Yuma Energy (YUMAQ) 10-Q 2018 Q3 Quarterly report

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 September 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.

Larger accelerated filer ☐	Accelerated filer
Non-accelerated filer ☐	Smaller reporting company ☒
(Do not check if a 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 November 14, 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)
		Consolidated Balance Sheets as of September 30, 2018 and December 31, 2017	5
		Consolidated Statements of Operations for the Three and Nine Months Ended September 30, 2018 and 2017	7
		Consolidated Statement of Changes in Equity for the Nine Months Ended September 30, 2018	8
		Consolidated Statements of Cash Flows for the Nine Months Ended September 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		28
Item 3.	Quantitative and Qualitative Disclosures About Market Risk		37
Item 4.	Controls and Procedures		37
	PART II – OTHER INFORMATION
Item 1.	Legal Proceedings		38
Item 1A.	Risk Factors		38
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		38
Item 3.	Defaults Upon Senior Securities		38
Item 4.	Mine Safety Disclosures		38
Item 5.	Other Information		38
Item 6.	Exhibits		39
	Signatures		40

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:

●

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

●

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;

3

●

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

●

environmental risks;

●

drilling and operating risks;

●

exploration and development risks;

●

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

●

general economic conditions, whether internationally, nationally or in the regional and local market areas in which we do business, may be less favorable than we expect, including the possibility that economic conditions in the United States 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. 

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PART I. FINANCIAL INFORMATION

Item 1. Financial Statements.

Yuma Energy, Inc.

CONSOLIDATED BALANCE SHEETS

(Unaudited)

	September 30,	December 31,
	2018	2017
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$2,545,644	$137,363
Accounts receivable, net of allowance for doubtful accounts:
Trade	2,795,115	4,496,316
Officer and employees	4,229	53,979
Other	487,678	1,004,479
Prepayments	373,884	976,462
Other deferred charges	307,686	347,490
Total current assets	6,514,236	7,016,089
OIL AND GAS PROPERTIES (full cost method):
Proved properties	504,594,550	494,216,531
Unproved properties - not subject to amortization	-	6,794,372
	504,594,550	501,010,903
Less: accumulated depreciation, depletion, amortization and impairment	(431,069,270)	(421,165,400)
Net oil and gas properties	73,525,280	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	(1,339,896)	(1,409,535)
Net other property and equipment	2,762,744	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	$83,349,849	$90,635,950

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

5

Yuma Energy, Inc.

CONSOLIDATED BALANCE SHEETS– CONTINUED

(Unaudited)

	September 30,	December 31,
	2018	2017
LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Current maturities of debt	$35,000,000	$651,124
Accounts payable, principally trade	7,582,015	11,931,218
Commodity derivative instruments	3,001,449	903,003
Asset retirement obligations	325,805	277,355
Other accrued liabilities	1,678,112	2,295,438
Total current liabilities	47,587,381	16,058,138
LONG-TERM DEBT	-	27,700,000
OTHER NONCURRENT LIABILITIES:
Asset retirement obligations	10,395,929	10,189,058
Commodity derivative instruments	545,992	336,406
Deferred rent	261,698	290,566
Employee stock awards	115,616	191,110
Total other noncurrent liabilities	11,319,235	11,007,140
COMMITMENTS AND CONTINGENCIES (Notes 2 and 15)
EQUITY
Series D convertible preferred stock
($0.001 par value, 7,000,000 authorized, 2,005,849 issued and outstanding
as of September 30, 2018, and 1,904,391 issued and outstanding as of
December 31, 2017)	2,006	1,904
Common stock
($0.001 par value, 100 million shares authorized, 23,243,763 outstanding as of
September 30, 2018 and 22,661,758 outstanding as of December 31, 2017)	23,244	22,662
Additional paid-in capital	57,873,967	55,064,685
Treasury stock at cost (380,525 shares as of September 30, 2018 and 13,343 shares
as of December 31, 2017)	(439,099)	(25,278)
Accumulated earnings (deficit)	(33,016,885)	(19,193,301)
Total equity	24,443,233	35,870,672
TOTAL LIABILITIES AND EQUITY	$83,349,849	$90,635,950

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

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Yuma Energy, Inc.

CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

	Three Months Ended September 30,		Nine Months Ended September 30,
	2018	2017	2018	2017
REVENUES:
Sales of natural gas and crude oil	$5,426,855	$5,816,883	$16,894,968	$19,516,011
EXPENSES:
Lease operating and production costs	2,465,020	2,509,352	7,886,613	8,229,740
General and administrative – stock-based
compensation	143,214	414,660	503,738	851,492
General and administrative – other	1,314,666	1,622,528	4,651,532	5,705,159
Deposit forfeiture	(275,000)	-	(275,000)	-
Depreciation, depletion and amortization	2,140,310	2,761,668	6,602,801	8,666,052
Asset retirement obligation accretion expense	140,701	138,867	423,802	418,890
Impairment of oil and gas properties	3,397,281	-	3,397,281	-
Impairment of long lived assets	-	-	176,968	-
Bad debt expense (recovery)	85,928	(38,706)	413,395	34,807
Total expenses	9,412,120	7,408,369	23,781,130	23,906,140
LOSS FROM OPERATIONS	(3,985,265)	(1,591,486)	(6,886,162)	(4,390,129)
OTHER INCOME (EXPENSE):
Net gains (losses) from commodity derivatives	(873,723)	(1,260,280)	(4,220,553)	4,434,583
Interest expense	(637,772)	(429,313)	(1,671,700)	(1,407,689)
Gain (loss) on other property and equipment	-	-	-	484,768
Other, net	43	14,043	78,390	56,110
Total other income (expense)	(1,511,452)	(1,675,550)	(5,813,863)	3,567,772
INCOME (LOSS) BEFORE INCOME TAXES	(5,496,717)	(3,267,036)	(12,700,025)	(822,357)
Income tax expense (benefit)	-	2,539	-	8,489
NET INCOME (LOSS)	(5,496,717)	(3,269,575)	(12,700,025)	(830,846)
PREFERRED STOCK:
Dividends paid in kind	385,125	359,311	1,123,559	1,048,221
NET INCOME (LOSS) ATTRIBUTABLE TO
COMMON STOCKHOLDERS	$(5,881,842)	$(3,628,886)	$(13,823,584)	$(1,879,067)
INCOME (LOSS) PER COMMON SHARE:
Basic	$(0.25)	$(0.29)	$(0.60)	$(0.15)
Diluted	$(0.25)	$(0.29)	$(0.60)	$(0.15)
WEIGHTED AVERAGE NUMBER OF
COMMON SHARES OUTSTANDING:
Basic	23,096,359	12,483,724	22,998,312	12,311,087
Diluted	23,096,359	12,483,724	22,998,312	12,311,087

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	Treasury	Accumulated	Stockholders'
	Shares	Value	Shares	Value	Capital	Stock	Deficit	Equity
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	-	-	-	-	-	-	(12,700,025)	(12,700,025)
Payment of Series "D" dividends in kind	101,458	102	-	-	1,123,457	-	(1,123,559)	-
Stock awards vested	-	-	963,313	963	(963)	-	-	-
Restricted stock awards forfeited	-	-	(14,126)	(14)	14	-	-	-
Restricted stock awards repurchased	-	-	(367,182)	(367)	367	-	-	-
Stock-based compensation	-	-	-	-	1,686,407	-	-	1,686,407
Treasury stock (surrendered to settle employee tax liabilities)						(413,821)		(413,821)
September 30, 2018	2,005,849	$2,006	23,243,763	$23,244	$57,873,967	$(439,099)	$(33,016,885)	$24,443,233

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

8

Yuma Energy, Inc.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Nine Months Ended September 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)	$(12,700,025)	$(830,846)
Depreciation, depletion and amortization of property and equipment	6,602,801	8,666,052
Impairment of oil and gas properties	3,397,281	-
Impairment of long lived assets	176,968	-
Amortization of debt issuance costs	340,225	277,293
Deferred rent liability, net	18,219	163,962
Stock-based compensation expense	503,738	851,492
Settlement of asset retirement obligations	(590,709)	(430,415)
Asset retirement obligation accretion expense	423,802	418,890
Bad debt expense	413,395	34,807
Net (gains) losses from commodity derivatives	4,220,553	(4,434,583)
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	(103,044)	(34,835)
Changes in assets and liabilities:
(Increase) decrease in accounts receivable	1,864,956	736,959
Decrease in prepaids, deposits and other assets	546,280	715,603
(Decrease) increase in accounts payable and other current and
non-current liabilities	(380,292)	(1,177,583)
NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES	4,734,148	4,472,028
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures for oil and gas properties	(7,711,751)	(5,964,781)
Proceeds from sale of oil and gas properties	1,127,400	5,400,563
Proceeds from sale of other fixed assets	-	645,791
Derivative settlements	(1,912,521)	1,103,525
NET CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES	(8,496,872)	1,185,098
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)	(8,050,000)
Repayments of borrowings - insurance financing	(651,124)	(599,341)
Debt issuance costs	-	(323,593)
Common stock registration and offering costs	(64,050)	(15,087)
Treasury stock repurchases	(413,821)	(24,432)
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES	6,171,005	(9,012,453)
CHANGE IN CASH AND CASH EQUIVALENTS	2,408,281	(3,355,327)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD	137,363	3,625,686
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$2,545,644	$270,359
Supplemental disclosure of cash flow information:
Interest payments (net of interest capitalized)	$1,324,950	$1,133,385
Interest capitalized	$133,772	$208,310
Income tax refund	$-	$20,699
Supplemental disclosure of significant non-cash activity:
(Increase) decrease in capital expenditures financed by accounts payable	$3,922,933	$(3,291,386)
Common stock subscription receivable (net of $909,600 offering costs at closing)	$-	$8,690,400
Other accrued offering expenses	$-	$271,227

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.

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 September 30, 2018; the Consolidated Statements of Operations for the three and nine months ended September 30, 2018 and 2017; the Consolidated Statement of Changes in Equity for the nine months ended September 30, 2018; and the Consolidated Statements of Cash Flows for the nine months ended September 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.

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

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 supersedes most of the existing revenue recognition requirements in GAAP and requires 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.

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NOTE 2 – Liquidity and Going Concern

The Company has borrowings under its credit facility that require, among other things, compliance with certain financial ratios and covenants.  Due to operating losses the Company sustained during recent quarters, at September 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 September 30, 2018. On October 9, 2018, the Company received a notice and reservation of rights from the administrative agent under its Credit Agreement advising that an event of default has occurred and continues to exist by reason of the Company’s noncompliance with the liquidity covenant requiring it to maintain cash and cash equivalents and borrowing base availability of at least $4.0 million. As a result of the default, the lenders may accelerate the outstanding balance under the Credit Agreement, increase the applicable interest rate by 2.0% per annum or commence foreclosure on the collateral securing the loans. As of the date of this report, the lenders have not accelerated the outstanding amount due and payable on the loans, increased the applicable interest rate or commenced foreclosure proceedings, but they may exercise one or more of these remedies in the future. The Company intends to commence discussions with the lenders under the Credit Agreement concerning a forbearance agreement or waiver of the event of default; however, there can be no assurance that the Company and the lenders will come to any agreement regarding a forbearance or waiver of the event of default (see Note 11 – Debt and Interest Expense).

As of September 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 $41.07 million (inclusive of the Company's outstanding debt under its credit facility) and a loss from operations of $6.89 million for the nine months ended September 30, 2018.

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

During the second quarter of 2018, the Company agreed to sell its Kern County, California properties for $4.7 million in gross proceeds and the buyer’s assumption of certain plugging and abandonment liabilities of approximately $864,000, and received a non-refundable deposit of $275,000. The sale did not close as scheduled, and the buyer forfeited the deposit. The Company currently anticipates that it will close the sale with the same buyer in the fourth quarter of 2018 on re-negotiated terms. Upon closing, the Company anticipates that the majority of the proceeds will be applied to the repayment of borrowings under the credit facility; however, there can be no assurance that the transaction will close.

On August 20, 2018, the Company sold its 3.1% leasehold interest consisting of 9.8 net acres in one section in Eddy County, New Mexico for $127,400. On October 23, 2018, the Company sold substantially all of its Bakken assets in North Dakota for approximately $1.16 million in gross proceeds and the buyer’s assumption of certain plugging and abandonment liabilities of approximately $15,200. The Bakken assets represent approximately 12 barrels of oil equivalent per day of the Company’s production in the third quarter. On October 24, 2018, the Company sold certain deep rights in undeveloped acreage located in Grady County, Oklahoma for approximately $120,000. Proceeds of $1.0 million from these non-core asset sales were applied to the repayment of borrowings under the credit facility in October 2018, bringing the current outstanding balance and borrowing base under the credit facility to $34.0 million, with the balance of the proceeds used for working capital purposes.

Additionally, the Company has reduced its personnel by nine employees since December 31, 2017, a 26% decrease. This brings the Company’s headcount to 25 employees at September 30, 2018. Also, the Company has taken 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.

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On October 22, 2018, the Company retained Seaport Global Securities LLC, an investment banking firm, to advise the Company on its strategic and tactical alternatives, including possible acquisitions and divestitures.

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

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 year ended December 31, 2017 and the nine months ended September 30, 2018, revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material.

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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.

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 September 30,		Nine Months Ended September 30,
	2018	2017	2018	2017
Sales of natural gas and crude oil:
Crude oil and condensate	$3,090,585	$2,734,269	$9,360,102	$9,673,049
Natural gas	1,463,581	2,304,154	5,030,751	7,445,564
Natural gas liquids	872,689	778,460	2,504,115	2,397,398
Total revenues	$5,426,855	$5,816,883	$16,894,968	$19,516,011

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 $1,973,262 and $2,636,867 as of September 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 ASC 606, 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 cash flows from estimated proved reserves less estimated future operating and development costs, abandonment costs (net of salvage value) and estimated related future deferred income taxes. In accordance with SEC rules, prices used are the 12 month average prices, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12 month period prior to the end of the reporting period, unless prices are defined by contractual arrangements. Prices are adjusted for “basis” or location differentials. Prices are held constant over the life of the reserves. The Company’s third quarter of 2018 full cost ceiling calculation was prepared by the Company using (i) $63.43 per barrel for oil, and (ii) $2.91 per MMBTU for natural gas as of September 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 nine month periods ended September 30, 2018, the Company recorded a full cost ceiling impairment charge of $3,397,281. This impairment resulted primarily from the write-off of the Company’s Proved Undeveloped Reserves in the third quarter due to the uncertainty of the Company’s ability to fund their development. During the three and nine month periods ended September 30, 2017, the Company did not record any full cost ceiling impairments.

See Note 14 – Divestitures and Oil and Gas Asset Sales for a discussion of impairments made to assets held for sale.

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 nine months ended September 30, 2018 in accordance with the provisions of FASB ASC Topic 410, “Asset Retirement and Environmental Obligations”:

	Nine Months Ended
	September 30, 2018
Asset retirement obligations at December 31, 2017	$10,466,413
Liabilities incurred	25,940
Liabilities settled	(194,421)
Accretion expense	423,802
Revisions in estimated cash flows	-
Asset retirement obligations at September 30, 2018	$10,721,734

Based on expected timing of settlements, $325,805 of the ARO is classified as current at September 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.

	Fair value measurements at September 30, 2018
	Quoted pricesin activemarkets (Level 1)	Significant other observable inputs (Level 2)	Significant unobservable inputs (Level 3)	Total
Liabilities:
Commodity derivatives – oil	$-	$3,501,458	$-	$3,501,458
Commodity derivatives – gas	-	45,983	-	45,983
Total liabilities	$-	$3,547,441	$-	$3,547,441

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	Fair value measurements at December 31, 2017
	Quoted prices in active markets (Level 1)	Significant other observable inputs (Level 2)	Significant unobservable inputs (Level 3)	Total
Liabilities (assets):
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.

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.

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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 September 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	438,434	1,660,297	1,095,430
Price	$2.97	$2.75	$2.68
CRUDE OIL (Bbls):
Swaps
Volume	43,768	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
	September 30, 2018	December 31, 2017
Asset commodity derivatives:
Current assets	$31,815	$295,304
Noncurrent assets	88,317	118
Total asset commodity derivatives	120,132	295,422
Liability commodity derivatives:
Current liabilities	(3,033,264)	(1,198,307)
Noncurrent liabilities	(634,309)	(336,524)
Total liability commodity derivatives	(3,667,573)	(1,534,831)
Total commodity derivative instruments	$(3,547,441)	$(1,239,409)

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

	Three Months Ended September 30,		Nine Months Ended September 30,
	2018	2017	2018	2017
Derivative settlements	$(723,310)	$552,850	$(1,912,521)	$1,103,525
Mark to market on commodity derivatives	(150,413)	(1,813,130)	(2,308,032)	3,331,058
Net gains (losses) from commodity derivatives	$(873,723)	$(1,260,280)	$(4,220,553)	$4,434,583

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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 September 30, 2018, the Series D Preferred Stock had a liquidation preference of approximately $22.2 million. The Series D Preferred Stock provides for cumulative dividends of 7.0% per annum, payable in-kind. The Company issued 34,777 shares of Series D Preferred Stock during the three months ended September 30, 2018. The Company does not have any dividends in arrears at September 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 September 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 September 30, 2018, all of the 4,000,000 shares of common stock authorized under the 2018 Plan remain available for future issuance.

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

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

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Equity Based Awards – During the three months ended September 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 September 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 September 30, 2018, the Company purchased 456 common shares from employees at a cost of $210 in satisfaction of employee tax obligations upon the vesting of RSAs.  During the nine months ended September 30, 2018, the Company purchased 367,182 common shares from employees at a cost of $413,821 in satisfaction of employee tax obligations of vested RSAs. 

Total share-based compensation expenses recognized for the three months ended September 30, 2018 and 2017 were $143,214 (none capitalized) and $414,660 (none capitalized), respectively. Total share-based compensation expenses recognized for the nine months ended September 30, 2018 and 2017 were $503,738 (none capitalized) and $851,492 (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 September 30,		Nine Months Ended September 30,
	2018	2017	2018	2017
Net income (loss) attributable to common stockholders	$(5,881,842)	$(3,628,886)	$(13,823,584)	$(1,879,067)
Weighted average common shares outstanding
Basic	23,096,359	12,483,724	22,998,312	12,311,087
Add potentially dilutive securities:
Unvested restricted stock awards	-	-	-	-
Stock appreciation rights	-	-	-	-
Stock options	-	-	-	-
Series D preferred stock	-	-	-	-
Diluted weighted average common shares outstanding	23,096,359	12,483,724	22,998,312	12,311,087
Net income (loss) per common share:
Basic	$(0.25)	$(0.29)	$(0.60)	$(0.15)
Diluted	$(0.25)	$(0.29)	$(0.60)	$(0.15)

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NOTE 11 – Debt and Interest Expense

Long-term debt consisted of the following:

	September 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	-	651,124
Total debt	35,000,000	28,351,124
Less: current maturities	(35,000,000)	(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 September 30, 2018, the Company’s credit facility had a borrowing base of $35.0 million, with outstanding borrowings of $35.0 million, leaving no undrawn borrowing base. As of September 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 September 30, 2018. On October 9, 2018, the Company received a notice and reservation of rights from the administrative agent under its Credit Agreement advising that an event of default has occurred and continues to exist by reason of the Company’s noncompliance with the liquidity covenant requiring it to maintain cash and cash equivalents and borrowing base availability of at least $4.0 million. As a result of the default, the lenders may accelerate the outstanding balance under the Credit Agreement, increase the applicable interest rate by 2.0% per annum or commence foreclosure on the collateral securing the loans. As of the date of this report, the lenders have not accelerated the outstanding amount due and payable on the loans, increased the applicable interest rate or commenced foreclosure proceedings, but they may exercise one or more of these remedies in the future. The Company intends to commence discussions with the lenders under the Credit Agreement concerning a forbearance agreement or waiver of the event of default; however, there can be no assurance that the Company and the lenders will come to any agreement regarding a forbearance or waiver of the event of default. In addition, as a result of the Bakken Sale discussed in Note 16-Subsequent Events, the outstanding balance and borrowing base under the credit facility were reduced to $34 million on October 23, 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 provided 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 the Company 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 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.

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 September 30, 2018 was 6.25% for LIBOR-based debt and 8.25% 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.

The Company incurred commitment fees in connection with our Credit Agreement of $-0- and $10,827 during the three months ended September 30, 2018 and 2017, respectively, and $19,170 and $23,203 during the nine months ended September 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.

NOTE 13 – Income Taxes

The Company’s effective tax rate for the three months ended September 30, 2018 and 2017 was 0.00% and (0.08%), respectively. The Company’s effective tax rate for the nine months ended September 30, 2018 and 2017 was 0.00% and (1.03%), respectively. Differences between the U.S. federal statutory rate of 21% in 2018 and 35% in 2017 and the Company’s effective tax rates are due to the tax effects of valuation allowances recorded against the deferred tax assets and state income taxes.

As of September 30, 2018, the Company had federal and state net operating loss carryforwards of approximately $181.9 million and $83.3 million respectively, 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.

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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 of approximately $864,000. The transaction was scheduled to close by August 31, 2018; however, the closing was delayed and the buyer forfeited a $275,000 deposit related to the original closing date. While the Company still anticipates closing the transaction in the fourth quarter of 2018 at a reduced sales price, there can be no assurance that the transaction will close. 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 September 30, 2018.

On August 20, 2018, the Company sold its 3.1% leasehold interest consisting of 9.8 net acres in one section in Eddy County, New Mexico for $127,400.

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.

NOTE 15 – Commitments and Contingencies

Joint Development Agreement

On March 27, 2017, the Company entered into a Joint Development Agreement (“JDA”) with two privately held companies, both unaffiliated entities, covering an area of approximately 52 square miles (33,280 acres) in the Permian Basin of Yoakum County, Texas. In connection with the JDA, the Company now holds a 62.5% working interest in approximately 4,823 acres (3,014 net acres) as of September 30, 2018. As the operator of the property covered by the JDA, the Company was committed as of September 30, 2018 to spend an additional $241,649 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.

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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 is responsible for additional operating expenses of the building as well as parking charges.  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.

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, and are awaiting a ruling by the arbitrator. 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. That did not occur and this case remains stayed. In the interim, an Order was issued in another of the coastal cases pending in the Eastern District of Louisiana lifting the stay and setting a schedule for briefing for plaintiffs’ motion to remand (Parish of Plaquemines v. Riverwood Production Company, et al., No. 2:18-cv-05217, Eastern District of Louisiana). Judge Martin L. C. Feldman is assigned to the Riverwood case and he will be the first Judge in the Eastern District to decide on the remand, and presumably the Judges assigned to other cases, including this one, will follow his decision as relevant and appropriate. There will be oral argument on the motion to remand in the Riverwood case on December 12, 2018. The parties currently anticipate that by year-end 2018, they will know whether these cases will be remanded to state court. It is impossible to predict at this time whether this second removal will keep the case in federal court. At this point in the legal process, no evaluation of the likelihood of an unfavorable outcome or associated economic loss can be made; therefore no liability has been recorded on the Company’s consolidated financial statements.

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

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

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 (Avanti) that would address the rule for all through a test case.  Exploration’s case has been stayed pending adjudication of the test case. The hearing for the Avanti test case was held on November 7, 2017, and on December 6, 2017, the Board of Tax Appeals rendered judgment in favor of the taxpayer in the first of these cases. The Department of Revenue filed an appeal to this decision on January 5, 2018. The Board of Tax Appeals case record has been lodged at the Louisiana Third Circuit Court of Appeal in the Avanti test case. The briefs will be due in the next 45 days, and then the case will be set for oral argument. All other Board of Tax Appeals cases are stayed pending the final decision in the Avanti case. 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 Department of Wildlife and Fisheries

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

Miami Corporation – South Pecan Lake Field Area P&A

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

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

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

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

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

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

The Company, as a successor in interest from another company years ago, along with 41 other companies in the chain of title, was named as a defendant in this lawsuit brought in St. Mary’s Parish, Louisiana on July 9, 2018. The substance of each of the petitions is virtually identical. In each case, the plaintiff(s) are seeking to recover damages to their property resulting from “oil and gas exploration and production activities.” The cited grounds for these actions include La. R.S. 30:29 (providing for restoration of property affected by oilfield contamination) and C.C. art. 2688 (notification by the lessee to the lessor when leased property is damaged). The plaintiffs are attempting to have these three cases consolidated. A hearing on motion to consolidate was scheduled for November 9, 2018. These cases are in the very early stages. At this point, not all of the named defendants have filed responsive pleadings. All of the defendants who have responded at this point have, inter alia, filed exceptions of vagueness due to the lack of specificity in the petitions which makes it impossible to determine what action(s) any individual defendant may have performed which would result in liability to the plaintiffs. No hearing on the exceptions has been set pending the result of the consolidation hearing. The Company has sold the leases that appear to be involved in this litigation to Hilcorp Energy I, L.P., with an effective date of September 1, 2016. The conveyance includes an indemnity provision which appears to transfer liability for this type of damage to Hilcorp, and at some point it will be necessary to invoke this indemnity. The Company has notified its insurance carrier of the claim but believes that the suit is without merit. No evaluation of the likelihood of an unfavorable outcome or associated economic loss can be made at this early stage, therefore no liability has been recorded on the Company’s consolidated financial statements.

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

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

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.

Notice of Default and Reservation of Rights

On October 9, 2018, the Company received a notice and reservation of rights from the administrative agent under its Credit Agreement advising that an event of default has occurred and continues to exist by reason of the Company’s noncompliance with the liquidity covenant requiring it to maintain cash and cash equivalents and borrowing base availability of at least $4.0 million. As a result of the default, the lenders may accelerate the outstanding balance under the Credit Agreement, increase the applicable interest rate by 2.0% per annum or commence foreclosure on the collateral securing the loans. As of the date of this report, the lenders have not accelerated the outstanding amount due and payable on the loans, increased the applicable interest rate or commenced foreclosure proceedings, but they may exercise one or more of these remedies in the future. In addition, as a result of the Bakken Sale discussed below, the outstanding balance and borrowing base under the credit facility were reduced to $34 million on October 23, 2018.

Seaport

On October 22, 2018, the Company retained Seaport Global Securities LLC (“Seaport”) as the Company’s exclusive financial advisor and investment banker in connection with identifying and potentially implementing various strategic alternatives to address the Company’s liquidity issues and the possible disposition, acquisition or merger of the Company or its assets.

Bakken Sale

On October 23, 2018, the Company sold substantially all of its Bakken assets in North Dakota pursuant to a purchase and sale agreement for approximately $1.16 million in gross proceeds, with the buyer assuming approximately $15,200 in plugging and abandonment liabilities. These assets represented approximately 12 barrels of oil equivalent per day of the Company’s production in the third quarter.

Oklahoma Sale

On October 24, 2018, the Company sold certain deep rights in undeveloped acreage located in Grady County, Oklahoma for approximately $120,000 in gross proceeds.

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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. Our common stock is listed on the NYSE American under the trading symbol “YUMA.”

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 September 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. 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 September 30, 2018, we had 2,005,849 shares of our Series D preferred stock outstanding with an aggregate liquidation preference of approximately $22.2 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 3.4 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).

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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 nine months ended September 30, 2018 and 2017, and the average sales price per unit sold.

	Three Months Ended September 30,		Nine Months Ended September 30,
	2018	2017	2018	2017
Production volumes:
Crude oil and condensate (Bbls)	42,642	57,134	137,121	199,774
Natural gas (Mcf)	500,969	757,361	1,672,650	2,442,899
Natural gas liquids (Bbls)	22,894	32,694	77,111	101,260
Total (Boe) (1)	149,031	216,055	493,007	708,184
Average prices realized:
Crude oil and condensate (per Bbl)	$72.48	$47.86	$68.26	$48.42
Natural gas (per Mcf)	$2.92	$3.04	$3.01	$3.05
Natural gas liquids (per Bbl)	$38.12	$23.81	$32.47	$23.68

(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 nine months ended September 30, 2018 and 2017.

	Three Months Ended September 30,		Nine Months Ended September 30,
	2018	2017	2018	2017
Sales of natural gas and crude oil:
Crude oil and condensate	$3,090,585	$2,734,269	$9,360,102	$9,673,049
Natural gas	1,463,581	2,304,154	5,030,751	7,445,564
Natural gas liquids	872,689	778,460	2,504,115	2,397,398
Total revenues	$5,426,855	$5,816,883	$16,894,968	$19,516,011

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 25.4%, or 14,492 Bbls, lower for the three months ended September 30, 2018 compared to crude oil volumes sold during the three months ended September 30, 2017, due primarily to decreases from the Cameron Canal Field (2,718 Bbls), the Livingston Field (2,132 Bbls), La Posada (3,023 Bbls), the Lac Blanc Field (1,091) and Main Pass 4 (3,534 Bbls). Realized crude oil prices experienced a 51.4% increase from the three months ended September 30, 2017 compared to the three months ended September 30, 2018.

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Crude oil volumes sold were 31.4%, or 62,653 Bbls, lower for the nine months ended September 30, 2018 compared to crude oil volumes sold during the nine months ended September 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 (11,176 Bbls), the Livingston Field (7,421 Bbls), Main Pass 4 (4,984 Bbls), La Posada (7,730 Bbls), Raccoon Island (3,404) and the Chalktown Field (3,637 Bbls). Realized crude oil prices experienced a 41.0% increase from the nine months ended September 30, 2017 compared to the nine months ended September 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 September 30, 2018 compared to the three months ended September 30, 2017, we experienced a 33.9%, or 256,392 Mcf, decrease in natural gas volumes sold and a decrease in natural gas liquids sold of 30.0%, or 9,800 Bbls. The decreases were due primarily to decreases at the Cameron Canal Field (64,852 Mcf), the Lac Blanc Field (15,977 Mcf) and La Posada (174,042 Mcf). During the same period, realized natural gas prices decreased by 3.9% and realized natural gas liquids prices increased by 60.1%.

For the nine months ended September 30, 2018 compared to the nine months ended September 30, 2017, we experienced a 31.5%, or 770,249 Mcf, decrease in natural gas volumes sold and a decrease in natural gas liquids sold of 23.8%, or 24,149 Bbls. The decreases were due primarily to decreases at La Posada (428,815 Mcf), the Cameron Canal Field (250,784 Mcf) and the Lac Blanc Field (46,009 Mcf). During the same period, realized natural gas prices decreased by 1.3% and realized natural gas liquids prices increased by 37.1%.

Expenses

Lease Operating Expenses

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

	Three Months Ended September 30,		Nine Months Ended September 30,
	2018	2017	2018	2017
Lease operating expenses	$1,609,659	$1,506,747	$5,165,788	$5,049,551
Severance, ad valorem taxes and
marketing	855,361	1,002,605	2,720,825	3,180,189
Total LOE	$2,465,020	$2,509,352	$7,886,613	$8,229,740
LOE per Boe	$16.54	$11.61	$16.00	$11.62
LOE per Boe without severance,
ad valorem taxes and marketing	$10.80	$6.97	$10.48	$7.13

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.

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The 1.8% decrease in total LOE for the three months ended September 30, 2018 compared to the three months ended September 30, 2017 was due to a $147,244 decrease in severance, ad valorem, and marketing, offset by a $102,912 increase in lease operating expense. Lower natural gas and NGL sales resulted in a decrease in marketing cost for La Posada and Lac Blanc of $83,273 and $42,264, respectively. The increase in lease operating expenses is mostly attributable to higher field-related costs for Cameron Canal, Lac Blanc and the Permian wells. LOE per barrel of oil equivalent increased by 42.5% 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 4.2% decrease in total LOE for the nine months ended September 30, 2018 compared to the nine months ended September 30, 2017 was due to a decrease of $227,711 related to the sale of the El Halcón Field during the second quarter of 2017, a decrease of $192,040 in the Livingston Field due to a reduction of active wells, and a $51,419 decrease in costs related to Sabine Lake.  These reductions were offset by an increase of $213,364 for our Permian operations which came online in the first quarter of 2018, a $78,954 increase at La Posada from production facility expenses, and a $148,012 increase for the Main Pass 4 workover.  LOE per barrel of oil equivalent increased by 37.7% 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.

General and Administrative Expenses

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

	Three Months Ended September 30,		Nine Months Ended September 30,
	2018	2017	2018	2017
General and administrative:
Stock-based compensation	$143,214	$414,660	$503,738	$851,492
Capitalized	-	-	-	-
Net stock-based compensation	143,214	414,660	503,738	851,492
Other	1,404,218	2,009,428	5,384,731	6,936,288
Capitalized	(89,552)	(386,900)	(733,199)	(1,231,129)
Net other	1,314,666	1,622,528	4,651,532	5,705,159
Net general and administrative expenses	$1,457,880	$2,037,188	$5,155,270	$6,556,651

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 September 30, 2018, net G&A expenses were 28.4%, or $579,308, lower than the amount for the same period in 2017. Variances include a decrease in accounting and audit fees of $62,529, a decrease in consulting fees of $132,029, a decrease in directors’ fees of $63,750, a decrease in salaries and stock compensation of $192,774 and $271,446, respectively, offset by an increase in office rent of $67,200. The decrease in stock compensation was primarily a result of the reevaluation of liability-based SARs.

For the nine months ended September 30, 2018, net G&A expenses were 21.4%, or $1,401,381, lower than the amount for the same period in 2017. Variances include a decrease in accounting and audit fees of $264,996, a decrease in consulting fees of $260,746, a decrease in salaries and stock compensation of $514,726 and $347,754, respectively, a decrease in legal fees of $102,920, and a decrease in costs associated with the Company’s acquisition of Davis of $257,398, offset by an increase in termination benefits of $169,825 and an increase in office rent of $150,493.

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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 nine months ended September 30, 2018 and 2017, is summarized as follows:

	Three Months Ended September 30,		Nine Months Ended September 30,
	2018	2017	2018	2017
DD&A	$2,124,566	$2,721,203	$6,506,589	$8,476,049
DD&A per Boe	$14.26	$12.59	$13.20	$11.97

DD&A decreased by 21.9% and 23.2% for the three and nine months ended September 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.

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 nine months ended September 30, 2018, we recorded a full cost ceiling impairment charge of $3,397,281. This impairment resulted primarily from the write-off of our Proved Undeveloped Reserves in the third quarter due to the uncertainty of our ability to fund their development. During the three and nine months ended September 30, 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 nine months ended September 30, 2018 and 2017, is summarized as follows:

	Three Months Ended September 30,		Nine Months Ended September 30,
	2018	2017	2018	2017
Interest expense	$637,772	$525,487	$1,805,472	$1,615,999
Interest capitalized	-	(96,174)	(133,772)	(208,310)
Net	$637,772	$429,313	$1,671,700	$1,407,689
Bank debt	$35,000,000	$31,450,000	$35,000,000	$31,450,000

Interest expense (net of amounts capitalized) increased $208,459 and $264,011 for the three and nine months ended September 30, 2018 over the same periods in 2017 as a result of higher interest rates, higher amounts outstanding under our credit facility during the three months ended September 30, 2018, and less capitalized interest in the three months ended September 30, 2018 compared to the same period in 2017.

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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 nine months ended September 30, 2018 and 2017:

	Three Months Ended September 30,		Nine Months Ended September 30,
	2018	2017	2018	2017
Net income (loss) before
income taxes	$(5,496,717)	$(3,267,036)	$(12,700,025)	$(822,357)
Income tax expense (benefit)	$-	$2,539	$-	$8,489
Effective tax rate	0.00%	(0.08%)	0.00%	(1.03%)

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.

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.

As of September 30, 2018, the credit facility had a borrowing base of $35.0 million. On October 9, 2018, we received a notice and reservation of rights from the administrative agent under our Credit Agreement advising that an event of default has occurred and continues to exist by reason of our noncompliance with the liquidity covenant requiring us to maintain cash and cash equivalents and borrowing base availability of at least $4.0 million. As a result of the default, the lenders may accelerate the outstanding balance under the Credit Agreement, increase the applicable interest rate by 2.0% per annum or commence foreclosure on the collateral securing the loans. As of the date of this report, the lenders have not accelerated the outstanding amount due and payable on the loans, increased the applicable interest rate or commenced foreclosure proceedings, but they may exercise one or more of these remedies in the future.We intend to commence discussions with the lenders under the Credit Agreement concerning a forbearance agreement or waiver of the event of default; however, there can be no assurance that we and the lenders will come to any agreement regarding a forbearance or waiver of the event of default.

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

During the second quarter of 2018, we agreed to sell our Kern County, California properties for $4.7 million in gross proceeds and the buyer’s assumption of certain plugging and abandonment liabilities of approximately $864,000, and received a non-refundable deposit of $275,000. The sale did not close as scheduled, and the buyer forfeited the deposit. We currently anticipate that we will close the sale with the same buyer in the fourth quarter of 2018 on re-negotiated terms. Upon closing, we anticipate that the majority of the proceeds will be applied to the repayment of borrowings under the credit facility; however, there can be no assurance that the transaction will close.

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On August 20, 2018, we sold our 3.1% leasehold interest consisting of 9.8 net acres in one section in Eddy County, New Mexico for $127,400. On October 23, 2018, we sold substantially all of our Bakken assets in North Dakota for approximately $1.16 million in gross proceeds and the buyer’s assumption of certain plugging and abandonment liabilities of approximately $15,200. The Bakken assets represent approximately 12 barrels of oil equivalent per day of our production in the third quarter. On October 24, 2018, we sold certain deep rights in undeveloped acreage located in Grady County, Oklahoma for approximately $120,000. Proceeds of $1.0 million from these non-core asset sales were applied to the repayment of borrowings under the credit facility in October 2018, bringing the current outstanding balance and borrowing base under the credit facility to $34.0 million, with the balance of the proceeds used for working capital purposes.

In addition, we have reduced our personnel by nine employees since December 31, 2017, a 26% decrease. This brings our headcount to 25 employees as of September 30, 2018. We have taken 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.

On October 22, 2018, we retained Seaport Global Securities LLC (“Seaport”) as our exclusive financial advisor and investment banker in connection with identifying and potentially implementing various strategic alternatives to improve our liquidity issues and the possible disposition, acquisition or merger of the Company or our assets.

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

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

Cash Flows from Operating Activities

Net cash provided by operating activities was $4,734,148 for the nine months ended September 30, 2018 compared to $4,472,028 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 $1,864,956 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 nine months ended September 30, 2018, cash used in investing activities totaled $8,496,872, primarily from the payment of net capital expenditures of $7,711,751.  The major capital expenditures were associated with the drilling of the State 320 #1H and Jameson #1 SWD, lease acquisition costs for our Permian Basin acquisition, and the Fremaux SWD #1 workover. These payments were offset by $1,127,400 related to proceeds from the sale of working interests in the Mario Prospect and the sale of the New Mexico property.  In addition, realized cash derivative settlements resulted in cash used of $1,912,521.

During the nine months ended September 30, 2017, we had a total of $1,185,098 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 $1,642,460 related to the drilling of the Weyerhaeuser 14 #1, $1,563,262 related to the recompletion of the State Lease 14564 #4 well, $1,001,444 related to the SL 18090 #2 well to establish production from the SIPH-D1 zone and $945,084 spent on lease acquisition costs related to our Permian Basis acquisition. In addition, $1,231,129 was capitalized G&A related to land, geological and geophysical costs.

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Cash Flows from Financing Activities

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

During the nine months ended September 30, 2018, we had net cash provided by financing activities of $6,171,005. Of that amount, $14,300,000 was borrowed on our credit facility, $7,000,000 was used for repayments on our credit facility, $413,821 of treasury stock was repurchased in connection with the satisfaction of tax obligations upon the vesting of employees’ restricted stock awards, and $651,124 was used for payments on our insurance financing. In addition, we paid costs related to a shelf registration statement of $64,050.

As of September 30, 2018, we had a $35,000,000 borrowing base under our credit facility with the full amount advanced. We had no debt other than our credit facility at September 30, 2018. We had a cash balance of $2,545,644 at September 30, 2018.

At September 30, 2017, we had a $40,500,000 conforming borrowing base under our credit facility with $31,450,000 advanced, leaving a borrowing capacity of $9,050,000. We had no debt other than our credit facility at September 30, 2017. We had a cash balance of $270,359 at September 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 September 30, 2018, the credit facility had a borrowing base of $35.0 million. On October 9, 2018, we received a notice and reservation of rights from the administrative agent under our Credit Agreement advising that an event of default has occurred and continues to exist by reason of our noncompliance with the liquidity covenant requiring us to maintain cash and cash equivalents and borrowing base availability of at least $4.0 million. As a result of the default, the lenders may accelerate the outstanding balance under the Credit Agreement, increase the applicable interest rate by 2.0% per annum or commence foreclosure on the collateral securing the loans. As of the date of this report, the lenders have not accelerated the outstanding amount due and payable on the loans, increased the applicable interest rate or commenced foreclosure proceedings, but they may exercise one or more of these remedies in the future.We intend to commence discussions with the lenders under the Credit Agreement concerning a forbearance agreement or waiver of the event of default; however, there can be no assurance that we and the lenders will come to any agreement regarding a forbearance or waiver of the event of default.

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 provided 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 we were 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 September 30, 2018 was 6.25% for LIBOR-based debt and 8.25% 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 our capital stock, engage in mergers or consolidations, sell certain assets, sell or discount any notes receivable or accounts receivable, and engage in certain transactions with affiliates.

In addition, the Credit Agreement requires us to maintain 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 September 30, 2018, we were not in compliance with several of our financial covenants under the Credit Agreement.

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

	September 30, 2018		December 31, 2017
	Oil	Natural Gas	Oil	Natural Gas
Assets
Current	$-	$31,815	$-	$-
Noncurrent	$-	$88,317	$-	$-
(Liabilities) assets
Current	$(2,950,695)	$(82,569)	$(1,198,307)	$295,304
Noncurrent	$(550,763)	$(83,546)	$(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 September 30, 2018 and December 31, 2017 were net liabilities of $3,547,441 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 September 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 September 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 September 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, except as set forth below. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial may materially adversely affect our business, financial condition and/or operating results.

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

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

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

	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
July 2018	456	$0.46	-	-
August 2018	-	-	-	-
September 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 September 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: November 14, 2018	Title:	Chief Executive Officer (Principal Executive Officer)
	By:	/s/ James J. Jacobs
Date: November 14, 2018	Name:	James J. Jacobs
	Title:	Chief Financial Officer (Principal Financial Officer)

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