a 62.5% working interest in approximately 4,823 gross acres (3,014 net acres) within the AMI. In November 2017, we drilled a salt water disposal well, the Jameson SWD #1. In December 2017, we spudded the State 320 #1H horizontal San Andres well, which was subsequently completed in February 2018. We opened the well on March 1, 2018 and placed the well on production. As of July 17, 2018, the well has produced a total of 1,708 barrels of oil, 12,748 Mcf of gas, and 421,603 barrels of water. The well is currently shut-in pending evaluation of the commerciality and future development of the prospect area. Given the well performance to date, the ability to establish commercial production in the prospect area is uncertain at this time. 

Preferred Stock

As of June 30, 2018, we had 1,971,072 shares of our Series D preferred stock outstanding with an aggregate liquidation preference of approximately $21.8 million and a conversion price of $6.5838109 per share. If all of our outstanding shares of Series D preferred stock were converted into common stock, we would need to issue approximately 3.3 million 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, 2018 and 2017, and the average sales price per unit sold.

	Three Months Ended June 30,		Six Months Ended June 30,
	2018	2017	2018	2017
Production volumes:
Crude oil and condensate (Bbls)	47,322	66,242	94,479	142,640
Natural gas (Mcf)	538,241	786,111	1,171,681	1,685,538
Natural gas liquids (Bbls)	28,974	35,092	54,217	68,566
Total (Boe) (1)	166,003	232,353	343,976	492,129
Average prices realized:
Crude oil and condensate (per Bbl)	$67.69	$47.14	$66.36	$48.65
Natural gas (per Mcf)	$3.30	$3.29	$3.04	$3.05
Natural gas liquids (per Bbl)	$29.11	$24.05	$30.09	$23.61

(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).

Revenues

The following table presents our revenues for the three and six months ended June 30, 2018 and 2017.

	Three Months Ended June 30,		Six Months Ended June 30,
	2018	2017	2018	2017
Sales of natural gas and crude oil:
Crude oil and condensate	$3,203,260	$3,122,848	$6,269,517	$6,938,780
Natural gas	1,775,919	2,587,968	3,567,170	5,141,410
Natural gas liquids	843,398	843,888	1,631,426	1,618,938
Total revenues	$5,822,577	$6,554,704	$11,468,113	$13,699,128

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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 is based on an average of specified posted prices, adjusted for gravity and transportation.

Crude oil volumes sold were 28.6%, or 18,920 Bbls, lower for the three months ended June 30, 2018 compared to crude oil volumes sold during the three months ended June 30, 2017, due primarily to a decrease of 5,478 Bbls resulting from divesting the El Halcón Field during the second quarter of 2017. Additional decreases included the Cameron Canal Field (2,381 Bbls), the Livingston Field (2,730 Bbls), La Posada (2,164 Bbls) and Main Pass 4 (2,785 Bbls). Realized crude oil prices experienced a 43.6% increase from the three months ended June 30, 2017 compared to the three months ended June 30, 2018.

Crude oil volumes sold were 33.8%, or 48,161 Bbls, lower for the six months ended June 30, 2018 compared to crude oil volumes sold during the three months ended June 30, 2017, due primarily to a decrease of 15,300 Bbls resulting from divesting the El Halcón Field during the second quarter of 2017. Additional decreases included the Cameron Canal Field (8,458 Bbls), the Livingston Field (5,289 Bbls), Main Pass 4 (4,919 Bbls), La Posada (4,707 Bbls) and the Chalktown Field (2,820 Bbls). Realized crude oil prices experienced a 36.4% increase from the six months ended June 30, 2017 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, 2018 compared to the three months ended June 30, 2017, we experienced a 31.5%, or 247,870 Mcf, decrease in natural gas volumes sold and a decrease in natural gas liquids sold of 17.4%, or 6,118 Bbls. The decreases were due primarily to decreases at the Cameron Canal Field (66,705 Mcf), the Lac Blanc Field (70,302 Mcf) and La Posada (113,509 Mcf). During the same period, realized natural gas prices increased by 0.3% and realized natural gas liquids prices increased by 21.0%.

For the six months ended June 30, 2018 compared to the six months ended June 30, 2017, we experienced a 30.5%, or 513,857 Mcf, decrease in natural gas volumes sold and a decrease in natural gas liquids sold of 20.9%, or 14,349 Bbls. The decreases were due primarily to decreases at La Posada (254,773 Bbls), the Cameron Canal Field (185,931 Bbls) and the Lac Blanc Field (30,033 Bbls). During the same period, realized natural gas prices decreased by 0.3% and realized natural gas liquids prices increased by 27.4%.

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Expenses

Lease Operating Expenses

Our lease operating expenses (“LOE”) and LOE per Boe for the three and six months ended June 30, 2018 and 2017, are set forth below:

	Three Months Ended June 30,		Six Months Ended June 30,
	2018	2017	2018	2017
Lease operating expenses	$1,890,809	$1,844,896	$3,556,129	$3,542,804
Severance, ad valorem taxes and
marketing	905,016	1,214,228	1,865,464	2,177,584
Total LOE	$2,795,825	$3,059,124	$5,421,593	$5,720,388
LOE per Boe	$16.84	$13.17	$15.76	$11.62
LOE per Boe without severance,
ad valorem taxes and marketing	$11.39	$7.94	$10.34	$7.20

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 8.6% decrease in total LOE for the three months ended June 30, 2018 compared to the three months ended June 30, 2017 was due to a decrease of $82,534 related to the sale of the El Halcón Field during the second quarter of 2017, a decrease of $48,916 in the Livingston Field due to a reduction of active wells, a decrease of $38,912 at Lac Blanc due to decreased field-related costs, and a $27,123 decrease in costs related to our California field operations.  These reductions were offset by an increase of $136,690 for our Permian operations which came online in the first quarter of 2018, and a $37,773 increase for the Main Pass 4 workover.  LOE per barrel of oil equivalent increased by 27.9% from the same period of the prior year generally due to the decrease in volumes noted above while a substantial portion of LOE is related to fixed costs.

The 5.2% decrease in total LOE for the six months ended June 30, 2018 compared to the six months ended June 30, 2017 was due to a decrease of $227,891 related to the sale of the El Halcón Field during the second quarter of 2017, a decrease of $73,570 in the Livingston Field due to a reduction of active wells, and a $90,159 decrease in costs related to our California field operations.  These reductions were offset by an increase of $162,576 for our Permian operations which came online in the first quarter of 2018, a $73,116 increase at La Posada from production facility expenses, and a $66,033 increase for the Main Pass 4 workover.  LOE per barrel of oil equivalent increased by 35.6% from the same period of the prior year generally due to the decrease in volumes noted above while a substantial portion of LOE is related to fixed costs.

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General and Administrative Expenses

Our general and administrative (“G&A”) expenses for the three and six months ended June 30, 2018 and 2017, are summarized as follows:

	Three Months Ended June 30,		Six Months Ended June 30,
	2018	2017	2018	2017
General and administrative:
Stock-based compensation	$64,230	$385,097	$360,524	$436,832
Capitalized	-	-	-	-
Net stock-based compensation	64,230	385,097	360,524	436,832
Other	1,853,316	2,329,938	3,980,513	4,926,860
Capitalized	(265,688)	(423,309)	(643,647)	(844,229)
Net other	1,587,628	1,906,629	3,336,866	4,082,631
Net general and administrative expenses	$1,651,858	$2,291,726	$3,697,390	$4,519,463

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.

For the three months ended June 30, 2018, net G&A expenses were 27.9%, or $639,868, lower than the amount for the same period in 2017. Variances include a decrease in accounting and audit fees of $45,078, a decrease in consulting fees of $71,297, a decrease in salaries and stock compensation of $178,337 and $320,867, respectively, a decrease in franchise taxes of $97,351, a decrease in costs associated with the Company’s acquisition of Davis Petroleum Acquisition Corp. (“Davis”) of $75,000, offset by an increase in termination benefits of $169,825. The decrease in stock compensation was primarily a result of the reevaluation of liability-based SARs in the second quarter.

For the six months ended June 30, 2018, net G&A expenses were 18.2%, or $822,073, lower than the amount for the same period in 2017. Variances include a decrease in accounting and audit fees of $202,467, a decrease in consulting fees of $128,718, a decrease in salaries and stock compensation of $321,951 and $76,308, respectively, a decrease in costs associated with the Company’s acquisition of Davis of $251,195, offset by an increase in termination benefits of $169,825.

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, 2018 and 2017, is summarized as follows:

	Three Months Ended June 30,		Six Months Eneded June 30,
	2018	2017	2018	2017
DD&A	$2,204,936	$2,763,444	$4,382,023	$5,904,384
DD&A per Boe	$13.28	$11.89	$12.74	$12.00

DD&A decreased by 20.2% and 25.8% for the three and six months ended June 30, 2018 compared to the same periods in 2017, primarily as a result of the decrease in the net quantities of crude oil and natural gas sold.

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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. During the three and six months ended June 30, 2018 and 2017, we 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, 2018 and 2017, is summarized as follows:

	Three Months Ended June 30,		Six Months Ended June 30,
	2018	2017	2018	2017
Interest expense	$585,866	$549,871	$1,167,699	$1,090,512
Interest capitalized	(18,231)	(67,586)	(133,772)	(112,136)
Net	$567,635	$482,285	$1,033,927	$978,376
Bank debt	$35,000,000	$32,000,000	$35,000,000	$32,000,000

Interest expense (net of amounts capitalized) increased $85,350 and $55,551 for the three and six months ended June 30, 2018 over the same periods in 2017 as a result of higher amounts outstanding under our credit facility during the three months ended June 30, 2018, in addition to less capitalized interest in the three months ended June 30, 2018 compared to the same period in 2017.

For a more complete narrative of interest expense, and terms of our credit agreement, refer to Note 11 – Debt and Interest Expense in the Notes to the Unaudited Consolidated Financial Statements included in Part I of this report.

Income Tax Expense

The following summarizes our income tax expense (benefit) and effective tax rates for the three and six months ended June 30, 2018 and 2017:

	Three Months Ended June 30,		Six Months Ended June 30,
	2018	2017	2018	2017
Consolidated net income (loss)
before income taxes	$(4,030,385)	$(183,977)	$(7,203,306)	$2,444,679
Income tax expense (benefit)	$-	$(20,581)	$-	$5,950
Effective tax rate	0.00%	11.19%	0.00%	0.24%

Differences between the U.S. federal statutory rate of 21% in 2018 and 35% in 2017 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.

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Liquidity and Capital Resources

Our primary and potential sources of liquidity include cash on hand, cash from operating activities, borrowings under our revolving credit facility, 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. We are subject to a number of factors that are beyond our control, including commodity prices, our bank’s determination of our borrowing base, production declines, and other factors that could affect our liquidity and ability to continue as a going concern.

We initiated several strategic alternatives to remedy 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 second quarter, we entered into an Asset Purchase and Sale Agreement on May 21, 2018 regarding our Kern County, California properties, including the sale of all of our oil and gas properties, fee properties, land, buildings, and other property and equipment in consideration of $4.7 million in gross proceeds and the buyer’s assumption of certain plugging and abandonment liabilities. The transaction is scheduled to close by August 31, 2018. Upon the closing of the transaction, it is anticipated that the majority of the proceeds will be applied to the repayment of borrowings under our credit facility. In addition, we have reduced our personnel by eight employees since December 31, 2017, a 24% decrease, including five positions that were eliminated on June 30, 2018. This brings the Company’s headcount to 26 employees as of June 30, 2018. It should also be noted that, during the second quarter of 2018, we took additional steps to further reduce our general and administrative costs by reducing subscriptions, consultants and other non-essential services, as well as eliminating certain of our capital expenditures planned for 2018.

Additionally, we plan to take further steps to remedy our limited liquidity, which may include, but are not limited to, further reducing or eliminating capital expenditures; entering into additional commodity derivatives for a portion of our anticipated production; further reducing general and administrative expenses; selling certain non-core assets; 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 remedy our limited liquidity.

The significant risks 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 provided by operating activities was $3,063,719 for the six months ended June 30, 2018 compared to $2,889,407 in cash provided during the same period in 2017. This increase was primarily caused by changes in assets and liabilities, including a decrease in accounts receivable of $1,339,227 offset 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 commodity prices, the impact of which we partially mitigate by entering into commodity derivatives. 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, 2018, we had a total of $7,117,895 of cash used in investing activities. Of that, $4,000,449 related to the drilling of the State 320 #1H, $2,186,791 related to the drilling of the Jameson #1 salt water disposal well, $889,108 related to lease acquisition costs for our Permian Basin acquisition, and realized cash derivatives resulting in a decrease of $1,189,211, offset by $1,000,000 related to proceeds from the sale of additional working interests in the Mario Prospect.

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During the six months ended June 30, 2017, we had a total of $2,066,207 of cash provided by investing activities. Of that, $5,175,063 was related to proceeds from the sale of the El Halcón field, offset by $1,001,444 related to the SL 18090 #2 well to establish production from the SIPH-D1 zone and $744,401 spent on lease acquisition costs related to our Permian Basis acquisition. In addition, $844,229 was capitalized G&A related to land, geological and geophysical costs.

Cash Flows from Financing Activities

We expect to finance future acquisition, development and exploration 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, 2018, we had net cash provided by financing activities of $6,265,440. Of that amount, $14,300,000 was borrowed on our credit facility, $7,000,000 was used for repayments on our credit facility, $413,612 of treasury stock was repurchased in connection with the satisfaction of tax obligations upon the vesting of employees’ restricted stock awards, and $556,898 was used for payments on our insurance financing. In addition, we paid costs related to a shelf registration statement of $64,050. As of June 30, 2018, we had a $35,000,000 borrowing base under our credit facility with the full amount advanced. Other than our credit facility, we had debt of $94,226 at June 30, 2018 from installment loans financing oil and natural gas property insurance premiums. We had a cash balance of $2,348,627 at June 30, 2018.

At June 30, 2017, we had a $40,500,000 conforming borrowing base under our credit facility with $32,000,000 advanced, leaving a borrowing capacity of $8,500,000. Other than the credit facility, we had debt of $86,558 at June 30, 2017 from installment loans financing oil and natural gas property insurance premiums. We had a cash balance of $543,095 at June 30, 2017.

Credit Facility

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

As of June 30, 2018, the credit facility had a borrowing base of $35.0 million. On July 31, 2018, the Borrowers entered into the Waiver and Third Amendment to Credit Agreement (the “Third Amendment”) with the Lender. Pursuant to the Third Amendment, effective as of June 30, 2018, the Borrowers were granted a waiver for non-compliance from the liquidity covenant to have cash and cash equivalent investments together with borrowing base availability under the Credit Agreement of at least $4.0 million. In addition, as part of the Third Amendment, the Lenders requested that the Borrowers provide weekly cash flow forecasts and a monthly accounts payable report to the Lenders. The Third Amendment also provides for a redetermination of the borrowing base on August 15, 2018.

On May 8, 2018, the Borrowers entered into the Limited Waiver and Second Amendment to Credit Agreement and Borrowing Base Redetermination (the “Second Amendment”) with the Lender. Pursuant to the Second Amendment, which was effective as of March 31, 2018, the Borrowers were required to enter into additional hedging arrangements with respect to a substantial portion of the Borrowers projected production, which the Company complied with in the second quarter. In addition, in the Second Amendment the terms of the covenant related to the current ratio were revised to exclude the current portion of long-term indebtedness outstanding under the Credit Agreement from current liabilities; and Yuma was required to provide monthly production and lease operating expense statements to the Lender. The Second Amendment also provided a waiver of the financial covenant related to the maximum ratio of total debt to EBITDAX for the four fiscal quarter period ended March 31, 2018. The Second Amendment also reduced the borrowing base under the credit facility to $35.0 million as of May 8, 2018.

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The borrowing base under the Credit Agreement is subject to redetermination on April 1st and October 1st of each year, as well as special redeterminations described in the Credit Agreement, in each case which may reduce the amount of the borrowing base. Our obligations under the Credit Agreement are guaranteed by our subsidiaries and are secured by liens on substantially all of our assets, including a mortgage lien on oil and natural gas properties covering at least 95% of the PV10 value of the proved oil and gas properties included in the determination of the borrowing base.

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 June 30, 2018 was 6.10% for LIBOR-based debt and 8.00% for prime-based debt. Principal amounts outstanding under the credit facility are due and payable in full at maturity on October 26, 2019. 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. We are 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, our 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.

In addition, the Credit Agreement requires us 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. As of June 30, 2018, we were not in compliance with several of our financial covenants under the Credit Agreement. On July 31, 2018, we received a waiver from our lenders to our lack of compliance with our liquidity covenant requiring unrestricted cash and borrowing base availability of at least $4.0 million. The Borrowers’ bank covenant calculations for the second quarter ended June 30, 2018 are due by August 29, 2018. Upon submission of these covenant calculations the Borrower intends to seek a waiver for the covenant violations related to the i) total debt to EBITDAX covenant, (ii) current ratio covenant, and (iii) EBITDAX to interest expense covenant for the second quarter. There can be no assurance that the Lenders will grant these waivers, as they represent breaches of the terms and conditions of the Credit Agreement and could result in acceleration of the Company’s indebtedness, in which case the debt would become immediately due and payable thereby giving our Lenders various rights and remedies, including foreclosure. We currently anticipate non-compliance with various financial covenants at September 30, 2018. See Note 2 – Liquidity and Going Concern in the Notes to the Unaudited Consolidated Financial Statements included in Part I of this report.

Hedging Activities

Current Commodity Derivative Contracts

We seek 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. We believe our hedging strategy should result in greater predictability of internally generated funds, which in turn can be dedicated to capital development projects and corporate obligations. 

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Fair Market Value of Commodity Derivatives

	June 30, 2018		December 31, 2017
	Oil	Natural Gas	Oil	Natural Gas
Assets
Current	$-	$-	$-	$-
Noncurrent	$-	$-	$-	$-
(Liabilities) assets
Current	$(2,587,919)	$(25,771)	$(1,198,307)	$295,304
Noncurrent	$(729,764)	$(53,574)	$(319,104)	$(17,302)

Assets and liabilities are netted within each commodity on the Consolidated Balance Sheets. For the balances without netting, refer to Note 7 – Commodity Derivative Instruments in the Notes to the Unaudited Consolidated Financial Statements included in Part I of this report.

The fair market value of our commodity derivative contracts in place at June 30, 2018 and December 31, 2017 were net liabilities of $3,397,028 and $1,239,409, respectively.

Off Balance Sheet Arrangements

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

Item 3.    

Quantitative and Qualitative Disclosures About Market Risk.

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

Item 4.  

Controls and Procedures.

Evaluation of disclosure controls and procedures.

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

As of June 30, 2018, we carried out an evaluation, under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Exchange Act Rule 13a-15(e)). Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that, as of June 30, 2018 our disclosure controls and procedures were effective.

Changes in internal control over financial reporting.

There were no changes in our internal control over financial reporting that occurred during the three month period ended June 30, 2018 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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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, 2017 on Form 10-K, which could materially affect our business, financial condition or future results. The risks described in our 2017 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, 2017. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial may materially adversely affect our business, financial condition and/or operating results.

Item 2.    

Unregistered Sales of Equity Securities and Use of Proceeds.

	Total Number of Shares Purchased (1)	Average Price Paid Per Share	Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Maximum Number (or Approximate Dollar Value) of Shares that May Yet Be Purchased Under the Plans or Programs
April 2018	-	-	-	-
May 2018	10,831	$0.40	-	-
June 2018	-	-	-	-

(1)

All of the shares were surrendered by employees (via net settlement) in satisfaction of tax obligations upon the vesting of restricted stock awards. The acquisition of the surrendered shares was not part of a publicly announced program to repurchase shares of our common stock.

Item 3.       

Defaults upon Senior Securities.

None.

Item 4.     

Mine Safety Disclosures.

Not Applicable.

Item 5.     

Other Information.

None.

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Item 6.   

Exhibits.

EXHIBIT INDEX

FOR

Form 10-Q for the quarter ended June 30, 2018.
		Incorporated by Reference
Exhibit No.	Description	Form	SEC File No.	Exhibit	Filing Date	Filed Herewith	Furnished Herewith
31.1	Certification of the Principal Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act.					X
31.2	Certification of the Principal Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act.					X
32.1	Certification of the Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act.						X
32.2	Certification of the Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act.						X
101.INS	XBRL Instance Document.					X
101.SCH	XBRL Schema Document.					X
101.CAL	XBRL Calculation Linkbase Document.					X
101.DEF	XBRL Definition Linkbase Document.					X
101.LAB	XBRL Label Linkbase Document.					X
101.PRE	XBRL Presentation Linkbase Document.					X

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SIGNATURES

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

	YUMA ENERGY, INC.
	By:	/s/ Sam L. Banks
	Name:	Sam L. Banks
Date: August 9, 2018	Title:	Chief Executive Officer (Principal Executive Officer)
	By:	/s/ James J. Jacobs
Date: August 9, 2018	Name:	James J. Jacobs
	Title:	Chief Financial Officer (Principal Financial Officer)

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