Yuma Energy, Inc. - FORM 10-Q - November 13, 2017

Attached files

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

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, 2017

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

For the transition period from to

Commission File Number: 001-37932

Yuma Energy, Inc.

(Exact name of registrant as specified in its charter)

DELAWARE

(State or other jurisdiction of incorporation)

94-0787340

(IRS Employer Identification No.)

1177 West Loop South, Suite 1825

Houston, Texas

(Address of principal executive offices)

77027

(Zip Code)

(713) 968-7000

(Registrant’s telephone number, including area code)

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

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

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

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

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

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

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

At November 13, 2017, 22,661,758 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)		4

		Consolidated Balance Sheets as of September 30, 2017 and December 31, 2016	4

		Consolidated Statements of Operations for the Three and Nine Months Ended September 30, 2017 and 2016	6

		Consolidated Statement of Changes in Equity for the Nine Months Ended September 30, 2017	7

		Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2017 and 2016	8

		Notes to the Unaudited Consolidated Financial Statements	9

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		22

Item 3.	Quantitative and Qualitative Disclosures About Market Risk		31

Item 4.	Controls and Procedures		31

	PART II – OTHER INFORMATION

Item 1.	Legal Proceedings		32

Item 1A.	Risk Factors		32

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		32

Item 3.	Defaults Upon Senior Securities		32

Item 4.	Mine Safety Disclosures		32

Item 5.	Other Information		32

Item 6.	Exhibits		33

	Signatures		34

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, 2016, and other disclosures contained herein and therein, which describe factors that could cause our actual results to differ from those anticipated in forward-looking statements, including, but not limited to, the following factors:

●

our ability to repay outstanding loans when due;

●

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

●

reductions in the borrowing base under our credit facility;

●

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

●

volatility and weakness in commodity 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;

●

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

●

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

●

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

●

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

●

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

●

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

●

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

●

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

●

our ability to replace our oil and natural gas reserves;

●

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

●

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

●

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

●

environmental risks;

●

drilling and operating risks;

●

exploration and development risks;

●

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

●

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

●

social unrest, political instability or armed conflict in major oil and natural gas producing regions outside the United States, such as Africa, the Middle East, and armed conflict or acts of terrorism or sabotage 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 insurance coverage maintained by us may not adequately cover all losses that may be sustained in connection with our business activities;

●

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

●

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

●

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

●

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

All forward-looking statements are expressly qualified in their entirety by the cautionary statements in this section and elsewhere in this report. Other than as required under applicable securities laws, we do not assume a duty to update these forward-looking statements, whether as a result of new information, subsequent events or circumstances, changes in expectations or otherwise. You should not place undue reliance on these forward-looking statements. All forward-looking statements speak only as of the date of this report or, if earlier, as of the date they were made.

PART I. FINANCIAL INFORMATION

Item 1.

Financial Statements.

Yuma Energy, Inc.

CONSOLIDATED BALANCE SHEETS

(Unaudited)

	September 30,	December 31,
	2017	2016

ASSETS

CURRENT ASSETS:
Cash and cash equivalents	$270,359	$3,625,686
Accounts receivable, net of allowance for doubtful accounts:
Trade	3,893,803	4,827,798
Officers and employees	48,575	68,014
Common stock subscription receivable	8,690,400	-
Other	1,186,320	1,757,337
Commodity derivative instruments	359,965	-
Prepayments	347,529	1,063,418
Other deferred charges	437,165	284,305

Total current assets	15,234,116	11,626,558

OIL AND GAS PROPERTIES (full cost method):
Proved properties	490,280,184	488,723,905
Unproved properties - not subject to amortization	5,584,644	3,656,989

	495,864,828	492,380,894
Less: accumulated depreciation, depletion and amortization	(418,916,482)	(410,440,433)

Net oil and gas properties	76,948,346	81,940,461

OTHER PROPERTY AND EQUIPMENT:
Land, buildings and improvements	1,600,000	1,600,000
Other property and equipment	2,845,459	7,136,530
	4,445,459	8,736,530
Less: accumulated depreciation and amortization	(1,369,302)	(5,349,145)

Net other property and equipment	3,076,157	3,387,385

OTHER ASSETS AND DEFERRED CHARGES:
Commodity derivative instruments	415,091	-
Deposits	467,592	467,306
Other noncurrent assets	333,587	517,201

Total other assets and deferred charges	1,216,270	984,507

TOTAL ASSETS	$96,474,889	$97,938,911

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

Yuma Energy, Inc.

CONSOLIDATED BALANCE SHEETS– CONTINUED

(Unaudited)

	September 30,	December 31,
	2017	2016

LIABILITIES AND EQUITY

CURRENT LIABILITIES:
Current maturities of debt	$-	$599,341
Accounts payable, principally trade	12,922,251	11,009,631
Commodity derivative instruments	-	1,340,451
Asset retirement obligations	359,659	376,735
Other accrued liabilities	1,875,211	2,572,680

Total current liabilities	15,157,121	15,898,838

LONG-TERM DEBT	31,450,000	39,500,000

OTHER NONCURRENT LIABILITIES:
Asset retirement obligations	9,717,448	9,819,648
Commodity derivative instruments	-	1,215,551
Deferred rent	286,907	-
Employee stock awards	93,669	-

Total other noncurrent liabilities	10,098,024	11,035,199

COMMITMENTS AND CONTINGENCIES (Note 14)

EQUITY
Series D convertible preferred stock
($0.001 par value, 7,000,000 authorized, 1,871,373 issued as of September 30,
2017, and 1,776,718 issued as of December 31, 2016, $11.07 per share
liquidation preference)	1,872	1,777
Common stock
($0.001 par value, 100 million shares authorized, 12,559,608 outstanding as of
September 30, 2017 and 12,201,884 outstanding as of December 31, 2016)	12,560	12,202
Common stock subscribed (9,600,000 shares, funds received October 3, 2017)	9,600	-
Additional paid-in capital	54,035,879	43,877,563
Treasury stock at cost (12,433 shares as of September 30, 2017 and -0- shares as
of December 31, 2016)	(24,432)	-
Accumulated earnings (deficit)	(14,265,735)	(12,386,668)

Total equity	39,769,744	31,504,874

TOTAL LIABILITIES AND EQUITY	$96,474,889	$97,938,911

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

Yuma Energy, Inc.

CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

	Three Months Ended September 30,		Nine Months Ended September 30,
	2017	2016	2017	2016

REVENUES:
Sales of natural gas and crude oil	$5,816,883	$3,048,249	$19,516,011	$8,579,137

EXPENSES:
Lease operating and production costs	2,509,352	1,233,626	8,229,740	3,311,402
General and administrative – stock-based
compensation	414,660	380,460	851,492	1,664,855
General and administrative – other	1,622,528	1,717,627	5,705,159	8,153,874
Depreciation, depletion and amortization	2,761,668	1,524,877	8,666,052	5,357,207
Asset retirement obligation accretion expense	138,867	51,885	418,890	158,960
Impairment of oil and gas properties	-	12,735	-	17,560,918
Bad debt expense net of recoveries	(38,706)	16,602	34,807	32,352
Total expenses	7,408,369	4,937,812	23,906,140	36,239,568

LOSS FROM OPERATIONS	(1,591,486)	(1,889,563)	(4,390,129)	(27,660,431)

OTHER INCOME (EXPENSE):
Net gains (losses) from commodity derivatives	(1,260,280)	128,177	4,434,583	(161,161)
Interest expense	(429,313)	(81,168)	(1,407,689)	(195,006)
Gain (loss) on other property and equipment	-	-	484,768	-
Other, net	14,043	1,157	56,110	14,622
Total other income (expense)	(1,675,550)	48,166	3,567,772	(341,545)

INCOME (LOSS) BEFORE INCOME TAXES	(3,267,036)	(1,841,397)	(822,357)	(28,001,976)

Income tax expense	2,539	33,635	8,489	6,866

NET INCOME (LOSS)	(3,269,575)	(1,875,032)	(830,846)	(28,008,842)

PREFERRED STOCK:
Dividends paid in kind	359,311	335,199	1,048,221	981,347

NET INCOME (LOSS) ATTRIBUTABLE TO
COMMON STOCKHOLDERS	$(3,628,886)	$(2,210,231)	$(1,879,067)	$(28,990,189)

INCOME (LOSS) PER COMMON SHARE:
Basic	$(0.29)	$(0.30)	$(0.15)	$(3.89)
Diluted	$(0.29)	$(0.30)	$(0.15)	$(3.89)

WEIGHTED AVERAGE NUMBER OF
COMMON SHARES OUTSTANDING:
Basic	12,483,724	7,444,542	12,311,087	7,446,986
Diluted	12,483,724	7,444,542	12,311,087	7,446,986

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

Yuma Energy, Inc.

CONSOLIDATED STATEMENT OF CHANGES IN EQUITY

(Unaudited)

	Preferred Stock		Common Stock		Common Stock Subscribed		Additional Paid-in Capital	Treasury Stock	Accumulated Deficit	Stockholders' Equity
	Shares	Value	Shares	Value	Shares	Value
December 31, 2016	1,776,718	$1,777	12,201,884	$12,202	-	$-	$43,877,563	$-	$(12,386,668)	$31,504,874
Net income	-	-	-	-	-	-	-	-	(830,846)	(830,846)
Payment of Series "D" dividends
in kind	94,655	95	-	-	-	-	1,048,126	-	(1,048,221)	-
Public offering proceeds net of
$1.2 million costs (funds received
and stock issued October 3, 2017)	-	-	-	-	9,600,000	9,600	8,394,486	-	-	8,404,086
Stock awards vested	-	-	30,446	31	-	-	(31)	-	-	-
Restricted stock awards issued	-	-	329,491	329	-	-	(329)	-	-	-
Restricted stock awards forfeited	-	-	(2,213)	(2)	-	-	2	-	-	-
Amortization of stock-based
compensation	-	-	-	-	-	-	716,062	-	-	716,062
Treasury stock (surrendered to
settle employee tax liabilities)	-	-	-	-	-	-	-	(24,432)	-	(24,432)
September 30, 2017	1,871,373	$1,872	12,559,608	$12,560	9,600,000	$9,600	$54,035,879	$(24,432)	$(14,265,735)	$39,769,744

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

Yuma Energy, Inc.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Nine Months Ended September 30,
	2017	2016
CASH FLOWS FROM OPERATING ACTIVITIES:
Reconciliation of net income (loss) to net cash provided by (used in)
operating activities:
Net income (loss)	$(830,846)	$(28,008,842)
Depreciation, depletion and amortization of property and equipment	8,666,052	5,357,207
Impairment of oil and gas properties	-	17,560,918
Amortization of debt issuance costs	277,293	-
Net deferred income tax expense	-	6,866
Deferred rent liability, net	163,962	-
Stock-based compensation expense	851,492	1,664,855
Settlement of asset retirement obligations	(430,415)	(17,890)
Accretion of asset retirement obligation	418,890	158,960
Bad debt expense	34,807	32,352
Net (gains) losses from commodity derivatives	(4,434,583)	161,161
Gain on sales of fixed assets	(556,141)	-
Loss on write-off of abandoned facilities	71,373	-
Gain on write-off of liabilities net of assets	(34,835)	-
Changes in assets and liabilities:
Decrease in accounts receivable	736,959	2,988,184
(Increase) decrease in prepaids, deposits and other assets	715,603	656,948
(Decrease) increase in accounts payable and other current and
non-current liabilities	(1,177,583)	(1,488,521)
NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES	4,472,028	(927,802)

CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures for oil and gas properties	(5,964,781)	(9,878,724)
Proceeds from sale of oil and gas properties	5,400,563	-
Proceeds from sale of other fixed assets	645,791	-
Derivative settlements	1,103,525	1,319,517
NET CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES	1,185,098	(8,559,207)

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings	-	9,000,000
Net repayments on the senior credit facility	(8,050,000)	-
Repayments of borrowings - insurance financing	(599,341)	-
Debt issuance costs	(323,593)	-
Costs for common stock offering	(15,087)	-
Treasury stock repurchases	(24,432)	(408,323)
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES	(9,012,453)	8,591,677

NET DECREASE IN CASH AND CASH EQUIVALENTS	(3,355,327)	(895,332)

CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD	3,625,686	4,064,094

CASH AND CASH EQUIVALENTS AT END OF PERIOD	$270,359	$3,168,762

Supplemental disclosure of cash flow information:
Interest payments (net of interest capitalized)	$1,021,249	$193,985
Income tax refund	$20,699	$-
Supplemental disclosure of significant non-cash activity:
(Increase) decrease in capital expenditures financed by accounts payable	$(3,291,386)	$498,140
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.

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. More recently, the Company has begun acquiring acreage in Yoakum County, Texas, with plans to explore and develop oil and natural gas assets in the Permian Basin. Finally, the Company has operated positions in Kern County, California, and non-operated positions in the East Texas Woodbine and the Bakken Shale in North Dakota.

On October 26, 2016, Yuma Energy, Inc., a California corporation (“Yuma California”), merged (the “Reincorporation Merger”) with and into Yuma. Pursuant to the Reincorporation Merger, Yuma California was reincorporated in Delaware as Yuma. Immediately thereafter, a wholly owned subsidiary of Yuma merged (the “Davis Merger”) with and into privately-held Davis Petroleum Acquisition Corp., a Delaware corporation (“Davis”). As a result of the Davis Merger, Davis became a wholly owned subsidiary of Yuma.

Prior to the Reincorporation Merger, each share of Yuma California’s existing 9.25% Series A Cumulative Redeemable Preferred Stock (the “Yuma California Series A Preferred Stock”) was converted into 35 shares of common stock of Yuma California (“Yuma California Common Stock”). As a result of the closing of the Reincorporation Merger, each share of Yuma California Common Stock was converted into one-twentieth of one share (the “Reverse Stock Split”) of common stock of Yuma (the “common stock”). As a result of the Reverse Stock Split, Yuma issued an aggregate of approximately 4.75 million shares of its common stock.

As a result of the Davis Merger, Yuma issued approximately 7.45 million shares of its common stock to the former stockholders of Davis’ common stock. Yuma also issued approximately 1.75 million shares of Series D Convertible Preferred Stock of Yuma (the “Series D Preferred Stock”) to existing Davis preferred stockholders. Upon completion of the Reincorporation Merger and the Davis Merger, there was an aggregate of approximately 12.2 million shares of common stock outstanding and 1.75 million shares of Series D Preferred Stock outstanding.

At the closing of the Davis Merger, Davis appointed a majority of the board of directors of Yuma. Four out of the five members of Yuma’s board of directors prior to the closing of the Davis Merger continued to serve on the board of directors of Yuma, with one of those four directors having been appointed by Davis. Three additional directors were appointed by Davis. The Davis Merger was accounted for as a “reverse acquisition” and a recapitalization since the former common stockholders of Davis have control over the combined company through their post-merger 61.1% ownership of the common stock and majority representation on Yuma’s board of directors.

The Davis Merger was accounted for as a business combination in accordance with ASC 805 Business Combinations (“ASC 805”). ASC 805, among other things, requires assets acquired and liabilities assumed to be measured at their acquisition date fair value. Although Yuma was the legal acquirer, Davis was the accounting acquirer. The historical financial statements are therefore those of Davis. Hence, the financial statements included in this report reflect (i) the historical results of Davis prior to the Davis Merger; (ii) the combined results of the Company following the Davis Merger; (iii) the acquired assets and liabilities of Davis at their historical cost; and (iv) the fair value of Yuma’s assets and liabilities as of the closing of the Davis Merger.

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, 2017; the Consolidated Statements of Operations for the three and nine months ended September 30, 2017 and 2016; the Consolidated Statement of Changes in Equity for the nine months ended September 30, 2017; and the Consolidated Statements of Cash Flows for the nine months ended September 30, 2017 and 2016. The Company’s Consolidated Balance Sheet at December 31, 2016 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, 2016.

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, 2016. 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. Reclassifications include moving COPAS overhead recoveries from lease operating expenses to general and administrative expenses, moving certain other revenue to offset lease operating expense, moving commodity derivative gains (losses) from expenses to other income (expense), moving regulatory interest from general and administrative to interest expense, and moving gain (loss) on other property and equipment from operating expenses to other income (expense).

NOTE 2 – Changes in Accounting Principles

Not Yet Adopted

In May 2017, the Financial Accounting Standards Board (“FASB”) issued ASU 2017-09, “Compensation – Stock Compensation (Topic 718): Scope of Modification Accounting.” The purpose of this update is to provide clarity as to which modifications of awards require modification accounting under Topic 718, whereas previously issued guidance frequently resulted in varying interpretations and a diversity of practice. An entity should employ modification accounting unless the following are met: (1) the fair value of the award is the same immediately before and after the award is modified; (2) the vesting conditions are the same under both the modified award and the original award; and (3) the classification of the modified award is the same as the original award, either equity or liability. Regardless of whether modification accounting is utilized, award disclosure requirements under Topic 718 remain unchanged. ASU 2017-09 will be effective for annual or any interim periods beginning after December 15, 2017. The Company does not believe adoption of ASU 2017-09 will have a material impact on its financial statements.

In August 2017, the FASB issued ASU 2017-12, “Derivatives and Hedging (Topic 815)”, which makes significant changes to the current hedge accounting rules. The new guidance impacts the designation of hedging relationships; measurement of hedging relationships; presentation of the effects of hedging relationships; assessment of hedge effectiveness; and disclosures. The guidance is effective for annual periods beginning after December 15, 2018, including interim periods within those annual periods. The Company has elected not to apply hedge accounting in accordance with current GAAP, and therefore does not believe the adoption of ASU 2017-12 will have a material impact on its consolidated financial statements and related disclosures.

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 does not expect the adoption of this ASU to have a material impact on its Consolidated Statements of Cash Flows.

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

In January 2016, the FASB issued ASU 2016-01, “Recognition and Measurement of Financial Assets and Financial Liabilities,” which changes certain guidance related to the recognition, measurement, presentation and disclosure of financial instruments. This update is effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years. Early adoption is not permitted for the majority of the update, but is permitted for two of its provisions. The Company is evaluating the new guidance, but does not believe that it will materially impact the Company’s consolidated financial statement presentation.

In May 2014, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers (Topic 606).” In March, April, and May of 2016, the FASB issued rules clarifying several aspects of the new revenue recognition standard. The new guidance is effective for fiscal years and interim periods beginning after December 15, 2017. This guidance outlines a new, single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance, including industry-specific guidance. This new revenue recognition model provides a five-step analysis in determining when and how revenue is recognized. The new model will require revenue recognition to depict the transfer of promised goods or services to customers in an amount that reflects the consideration a company expects to receive in exchange for those goods and services. The new standard also requires more detailed disclosures related to the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. The Company will not early adopt the standard although early adoption is permitted. The Company is currently evaluating whether to apply the retrospective approach or modified retrospective approach with the cumulative effect recognized as of the date of initial application. The Company is currently evaluating the impact the standard is expected to have on its consolidated financial statements by evaluating current revenue streams and evaluating contracts under the revised standards. Based upon the Company’s preliminary analysis, the Company does not expect the adoption of this ASU to have a material impact on its consolidated financial statements.

Recently adopted

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 provides a screen that when substantially all of the fair value of the gross assets acquired, or disposed of, are concentrated in a single identifiable asset, or a group of similar identifiable assets, the set will not be considered a business. If the screen is not met, a set must include an input and a substantive process that together significantly contribute to the ability to create an output to be considered 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, and expects that the adoption of this ASU could have a material impact on future consolidated financial statements as future oil and gas asset acquisitions may not be considered businesses.

The FASB issued ASU 2016-09, “Compensation—Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting,” which simplifies 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. 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.

The FASB issued ASU 2014-15, “Presentation of Financial Instruments – Going Concern,” which requires management of an entity to evaluate whether there are conditions or events, considered in the aggregate, that raise substantial doubt about the entity’s ability to continue as a going concern within one year after the date that the financial statements are issued or available to be issued. This update is effective for annual periods ending after December 15, 2016. The adoption of this standard did not have a material impact on the Company’s consolidated financial statements.

NOTE 3 – 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 ceiling limits these costs to an amount equal to the present value, discounted at 10%, of estimated future net cash flows from estimated proved reserves less estimated future operating and development costs, abandonment costs (net of salvage value) and estimated related future income taxes. In accordance with SEC rules, prices used are the 12 month average prices, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12 month period prior to the end of the reporting period, unless prices are defined by contractual arrangements. Prices are adjusted for “basis” or location differentials. Prices are held constant over the life of the reserves. The Company’s third quarter of 2017 full cost ceiling calculation was prepared by the Company using (i) $49.81 per barrel for oil, and (ii) $3.00 per MMBTU for natural gas as of September 30, 2017. 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 month periods ended September 30, 2017 and 2016, the Company recorded full cost ceiling impairments after income taxes of $-0- and $12,735, respectively. During the nine month periods ended September 30, 2017 and 2016, the Company recorded full cost ceiling impairments after income taxes of $-0- and $17.6 million, respectively.

NOTE 4 – Asset Retirement Obligations

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

The following table summarizes the Company’s ARO transactions recorded during the nine months ended September 30, 2017 in accordance with the provisions of FASB ASC Topic 410, “Asset Retirement and Environmental Obligations”:

	Nine Months Ended
	September 30, 2017
Asset retirement obligations at December 31, 2016	$10,196,383
Liabilities incurred	-
Liabilities settled	(873,728)
Liabilities sold	(418,527)
Accretion expense	418,890
Revisions in estimated cash flows	754,089

Asset retirement obligations at September 30, 2017	$10,077,107

Based on expected timing of settlements, $359,659 of the ARO is classified as current at September 30, 2017.

NOTE 5 – Fair Value Measurements

Certain financial instruments are reported at fair value on the Company’s 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, 2017
		Significant
	Quoted prices	other	Significant
	in active	observable	unobservable
	markets	inputs	inputs
	(Level 1)	(Level 2)	(Level 3)	Total
Assets (liabilities):
Commodity derivatives – oil	$-	$894,423	$-	$894,423
Commodity derivatives – gas	-	(119,367)	-	(119,367)
Total assets	$-	$775,056	$-	$775,056

	Fair value measurements at December 31, 2016
		Significant
	Quoted prices	other	Significant
	in active	observable	unobservable
	markets	inputs	inputs
	(Level 1)	(Level 2)	(Level 3)	Total
Liabilities:
Commodity derivatives – oil	$-	$956,997	$-	$956,997
Commodity derivatives – gas	-	1,599,005	-	1,599,005
Total liabilities	$-	$2,556,002	$-	$2,556,002

Derivative instruments listed above include swaps and three-way collars (see Note 6 – Commodity Derivative Instruments).

Debt – The Company’s debt is recorded at the carrying amount on its Consolidated Balance Sheets (see Note 10 – Debt and Interest Expense). 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 4 – Asset Retirement Obligations). Therefore, the Company has designated these liabilities as Level 3.

NOTE 6 – 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.

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, 2017 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”).

	2017	2018	2019
	Settlement	Settlement	Settlement
NATURAL GAS (MMBtu):
Swaps
Volume	517,916	1,725,133	373,906
Price	$3.13	$3.00	$3.00

3-way collars
Volume	41,712	-	-
Ceiling sold price (call)	$3.39	-	-
Floor purchased price (put)	$3.03	-	-
Floor sold price (short put)	$2.47	-	-

CRUDE OIL (Bbls):
Swaps
Volume	31,927	195,152	156,320
Price	$52.24	$53.17	$53.77

3-way collars
Volume	26,637	-	-
Ceiling sold price (call)	$77.00	-	-
Floor purchased price (put)	$60.00	-	-
Floor sold price (short put)	$45.00	-	-

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, 2017	December 31, 2016
Asset commodity derivatives:
Current assets	$514,385	$734,464
Noncurrent assets	504,109	54,380
	1,018,494	788,844

Liability commodity derivatives:
Current liabilities	(154,420)	(2,074,915)
Noncurrent liabilities	(89,018)	(1,269,931)
	(243,438)	(3,344,846)

Total commodity derivative instruments	$775,056	$(2,556,002)

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,
	2017	2016	2017	2016

Derivative settlements	$552,850	$259,617	$1,103,525	$1,319,517
Mark to market on commodity derivatives	(1,813,130)	(131,440)	3,331,058	(1,480,678)
Net gains (losses) from commodity derivatives	$(1,260,280)	$128,177	$4,434,583	$(161,161)

NOTE 7 – Preferred Stock

The Company issued an aggregate of 1,754,179 shares of Series D Preferred Stock as part of the completion of the Davis Merger to former holders of Series A Preferred Stock, which is convertible into shares of the Company’s common stock. Each share of 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 was $11.0741176 as of September 30, 2017. 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, 2017, the Series D Preferred Stock had a liquidation preference of approximately $20.7 million and a conversion rate of $11.0741176 per share. The conversion price of the Series D Preferred Stock was adjusted as a result of our common stock offering that closed in October 2017. See Note 15 – Subsequent Events. The Series D Preferred Stock provides for cumulative dividends of 7.0% per annum, payable in-kind. The Company issued 32,446 and 94,655 shares of Series D Preferred Stock as in-kind dividends for the three and nine months ended September 30, 2017, respectively. The Company does not have any dividends in arrears at September 30, 2017.

NOTE 8 – Stock-Based Compensation

2014 Long-Term Incentive Plan

On October 26, 2016, Yuma assumed the Yuma California 2014 Long-Term Incentive Plan (the “2014 Plan”), which was approved by the shareholders of Yuma California. The shareholders of Yuma California originally approved the 2014 Plan at the special meeting of shareholders on September 10, 2014 and the subsequent amendment to the 2014 Plan at the special meeting of shareholders on October 26, 2016. Under the 2014 Plan, Yuma may 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. Yuma 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 of Yuma and its subsidiaries, subject to the conditions set forth in the 2014 Plan. Generally, all classes of the Company’s employees are eligible to participate in the 2014 Plan.

The 2014 Plan provides that a maximum of 2,495,000 shares of common stock may be issued in conjunction with awards granted under the 2014 Plan. As of the closing of the Reincorporation Merger, there were awards for approximately 179,165 shares of common stock outstanding. Awards that are forfeited under the 2014 Plan will again be eligible for issuance as though the forfeited awards had never been issued. Similarly, awards settled in cash will not be counted against the shares authorized for issuance upon exercise of awards under the 2014 Plan.

The 2014 Plan provides that a maximum of 1,000,000 shares of common stock may be issued in conjunction with incentive stock options granted under the 2014 Plan. The 2014 Plan also limits the aggregate number of shares of common stock that may be issued in conjunction with stock options and/or SARs to any eligible employee in any calendar year to 1,500,000 shares. The 2014 Plan also limits the aggregate number of shares of common stock that may be issued in conjunction with the grant of RSAs, RSUs, performance unit awards, stock awards and other incentive awards to any eligible employee in any calendar year to 700,000 shares.

At September 30, 2017, 943,349 shares of the 2,495,000 shares of common stock originally authorized under active share-based compensation plans remained available for future issuance. Yuma generally issues new shares to satisfy awards under employee share-based payment plans. The number of shares available is reduced by awards granted.

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

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

Equity Based Awards – During the three months ended September 30, 2017, the Company did not grant any equity based awards.

Liability Based Awards – During the three months ended September 30, 2017, the Company did not grant any liability based awards.

Total share-based compensation expenses recognized for the three months ended September 30, 2017 and 2016 were $414,660 (none capitalized) and $380,460 (none capitalized), respectively. For the nine months ended September 30, 2017 and 2016, total share-based compensation expenses recognized were $851,492 (none capitalized) and $1,664,855 (net of capitalized amount of $1,715,810), respectively.

NOTE 9 – Earnings Per Common Share

Earnings per common share – Basic is calculated by dividing net income (loss) attributable to common shareholders by the weighted average number of shares of common stock outstanding during the period. Earnings per common share – Diluted assumes the conversion of all potentially dilutive securities, and is calculated by dividing net income (loss) attributable to common shareholders by the sum of the weighted average number of shares of common stock outstanding plus potentially dilutive securities. Earnings per common share – Diluted considers the impact of potentially dilutive securities except in periods where their inclusion would have an anti-dilutive effect. Equity, including the average number of shares of common stock and per share amounts, has been retroactively restated to reflect the Davis Merger.

A reconciliation of earnings per common share is as follows:

	Three Months Ended September 30,		Nine Months Ended September 30,
	2017	2016	2017	2016

Net income (loss) attributable to common stockholders	$(3,628,886)	$(2,210,231)	$(1,879,067)	$(28,990,189)

Weighted average common shares outstanding
Basic	12,483,724	7,444,542	12,311,087	7,446,986
Add potentially dilutive securities:
Unvested restricted stock awards	-	-	-	-
Stock appreciation rights	-	-	-	-
Stock options	-	-	-	-
Series A preferred stock	-	-	-	-
Series D preferred stock	-	-	-	-
Diluted weighted average common shares outstanding	12,483,724	7,444,542	12,311,087	7,446,986

Net income (loss) per common share:
Basic	$(0.29)	$(0.30)	$(0.15)	$(3.89)
Diluted	$(0.29)	$(0.30)	$(0.15)	$(3.89)

NOTE 10 – Debt and Interest Expense

Long-term debt consisted of the following:

	September 30,	December 31,
	2017	2016

Senior credit facility	$31,450,000	$39,500,000
Installment loan due 7/15/17 originating from the financing of
insurance premiums at 4.38% interest rate	-	599,341
Total debt	31,450,000	40,099,341
Less: current maturities	-	(599,341)
Total long-term debt	$31,450,000	$39,500,000

Senior Credit Facility

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

The borrowing base of the credit facility was reaffirmed on September 8, 2017 at $40.5 million. The borrowing base is generally subject to redetermination on April 1st and October 1st of each year, as well as special redeterminations described in the Credit Agreement. 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, 2017 was 4.99% for LIBOR-based debt and 7.0% for prime-based debt. Principal amounts outstanding under the credit facility are due and payable in full at maturity on October 26, 2019. All of the obligations under the Credit Agreement, and the guarantees of those obligations, are secured by substantially all of the Company’s assets. Additional payments due under the Credit Agreement include paying a commitment fee to the Lender in respect of the unutilized commitments thereunder. The commitment rate is 0.50% per year of the unutilized portion of the borrowing base in effect from time to time. The Company is also required to pay customary letter of credit fees.

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

In addition, the Credit Agreement requires the Company to maintain the following financial covenants: a current ratio of not less than 1.0 to 1.0 on the last day of each quarter, a ratio of total debt to earnings before interest, taxes, depreciation, depletion, amortization and exploration expenses (“EBITDAX”) ratio of not greater than 3.5 to 1.0 for the four fiscal quarters ending on the last day of the fiscal quarter immediately preceding such date of determination, and a ratio of EBITDAX to interest expense of not less than 2.75 to 1.0 for the four fiscal quarters ending on the last day of the fiscal quarter immediately preceding such date of determination, and cash and cash equivalent investments together with borrowing availability under the Credit Agreement of at least $4.0 million. The Credit Agreement contains customary affirmative covenants and defines events of default for credit facilities of this type, including failure to pay principal or interest, breach of covenants, breach of representations and warranties, insolvency, judgment default, and a change of control. Upon the occurrence and continuance of an event of default, the Lender has the right to accelerate repayment of the loans and exercise its remedies with respect to the collateral. As of September 30, 2017 and December 31, 2016, the Company was in compliance with the covenants under the Credit Agreement.

NOTE 11 – Stockholders’ Equity

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

The Company assumed the 2014 Plan upon the completion of the Reincorporation Merger as described in Note 8 – Stock-Based Compensation, which describes outstanding stock options, RSAs and SARs granted under the 2014 Plan.

Common Stock Offering

On September 28, 2017, the Company entered into an underwriting agreement with Northland Securities, Inc., as representative of the underwriters (the “Underwriters”) for a public offering of 9,600,000 shares of common stock (excluding the 1,440,000 shares that may be purchased pursuant to the underwriter’s overallotment option), at a public offering price of $1.00 per share. The Company received net proceeds from this offering of $8.4 million, after deducting underwriters’ fees and offering expenses of $1.2 million. The Company recorded a subscription receivable of $8,690,400 on September 30, 2017 in connection with the Company’s entry into a firm underwriting agreement, and accrued $271,227 of additional offering costs. The Company received the $8,690,400 on October 3, 2017 in connection with the closing of the offering. See Note 15 – Subsequent Events.

NOTE 12 – Income Taxes

The Company’s effective tax rate for the three months ended September 30, 2017 and 2016 was (0.08%) and (1.83%), respectively. The difference between the statutory federal income taxes calculated using a U.S. Federal statutory corporate income tax rate of 35% and the Company’s effective tax rate of (0.08%) for the three months ended September 30, 2017 is primarily related to the valuation allowance on the deferred tax assets and state income taxes. The difference between the statutory federal income taxes calculated using a U.S. Federal statutory corporate income tax rate of 35% and the Company’s effective tax rate of (1.83%) for the three months ended September 30, 2016 is primarily related to the full valuation allowance against its Federal and Louisiana net deferred tax assets.

The Company’s effective tax rate for the nine months ended September 30, 2017 and 2016 was (1.03%) and (0.02%), respectively. The difference between the statutory federal income taxes calculated using a U.S. Federal statutory corporate income tax rate of 35% and the Company’s effective tax rate of (1.03%) for the nine months ended September 30, 2017 is primarily related to the valuation allowance on the deferred tax assets. The difference between the statutory federal income taxes calculated using a U.S. Federal statutory corporate income tax rate of 35% and the Company’s effective tax rate of (0.02%) for the nine months ended September 30, 2016 is primarily related to the full valuation allowance against its Federal and Louisiana net deferred tax assets.

As of September 30, 2017, the Company had federal and state net operating loss carryforwards of approximately $133.6 million which expire between 2022 and 2037. Of this amount, approximately $61.3 million is subject to limitation under Section 382 of the Internal Revenue Code of 1986, as amended, which could result in some amounts expiring prior to being utilized. Realization of a deferred tax asset is dependent, in part, on generating sufficient taxable income prior to expiration of the loss carryforwards.

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

NOTE 13 – Oil and Gas Asset Sales

On May 22, 2017 and effective as of January 1, 2017, the Company sold certain oil and natural gas properties for $5.5 million located in Brazos County, Texas known as the El Halcón property. The Company’s El Halcón property consisted of an average working interest of approximately 8.5% (1,557 net acres) producing approximately 140 Boe/d net from 50 Eagle Ford wells and one Austin Chalk well.

NOTE 14 – 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 acquired an 87.5% working interest in approximately 2,841 acres (2,486 net acres) as of September 30, 2017. As the operator of the property covered by the JDA, the Company is committed to spend an additional $1.5 million by March 2020. The Company intends to acquire additional leasehold acreage and begin drilling its first joint venture well in fourth quarter of 2017.

Throughput Commitment Agreement

On August 1, 2014, Crimson Energy Partners IV, LLC (“Crimson”), 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 based on production to lease operating expense (“LOE”) on a monthly basis. On a net basis, the Company anticipates accruing approximately $30,000 in LOE per month, which represents the maximum amounts that could be owed based upon the Commitment.

Lease Agreement

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 goes into effect on January 1, 2018. In addition, the lease amendment included seven months of abated rent and additional rent expense associated with 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 begins on January 1, 2018) starts at $258,060 per annum and escalates to $288,420 per annum during the final 19 months of the lease extension. In addition to the base rent amount, the Company will also be responsible for additional rent expense associated with the operating cost of the building as well as parking charges once the abatement period ends. The Company accounts for the lease as an operating lease under GAAP.

Certain Legal Proceedings

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

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 have selected an arbitrator, and the arbitration hearing is presently set for January 9, 2018. Management intends to pursue the Company’s claims and to defend the counterclaim vigorously.

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

On October 13, 2016, two subsidiaries of the Company, 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. 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 case has been removed to federal district court for the Eastern District of Louisiana. A motion to remand has been filed and the Court officially remanded the case on July 6, 2017. Exceptions for the Company and the other defendants have been filed; however, the hearing for such exceptions has been continued from the original date of October 6, 2017 to November 22, 2017.

Davis - Cameron Parish vs. BEPCO LP, et al & Davis - 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, 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. Motions to remand have been filed but have not yet been ruled upon.

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.

Louisiana Severance Tax Audit

The State of Louisiana, Department of Revenue, notified Exploration that it was auditing Exploration’s calculation of its severance tax relating to Exploration’s production from November 2012 through March 2016. The audit relates to the Department of Revenue’s recent interpretation of long-standing oil purchase contracts to include a disallowable “transportation deduction,” and thus to assert that the severance tax paid on crude oil sold during the contract term was not properly calculated. The Department of Revenue sent a proposed assessment in which they sought to impose $476,954 in additional state severance tax plus associated penalties and interest. Exploration engaged legal counsel to protest the proposed assessment and request a hearing. Exploration then entered a Joint Defense Group of operators challenging similar audit results. Since the Joint Defense Group is challenging the same legal theory, the Board of Tax Appeals proposed to hear a motion brought by one of the taxpayers that would address the rule for all through a test case. Exploration’s case has been stayed pending adjudication of the test case. The hearing for the test case was held on November 7, 2017, and the Company is currently waiting on a decision from the Board of Tax Appeals.

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 and is reviewing the LDWF analysis.

Miami Corporation – South Pecan Lake Field Area P&A

The Company, along with several other E&P companies in the chain of title, received letters from representatives of Miami Corporation demanding the performance of well P&A, facility removal and restoration obligations for wells in the South Pecan Lake Field Area, Cameron Parish, Louisiana. The Company is currently evaluating the merits of the claim.

NOTE 15 – Subsequent Events

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

On October 3, 2017, the Company closed its common stock offering of 9,600,000 shares of common stock.

On October 31, 2017, the Underwriters exercised their overallotment option and purchased 500,000 shares of common stock at the public offering price of $1.00 per share. The Company received net proceeds of approximately $462,000 after deducting underwriters’ fees and expenses.

On October 3, 2017, at the closing of the Company’s common stock offering, the Company issued 9,600,000 shares of common stock and at the closing of the overallotment option on October 31, 2017, the Company issued 500,000 shares of its common stock, resulting in an adjustment to the conversion price of the Series D preferred stock from $11.0741176 per share to $6.5838109 per share, resulting in the issuance of approximately 3,147,693 shares of common stock if all of the outstanding shares of Series D preferred stock were to be converted.

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, 2016.

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. More recently, we have begun acquiring acreage in Yoakum County, Texas, with plans to explore and develop oil and natural gas assets in the Permian Basin. Finally, we have operated positions in Kern County, California, and non-operated positions in the East Texas Woodbine and the Bakken Shale in North Dakota. Our common stock is listed on the NYSE American under the trading symbol “YUMA.”

Common Stock Offering

On September 28, 2017, we entered into an underwriting agreement with Northland Securities, Inc., as representative of the underwriters (the “Underwriters”), for a public underwritten offering of 9,600,000 shares of common stock (excluding the 1,440,000 shares that may be purchased pursuant to the underwriter’s overallotment option), at a public offering price of $1.00 per share. On October 31, 2017, the Underwriters exercised their over-allotment option and purchased 500,000 shares of common stock at a public offering price of $1.00 per share. We received net proceeds from this offering of approximately $8.9 million, after deducting underwriters’ fees and offering expenses of $1.2 million.

Entry into the Permian Basin

We recently entered into the Permian Basin through a joint venture with two privately held energy companies and have established an Area of Mutual Interest (“AMI”) covering approximately 33,280 acres in Yoakum County, Texas, located in the Northwest Shelf (“NWS”) of the Permian Basin. The primary target within the AMI will be the San Andres formation, which has been one of the largest producing formations in Texas to date. As of September 30, 2017, we held an 87.5% working interest in approximately 2,841 gross acres (2,486 net acres) within the AMI and intend to apply horizontal drilling technology to the San Andres formation which we believe will result in increased reserves and production on a per well basis. This activity is commonly referred to as the Horizontal San Andres Play, and in certain areas, referred to as a Residual Oil Zone (“ROZ”) Play due to the presence of residual oil zone fairways with substantial recoverable hydrocarbon resources in place. We are the operator of the joint venture and intend on acquiring additional leases offsetting existing acreage. We intend to spud a joint venture well in the fourth quarter of 2017, as well as acquire additional acreage within the AMI.

Sale of Certain Non-Core Oil and Gas Properties

On May 22, 2017 and effective as of January 1, 2017, we sold certain oil and natural gas properties for $5.5 million located in Brazos County, Texas known as the El Halcón property. Our El Halcón property consisted of an average working interest of approximately 8.5% (1,557 net acres) producing approximately 140 Boe/d net from 50 Eagle Ford wells and one Austin Chalk well.

Drilling Results

We drilled the Weyerhaeuser 14-1 well in Livingston Parish to a total depth of 15,088 feet and unsuccessfully tested the Tuscaloosa oil sands from 14,543 feet to 14,550 feet. We are preparing to plug and abandon the well.

Reincorporation and Davis Merger

On October 26, 2016, Yuma Energy, Inc., a California corporation (“Yuma California”), merged with and into Yuma resulting in the reincorporation from California to Delaware (the “Reincorporation Merger”). In connection with the Reincorporation Merger, Yuma California converted each outstanding share of its 9.25% Series A Cumulative Redeemable Preferred Stock (the “Yuma California Series A Preferred Stock”), into 35 shares of its common stock (the “Yuma California Common Stock”), and then each share of Yuma California Common Stock was exchanged for one-twentieth of one share of common stock of Yuma (the “common stock”). Immediately after the Reincorporation Merger on October 26, 2016, a wholly owned subsidiary of Yuma merged (the “Davis Merger”) with and into Davis Petroleum Acquisition Corp., a Delaware corporation (“Davis”), in exchange for approximately 7,455,000 shares of common stock and 1,754,179 shares of Series D Convertible preferred stock (the “Series D preferred stock”). The Series D preferred stock had an aggregate liquidation preference of approximately $19.4 million and a conversion rate of $11.0741176 per share at the closing of the Davis Merger, and will be paid dividends in the form of additional shares of Series D preferred stock at a rate of 7% per annum. As a result of the Davis Merger, the former holders of Davis common stock received approximately 61.1% of the then outstanding common stock of Yuma and thus acquired voting control. Although Yuma was the legal acquirer, for financial reporting purposes the Davis Merger was accounted for as a reverse acquisition of Yuma by Davis.

Preferred Stock

As of November 9, 2017, we had 1,871,373 shares of our Series D preferred stock outstanding with an aggregate liquidation preference of approximately $20.7 million and a conversion rate of $6.5838109 per share. The conversion rate was adjusted from $11.0741176 per share to $6.5838109 per share as a result of our common stock offering that closed in October 2017. As a result, if all of our outstanding shares of Series D preferred stock were converted into common stock, we would need to issue approximately 3.1 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.

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, 2017 and 2016, and the average sales price per unit sold.

	Three Months Ended September 30,		Nine Months Ended September 30,
	2017	2016	2017	2016
Production volumes:
Crude oil and condensate (Bbls)	57,134	32,242	199,774	106,257
Natural gas (Mcf)	757,361	507,521	2,442,899	1,553,906
Natural gas liquids (Bbls)	32,694	23,903	101,260	74,282
Total (Boe) (1)	216,055	140,732	708,184	439,523
Average prices realized:
Crude oil and condensate (per Bbl)	$47.86	$43.45	$48.42	$39.27
Natural gas (per Mcf)	$3.04	$2.46	$3.05	$2.12
Natural gas liquids (per Bbl)	$23.81	$16.66	$23.68	$14.96

(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, 2017 and 2016.

	Three Months Ended September 30,		Nine Months Ended September 30,
	2017	2016	2017	2016
Sales of natural gas and crude oil:
Crude oil and condensate	$2,734,269	$1,400,837	$9,673,049	$4,172,477
Natural gas	2,304,154	1,249,148	7,445,564	3,295,258
Natural gas liquids	778,460	398,264	2,397,398	1,111,402
Total revenues	$5,816,883	$3,048,249	$19,516,011	$8,579,137

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 were 24,892 barrels, or 77.2%, higher for the three months ended September 30, 2017 compared to crude oil volumes sold during the three months ended September 30, 2016, due primarily to the Davis Merger, as Yuma California’s properties from the period prior to the merger contributed 42,706 barrels of oil to the September 30, 2017 total sales volumes. Offsetting this increase were decreases in the El Halcón field (11,368 barrels), which was divested during the second quarter of 2017, and declines in the Cameron Canal field (3,105 barrels). Realized crude oil prices experienced a 10.2% increase from the three months ended September 30, 2016 compared to the three months ended September 30, 2017.

Crude oil volumes increased by 93,517 barrels, or 88.0%, for the nine months ended September 30, 2017 compared to the same period in 2016, due primarily to the Davis Merger, as Yuma California’s properties from the period prior to the merger contributed 134,637 barrels of oil to the period’s total sales volumes. Offsetting this increase were decreases in the El Halcón field (22,197 barrels) due to the sale, and declines in the Chalktown field (10,708 barrels). Realized crude oil prices experienced a 23.3% increase from the nine months ended September 30, 2016 compared to the nine months ended September 30, 2017.

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, 2017 compared to the three months ended September 30, 2016, we experienced a 249,840 Mcf, or 49.2%, increase in natural gas volumes sold and an increase in natural gas liquids sold of 8,791 barrels, or 36.8%. The increases were due primarily to the Davis Merger, as Yuma California’s properties contributed 324,513 Mcf to the September 30, 2017 total sales volumes, as well as an increase in the Lac Blanc field (17,827 Mcf). Offsetting this increase were decreases in the Cameron Canal field (58,895 Mcf) and Chalktown field (24,160 Mcf). Realized natural gas prices experienced a 23.6% increase from the three months ended September 30, 2016 compared to the three months ended September 30, 2017.

For the nine months ended September 30, 2017, natural gas volumes increased by 888,993 Mcf, or 57.2%, and natural gas liquids increased by 26,978 barrels, or 36.3%. The increase was due primarily to the Davis Merger, as Yuma California’s properties contributed 1,062,190 Mcf to the period’s total sales volumes. Offsetting this increase were decreases in the Cameron Canal field (93,846 Mcf) and Chalktown field (87,768 Mcf). Realized natural gas prices experienced a 43.9% increase from the nine months ended September 30, 2016 compared to the nine months ended September 30, 2017.

Expenses

Lease Operating Expenses

Our lease operating expenses (“LOE”) and LOE per Boe for the three and nine months ended September 30, 2017 and 2016, are set forth below:

	Three Months Ended September 30,		Nine Months Ended September 30,
	2017	2016	2017	2016
Lease operating expenses	$1,506,747	$810,115	$5,049,551	$2,043,298
Severance, ad valorem taxes and
marketing	1,002,605	423,511	3,180,189	1,268,104
Total LOE	$2,509,352	$1,233,626	$8,229,740	$3,311,402

LOE per Boe	$11.61	$8.77	$11.62	$7.53
LOE per Boe without severance,
ad valorem taxes and marketing	$6.97	$5.76	$7.13	$4.65

LOE includes all costs incurred to operate wells and related facilities, both operated and non-operated. In addition to direct operating costs such as labor, repairs and maintenance, equipment rentals, materials and supplies, fuel and chemicals, LOE also includes severance taxes, product marketing and transportation fees, insurance, ad valorem taxes and operating agreement allocable overhead.

The 103.4% increase in total LOE for the three months ended September 30, 2017 compared to the three months ended September 30, 2016 was due to the Davis Merger, as Yuma California’s properties contributed $1,526,751 to the total LOE for the quarter. The LOE related to the Davis properties decreased by $251,025, primarily due to the lower severance taxes and production handling costs. LOE per barrel of oil equivalent increased by32.4% from the same period of the prior year generally due to Yuma California’s properties having higher per unit operating costs than the Davis properties.

For the nine months ended September 30, 2017, total LOE increased by 148.5% compared to the same period in 2016. The increase was due to the Davis Merger, as Yuma California’s properties contributed $4,844,013 to the total LOE for the period. The LOE related to the Davis properties increased by $74,325 primarily due to the transportation and marketing charges for the Chalktown field. LOE per barrel of oil equivalent increased by 54.3% from the same period of the prior year generally due to Yuma California’s properties having higher per unit operating costs than the Davis properties.

General and Administrative Expenses

Our general and administrative (“G&A”) expenses for the three and nine months ended September 30, 2017 and 2016, are summarized as follows:

	Three Months Ended September 30,		Nine Months Ended September 30,
	2017	2016	2017	2016
General and administrative:
Stock-based compensation	$414,660	$380,460	$851,492	$3,380,665
Capitalized	-	-	-	(1,715,810)
Net stock-based compensation	414,660	380,460	851,492	1,664,855

Other	2,009,428	2,143,717	6,936,288	9,785,544
Capitalized	(386,900)	(426,090)	(1,231,129)	(1,631,670)
Net other	1,622,528	1,717,627	5,705,159	8,153,874

Net general and administrative expenses	$2,037,188	$2,098,087	$6,556,651	$9,818,729

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

For the three months ended September 30, 2017, net G&A expenses of $2,037,188, were 2.9% lower than the amount for the same period in 2016. Variances include an increase in salaries and consulting fees of $514,542 and $176,670, respectively, offset by a decrease in accounting and audit fees of $280,329 and a decrease in costs associated with the Davis Merger of $448,765.

For the nine months ended September 30, 2017, net G&A expenses of $6,556,651 were 33.2% lower than the amount for the same period in 2016. This decrease was primarily due to an $813,363 decrease in net stock-based compensation, a decrease in salaries and severance amounts of $1,307,315, and a decrease in other merger-related costs of $1,238,054, all associated with the Davis Merger.

Depreciation, Depletion and Amortization

Our depreciation, depletion and amortization (“DD&A”) for the three and nine months ended September 30, 2017 and 2016, is summarized as follows:

	Three Months Ended September 30,		Nine Months Ended September 30,
	2017	2016	2017	2016
DD&A	$2,761,668	$1,524,877	$8,666,052	$5,357,207

DD&A per Boe	$12.78	$10.84	$12.24	$12.19

DD&A increased by 81.1% and 61.8% for the three and nine months ended September 30, 2017, respectively, compared to the same periods in 2016, primarily as a result of the increase in the net quantities of crude oil and natural gas sold. The variance in DD&A per Boe for the three months ended September 30, 2017 compared to the same period in 2016 is related to the Davis Merger.

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. 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. We recorded a full cost ceiling test impairment of $-0- and $12,735 for the three months ended September 30, 2017 and 2016, respectively. For the nine months ended September 30, 2017 and 2016, we recorded a full cost ceiling test impairment of $-0- and $17.6 million. The impact of low commodity prices that adversely affected estimated proved reserve volumes and future estimated revenues was the primary contributor to the 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.

If prices remain at current levels, subject to numerous factors and inherent limitations, and all other factors remain constant, the Company does not expect to incur a non-cash full cost impairment during the fourth quarter of 2017. There are numerous uncertainties inherent in the estimation of proved reserves and accounting for oil and natural gas properties in future periods. Our estimated fourth quarter 2017 full cost ceiling calculation has been prepared by substituting (i) $50.62 per barrel for oil, and (ii) $3.00 per MMBtu for natural gas for the expected realized prices as of December 31, 2017. The forecasted average realized price was based on the average realized price for sales of crude oil, natural gas liquids and natural gas on the first calendar day of each month for the first 11 months and an estimate for the twelfth month based on a quoted forward price. Changes to our reserves and future production were made due to changing the effective date of the evaluation from September 30, 2017 to December 31, 2017. All other inputs and assumptions have been held constant. Accordingly, this estimate accounts for the impact of more current commodity prices in the fourth quarter of 2017 utilized in our full cost ceiling calculation.

Interest Expense

Our interest expense for the three and nine months ended September 30, 2017 and 2016, is summarized as follows:

	Three Months Ended September 30,		Nine Months Ended September 30,
	2017	2016	2017	2016
Interest expense	$525,487	$81,168	$1,615,999	$195,006
Interest capitalized	(96,174)	-	(208,310)	-
Net	$429,313	$81,168	$1,407,689	$195,006

Bank debt	$31,450,000	$9,000,000	$31,450,000	$9,000,000

Interest expense (net of amounts capitalized) increased $348,145 and $1,212,683 for the three and nine months ended September 30, 2017, respectively, over the same periods in 2016 as a result of higher borrowings following the Davis Merger on October 26, 2016.

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

Income Tax Expense

The following summarizes our income tax expense (benefit) and effective tax rates for the three and nine months ended September 30, 2017 and 2016:

	Three Months Ended September 30,		Nine Months Ended September 30,
	2017	2016	2017	2016
Consolidated net income (loss)
before income taxes	$(3,267,036)	$(1,841,397)	$(822,357)	$(28,001,976)
Income tax expense (benefit)	$2,539	$33,635	$8,489	$6,866
Effective tax rate	(0.08%)	(1.83%)	(1.03%)	(0.02%)

Differences between the U.S. federal statutory rate of 35% and our effective tax rates are due to the tax effects of valuation allowances recorded against our deferred tax assets, state income taxes, and non-deductible expenses. Refer to Note 12 – 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.

Cash Flows from Operating Activities

Net cash provided by operating activities was $4,472,028 for the nine months ended September 30, 2017 compared to $927,802 in cash used during the same period in 2016. This increase was primarily caused by increased revenue as a result of higher sales volumes due to the Davis Merger and realized commodity prices, offset by increases in LOE. Funds were also used for changes in assets and liabilities including a decrease of $1,177,583 in accounts payable and other liabilities.

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, 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 Basin acquisition. In addition, $1,231,129 was capitalized G&A related to land, geological and geophysical costs.

During the nine months ended September 30, 2016, cash used in investing activities included $8,559,207 of capital expenditures, a majority of which were related to the drilling and completion of the EE Broussard #1.

Cash Flows from Financing Activities

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

During the nine months ended September 30, 2017, we had net cash used in financing activities of $9,012,453. Of that amount, $8,050,000 was used for repayments on our credit facility and $599,341 was used for payments on our insurance financing. In addition, we paid debt issuance costs of $323,593.

During the nine months ended September 30, 2016, we had borrowings under our credit facility of $9,000,000.

At September 30, 2017, we had a $40,500,000 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.

On September 28, 2017, we entered into an underwriting agreement with the Underwriters for the public underwritten offering of 9,600,000 shares of our common stock (excluding the 1,440,000 shares of common stock that may be purchased pursuant to the underwriter’s overallotment option), at a public offering price of $1.00 per share. On October 31, 2017, the Underwriters exercised their over-allotment option and purchased 500,000 shares of common stock at a public offering price of $1.00 per share. We received net proceeds from this offering of approximately $8.9 million, after deducting underwriters’ fees and offering expenses of $1.2 million.

Credit Facility

The borrowing base of the credit facility was reaffirmed on September 8, 2017 at $40.5 million. The borrowing base is generally subject to redetermination on April 1st and October 1st of each year, as well as special redeterminations described in the Credit Agreement. 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, 2017 was 4.99% for LIBOR-based debt and 7.0% for prime-based debt. Principal amounts outstanding under the credit facility are due and payable in full at maturity on October 26, 2019. All of the obligations under the Credit Agreement, and the guarantees of those obligations, are secured by substantially all of our assets. Additional payments due under the Credit Agreement include paying a commitment fee to the Lender in respect of the unutilized commitments thereunder. The commitment rate is 0.50% per year of the unutilized portion of the borrowing base in effect from time to time. We are also required to pay customary letter of credit fees.

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

In addition, the Credit Agreement requires us to maintain the following financial covenants: a current ratio of not less than 1.0 to 1.0 on the last day of each quarter, a ratio of total debt to earnings before interest, taxes, depreciation, depletion, amortization and exploration expenses (“EBITDAX”) ratio of not greater than 3.5 to 1.0 for the four fiscal quarters ending on the last day of the fiscal quarter immediately preceding such date of determination, and a ratio of EBITDAX to interest expense of not less than 2.75 to 1.0 for the four fiscal quarters ending on the last day of the fiscal quarter immediately preceding such date of determination, and cash and cash equivalent investments together with borrowing availability under the Credit Agreement of at least $4.0 million. The Credit Agreement contains customary affirmative covenants and defines events of default for credit facilities of this type, including failure to pay principal or interest, breach of covenants, breach of representations and warranties, insolvency, judgment default, and a change of control. Upon the occurrence and continuance of an event of default, the Lender has the right to accelerate repayment of the loans and exercise its remedies with respect to the collateral. As of September 30, 2017 and December 31, 2016, we were in compliance with the 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.

Fair Market Value of Commodity Derivatives

	September 30, 2017		December 31, 2016
	Oil	Natural Gas	Oil	Natural Gas
Assets (liabilities)
Current	$395,858	$(35,894)	$-	$-
Noncurrent	$498,565	$(83,473)	$-	$-

Liabilities
Current	$-	$-	$(24,140)	$(1,316,311)
Noncurrent	$-	$-	$(932,857)	$(282,694)

Assets and liabilities are netted within each commodity on the Consolidated Balance Sheets. For the balances without netting, refer to Note 6 – 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, 2017 and December 31, 2016 were $775,056 and ($2,556,002), 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, 2017, 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, 2017 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, 2017 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION

Item 1.

Legal Proceedings.

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 14 – 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 that have arisen or have been updated since the filing of our Annual Report on Form 10-K for the year ended December 31, 2016.

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, 2016 on Form 10-K, which could materially affect our business, financial condition or future results. The risks described in our 2016 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, 2016. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial may materially adversely affect our business, financial condition and/or operating results.

Item 2.

Unregistered Sales of Equity Securities and Use of Proceeds.

	Total Number of Shares Purchased (1)	Average Price Paid Per Share	Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Maximum Number (or Approximate Dollar Value) of Shares that May Yet Be Purchased Under the Plans or Programs
July 2017	533	$2.18	-	-
August 2017	-	-	-	-
September 2017	-	-	-	-

(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.

Item 6.

Exhibits.

EXHIBIT INDEX

FOR

Form 10-Q for the quarter ended September 30, 2017.

Incorporated by Reference

Exhibit No.

Description

Form

SEC File No.

Exhibit

Filing Date

Filed Herewith

Furnished Herewith

31.1

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

31.2

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

32.1

Certification of the Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act.

32.2

Certification of the Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act.

101.INS

XBRL Instance Document.

101.SCH

XBRL Schema Document.

101.CAL

XBRL Calculation Linkbase Document.

101.DEF

XBRL Definition Linkbase Document.

101.LAB

XBRL Label Linkbase Document.

101.PRE

XBRL Presentation Linkbase Document.

SIGNATURES

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

	YUMA ENERGY, INC.

Date: November 13, 2017	By:	/s/ Sam L. Banks
	Name:	Sam L. Banks
	Title:	Chief Executive Officer (Principal Executive Officer)



Date: November 13, 2017	By:	/s/ James J. Jacobs
	Name:	James J. Jacobs
	Title:	Chief Financial Officer (Principal Financial Officer)

Yuma Energy, Inc. - FORM 10-Q - November 13, 2017

Attached files

Yuma Energy, Inc. Reports