YUMA Yuma Energy Inc New

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C.  20549

 

FORM 10-Q

 

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

 

For the quarterly period ended September 30, 2016

 

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

 

For the transition period from                             to

 

Commission File Number: 001-32989

 

Yuma Energy, Inc.

(Exact name of registrant as specified in its charter)

 

CALIFORNIA (State or other jurisdiction of incorporation)

94-0787340 (IRS Employer Identification No.)

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements.

Yuma Energy, Inc.

CONSOLIDATED BALANCE SHEETS

 

	September 30,	December 31,
	2016	2015
	(Unaudited)	(As Restated)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$ 1,831,928	$ 5,355,191
Accounts receivable, net of allowance for doubtful accounts:
Trade	2,942,948	2,829,266
Officers and employees	65,153	75,404
Other	338,461	633,573
Commodity derivative instruments	1,016,583	2,658,047
Prepayments	321,237	704,523
Other deferred charges	29,921	415,740
Total current assets	6,546,231	12,671,744
OIL AND GAS PROPERTIES (full cost method):
Not subject to amortization	15,336,916	14,288,716
Subject to amortization	205,331,835	204,512,038
	220,668,751	218,800,754
Less: accumulated depreciation, depletion and amortization	(134,312,088 )	(117,304,945 )
Net oil and gas properties	86,356,663	101,495,809
OTHER PROPERTY AND EQUIPMENT:
Land, buildings and improvements	2,795,000	2,795,000
Other property and equipment	3,497,948	3,460,507
	6,292,948	6,255,507
Less: accumulated depreciation and amortization	(2,361,010 )	(2,174,316 )
Net other property and equipment	3,931,938	4,081,191
OTHER ASSETS AND DEFERRED CHARGES:
Commodity derivative instruments	177,724	1,070,541
Deposits	414,064	264,064
Other noncurrent assets	-	38,104
Total other assets and deferred charges	591,788	1,372,709
TOTAL ASSETS	$ 97,426,620	$ 119,621,453

 

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

 

 

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Yuma Energy, Inc.

CONSOLIDATED BALANCE SHEETS – CONTINUED

 

	September 30,	December 31,
	2016	2015
	(Unaudited)	(As Restated)
LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Current maturities of debt	$ 29,800,000	$ 30,063,635
Accounts payable, principally trade	6,378,942	7,933,664
Commodity derivative instruments	74,331	-
Asset retirement obligations	243,711	70,000
Other accrued liabilities	2,593,813	1,781,484
Total current liabilities	39,090,797	39,848,783
OTHER NONCURRENT LIABILITIES:
Asset retirement obligations	8,571,895	8,720,498
Commodity derivative instruments	4,432	-
Deferred taxes	144,700	1,417,364
Other liabilities	7,467	30,090
Total other noncurrent liabilities	8,728,494	10,167,952
EQUITY:
Preferred stock	10,828,603	10,828,603
Common stock, no par value (300 million shares authorized, 3,628,991 and 3,591,731 issued)	142,724,775	141,858,946
Accumulated earnings (deficit)	(103,946,049 )	(83,082,831 )
Total equity	49,607,329	69,604,718
TOTAL LIABILITIES AND EQUITY	$ 97,426,620	$ 119,621,453

 

 

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

 

 

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Yuma Energy, Inc.

CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

 

	Three Months Ended September 30,		Nine Months Ended September 30,
	2016	2015	2016	2015
		(As Restated)		(As Restated)
REVENUES:
Sales of natural gas and crude oil	$ 3,151,626	$ 4,649,009	$ 9,207,636	$ 14,756,582
Net gains (losses) from commodity derivatives	447,936	3,893,650	(407,828 )	3,267,239
Total revenues	3,599,562	8,542,659	8,799,808	18,023,821
EXPENSES:
Lease operating	1,798,868	2,718,919	5,692,077	9,168,260
Re-engineering and workovers	132,708	1,136	132,708	555,628
Marketing cost of sales	-	234,507	-	434,189
General and administrative – stock-based compensation	189,211	338,619	909,309	2,210,950
General and administrative – other	1,581,619	1,873,484	5,742,824	5,389,859
Depreciation, depletion and amortization	1,711,043	3,123,812	6,178,248	11,020,278
Asset retirement obligation accretion expense	107,760	170,209	318,016	499,766
Impairments	-	-	11,015,589	4,927,508
Other	6,612	(274,329 )	(10,173 )	444,320
Total expenses	5,527,821	8,186,357	29,978,598	34,650,758
INCOME (LOSS) FROM OPERATIONS	(1,928,259 )	356,302	(21,178,790 )	(16,626,937 )
OTHER INCOME (EXPENSE):
Interest expense	(245,359 )	(131,114 )	(974,403 )	(337,499 )
Other, net	10,745	14,055	17,311	35,521
Total other income (expense)	(234,614 )	(117,059 )	(957,092 )	(301,978 )
NET INCOME (LOSS) BEFORE INCOME TAXES	(2,162,873 )	239,243	(22,135,882 )	(16,928,915 )
Income tax expense (benefit)	(47,429 )	329,653	(1,272,664 )	(3,605,839 )
NET INCOME (LOSS)	(2,115,444 )	(90,410 )	(20,863,218 )	(13,323,076 )
PREFERRED STOCK, PERPETUAL PREFERRED SERIES A:
Dividends paid in cash	-	320,626	-	940,315
Dividends in arrears	320,625	-	961,877	-
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON
STOCKHOLDERS	$ (2,436,069 )	$ (411,036 )	$ (21,825,095 )	$ (14,263,391 )
EARNINGS (LOSS) PER COMMON SHARE ADJUSTED FOR
OCTOBER 26,2016 1-FOR-20 REVERSE STOCK SPLIT:
Basic	$ (0.67 )	$ (0.11 )	$ (6.04 )	$ (4.03 )
Diluted	$ (0.67 )	$ (0.11 )	$ (6.04 )	$ (4.03 )
WEIGHTED AVERAGE NUMBER OF COMMON SHARES
OUTSTANDING ADJUSTED FOR OCTOBER 26, 2016 1-FOR-20
REVERSE STOCK SPLIT:
Basic	3,628,683	3,580,163	3,611,241	3,539,755
Diluted	3,628,683	3,580,163	3,611,241	3,539,755

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

 

 

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Yuma Energy, Inc.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(Unaudited)

 

	Three Months Ended September 30,		Nine Months Ended September 30,
	2016	2015	2016	2015
		(As Restated)		(As Restated)
NET LOSS	$ (2,115,444 )	$ (90,410 )	$ (20,863,218 )	$ (13,323,076 )
OTHER COMPREHENSIVE INCOME (LOSS):
Commodity derivatives sold	-	-	-	(119,917 )
Less income taxes	-	-	-	(46,168 )
Commodity derivatives sold, net of income taxes	-	-	-	(73,749 )
Reclassification of loss on settled
commodity derivatives	-	9,971	-	41,525
Less income taxes	-	3,839	-	15,987
Reclassification of loss on settled
commodity derivatives, net of income taxes	-	6,132	-	25,538
OTHER COMPREHENSIVE INCOME (LOSS)	-	6,132	-	(48,211 )
COMPREHENSIVE LOSS	$ (2,115,444 )	$ (84,278 )	$ (20,863,218 )	$ (13,371,287 )

 

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

 

 

 

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Yuma Energy, Inc.

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

 

	September 30,	December 31,
	2016	2015
	(Unaudited)	(As Restated)
PERPETUAL PREFERRED STOCK - 9.25% CUMULATIVE AND REDEEMABLE, NO PAR VALUE:
Balance at beginning of period: 554,596 for 2016 and 507,739 shares for 2015	$ 10,828,603	$ 9,958,217
Sales of 46,857 shares for 2015	-	870,386
Balance at end of period: 554,596 shares for both 2016 and 2015	10,828,603	10,828,603
COMMON STOCK, NO PAR VALUE:
Balance at beginning of period: 3,591,731 shares for 2016 and 3,456,993 shares for 2015	141,858,946	137,469,772
Sales of 67,373 shares of common stock in 2015	-	1,363,160
Restricted stock awards, of which 51,929 vested in 2016 and 83,806 vested in 2015	725,573	3,171,477
Buy back shares from vested stock awards: 14,669 in 2016 and 16,441 in 2015	(74,422 )	(300,732 )
Stock appreciation rights issued in 2015, of which 39,456 vested in 2016	214,678	155,269
Balance at end of period: 3,628,991 shares for 2016 and 3,591,731 shares for 2015	142,724,775	141,858,946
ACCUMULATED OTHER COMPREHENSIVE INCOME:
Balance at beginning of period	-	38,801
Comprehensive loss from commodity derivative instruments, net of income taxes	-	(38,801 )
Balance at end of period	-	-
ACCUMULATED EARNINGS (DEFICIT):
Balance at beginning of period	(83,082,831 )	(67,195,800 )
Net loss	(20,863,218 )	(14,839,840 )
Series A perpetual preferred stock cash dividends	-	(1,047,191 )
Balance at end of period	(103,946,049 )	(83,082,831 )
TOTAL EQUITY	$ 49,607,329	$ 69,604,718

 

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

 

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Yuma Energy, Inc.

 

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

 

	Nine Months Ended September 30,
	2016	2015
		(As Restated)
CASH FLOWS FROM OPERATING ACTIVITIES:
Reconciliation of net loss to net cash provided by (used in) operating activities
Net loss	$ (20,863,218 )	$ (13,323,076 )
Impairment of oil and gas properties	11,015,589	-
Impairment of goodwill	-	4,927,508
Depreciation, depletion and amortization of property and equipment	6,178,248	11,020,278
Accretion of asset retirement obligation	318,016	499,766
Stock-based compensation net of capitalized cost	909,309	2,210,950
Amortization of other assets and liabilities	518,478	209,904
Deferred tax expense (benefit)	(1,272,664 )	(3,608,239 )
Bad debt expense increase (decrease)	(10,173 )	787,264
Unrealized losses on commodity derivatives	2,613,044	1,847,371
Other	-	(342,944 )
Changes in current operating assets and liabilities:
Accounts receivable	201,854	4,411,640
Other current assets	383,286	(77,453 )
Accounts payable	(1,471,397 )	(13,938,649 )
Other current liabilities	783,551	1,095,356
Other noncurrent assets and liabilities	(108,618 )	-
NET CASH USED IN OPERATING ACTIVITIES	(804,695 )	(4,280,324 )
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures on property and equipment	(2,588,455 )	(11,211,634 )
Proceeds from sale of property	340,603	30,442
Decrease in short-term investments	-	1,170,868
NET CASH USED IN INVESTING ACTIVITIES	(2,247,852 )	(10,010,324 )(
CASH FLOWS FROM FINANCING ACTIVITIES:
Change in borrowing on line of credit	-	$ 6,800,000
Proceeds from insurance note	-	813,562
Payments on insurance note	(263,635 )	(579,005 )
Line of credit financing costs	(132,659 )	(215,141 )
Net proceeds from sale of common stock	-	1,363,160
Net proceeds from sale of perpetual preferred stock	-	870,386
Cash dividends to preferred shareholders	-	(940,315 )
Common stock purchased from employees	(74,422 )	(300,732 )
Other	-	(31,485 )
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES	(470,716 )	7,780,430
NET DECREASE IN CASH AND CASH EQUIVALENTS	(3,523,263 )	(6,510,218 )
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD	5,355,191	11,558,322
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$ 1,831,928	$ 5,048,104
Supplemental disclosure of cash flow information:
Interest payments (net of interest capitalized)	$ 354,344	$ 73,342
Interest capitalized	$ 395,244	$ 750,107
Supplemental disclosure of significant non-cash activity:
(Increase) decrease in capital expenditures financed by accounts payable	$ 83,325	$ 2,979,301

 

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

 

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Yuma Energy, Inc.

UNAUDITED CONDENSED NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

 

NOTE 1 – BASIS OF PRESENTATION

 

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

 

On October 26, 2016, the shareholders of the Company approved, among other proposals, (i) the conversion (the “Series A Conversion”) of the 9.25% Series A Cumulative Redeemable Preferred Stock, no par value per share of the Company (the “Series A Preferred Stock”), into common stock, no par value per share of the Company (the “common stock”), at a rate of 35 shares of common stock for each share of Series A Preferred Stock; (ii) the reincorporation of the Company from California to Delaware pursuant to a merger (the “Reincorporation Merger”) of the Company with and into Yuma Energy, Inc., a Delaware corporation and wholly owned subsidiary of the Company (“Yuma Delaware”); and (iii) the merger (the “Merger”) of Yuma Merger Subsidiary, Inc., a Delaware corporation and wholly owned subsidiary of Yuma Delaware (“Merger Subsidiary”), with and into Davis Petroleum Acquisition Corp., a Delaware corporation (“Davis”) with Davis surviving as a wholly owned subsidiary of Yuma Delaware. The Company issued approximately 19,411,000 shares of common stock as a result of the Series A Conversion. Immediately following the Series A Conversion, each share of common stock was exchanged for one-twentieth of one share of common stock, $0.001 par value per share of Yuma Delaware (the “Yuma Delaware Common Stock”) as part of the Reincorporation Merger. The shares outstanding presented in this quarterly report on Form 10-Q have been retroactively adjusted to account for the 1-for-20 reverse stock split. See Note 15 – Subsequent Events, for a discussion of the Reincorporation Merger and the Merger.

 

Restatement Background

 

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

 

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

 

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

 

NOTE 2 – LIQUIDITY CONSIDERATIONS

 

The Company has borrowings which require, among other things, compliance with certain financial ratios. Due to operating losses the Company has sustained during recent quarters as a result of the prolonged weak commodity price environment and other factors, the Company was not in compliance with the trailing four quarter funded debt to EBITDA financial ratio covenant under its credit facility at September 30, 2015, December 31, 2015, March 31, 2016, June 30, 2016 and September 30, 2016, its current ratio as of June 30, 2016 and September 30, 2016, as well as its EBITDA to interest expense ratio as of December 31, 2015, March 31, 2016, June 30, 2016 and September 30, 2016. In addition, the Company was not in compliance due to its going concern opinion at March 31, 2016 and June 30, 2016, as well as its failure to maintain a certain financial bank as its principal depository bank. On May 20, 2016, the Company remedied its compliance with regard to the depository bank. On December 30, 2015, the Company’s wholly owned subsidiary, Yuma Exploration and Production Company, Inc. (“Exploration”) entered into the Waiver, Borrowing Base Redetermination and Ninth Amendment (the “Ninth Amendment”) to the credit agreement which provided for a $29.8 million conforming borrowing base, with an automatic reduction to $20.0 million on May 31, 2016, and waived the compliance with the trailing four quarter funded debt to EBITDA and EBITDA to interest expense financial ratio covenants or any other events of default under the credit facility for the quarters ended September 30, 2015 and December 31, 2015. On June 6, 2016 and effective as of May 31, 2016, Exploration entered into the Waiver and Tenth Amendment to the credit agreement as amended by the Waiver and Amendment to the Waiver and Tenth Amendment dated August 25, 2016 (the “Tenth Amendment”), which maintained the borrowing base at $29.8 million and automatically reduced the borrowing base to $20.0 million on the earliest of (i) September 23, 2016, if the registration statement on Form S-4 (the “Form S-4”) filed with the SEC pursuant to the pending Merger Agreement had not been declared effective by such date; (ii) the date that was forty-seven days after the date the Form S-4 had been declared effective by the SEC; (iii) October 31, 2016; and (iv) in the event of the termination of the merger agreement. As of September 30, 2016, the Company had a working capital deficit of $32.5 million inclusive of the Company’s outstanding debt under its credit facility, which was fully drawn with no additional borrowing capacity available.

 

Upon the closing of the Merger discussed in Note 15 – Subsequent Events, the outstanding balance under the credit facility was assumed by Yuma Delaware in a new credit facility. Under the new credit facility, which was entered into in connection with the Merger, Yuma Delaware is in compliance with the credit facility. This new credit facility supersedes the Company’s previous credit agreement and non-compliance matters discussed above.

NOTE 3 – ACCOUNTING STANDARDS

Not Yet Adopted

In October 2016, the Financial Accounting Standards Board (“FASB”) issued ASU 2016-16, “Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other Than Inventory,” which requires an entity to recognize the income tax consequences of an intra-entity transfer of an asset other than inventory when the transfer occurs and eliminates the exception for an intra-entity transfer of an asset other than inventory. This ASU is effective for annual and interim periods beginning in 2018 and is required to be adopted using a modified retrospective approach, with early adoption permitted. The Company does not expect the adoption of this ASU to have a material impact on its Consolidated Financial Statements.

 

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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 in 2018 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 Statement of Cash Flows.

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

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

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

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

 

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Recently Adopted

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

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

NOTE 4 – FAIR VALUE MEASUREMENTS

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

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

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

 

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Financial assets are considered Level 3 when their fair values are determined using pricing models, discounted cash flow methodologies or similar techniques, and at least one significant model assumption or input is unobservable.

 

	Fair value measurements at September 30, 2016
		Significant
	Quoted prices	other	Significant
	in active	observable	unobservable
	markets	inputs	inputs
	(Level 1)	(Level 2)	(Level 3)	Total
Assets:
Commodity derivatives – oil	$ -	$ 1,194,307	$ -	$ 1,194,307
Liabilities:
Commodity derivatives – gas	$ -	$ 78,763	$ -	$ 78,763

 

 

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

 

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

Debt – The Company’s debt is recorded at the carrying amount on its Consolidated Balance Sheets. For further discussion of the Company’s debt, please see Note 9 – Debt and Interest Expense. The carrying amount of floating-rate debt approximates fair value because the interest rates are variable and reflective of market rates.

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

 

NOTE 5 – COMMODITY DERIVATIVE INSTRUMENTS

 

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

 

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

 

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

 

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

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

	2016	2017
	Settlement	Settlement
NATURAL GAS (MMBtu):
Swaps
Volume	105,475	-
Price	$ 2.646 *	-
3-way collars
Volume	-	248,023
Ceiling sold price (call)	-	$ 3.280 *
Floor purchased price (put)	-	$ 2.946 *
Floor sold price (short put)	-	$ 2.381 *
CRUDE OIL (Bbls):
Put spread
Volume	31,547	-
Floor purchased price (put)	$ 62.27	-
Floor sold price (short put)	$ 40.00	-
3-way collars
Volume	10,630	113,029
Ceiling sold price (call)	$ 47.15	$ 77.00
Floor purchased price (put)	$ 40.00	$ 60.00
Floor sold price (short put)	$ 30.00	$ 45.00

 

            

*Price is a weighted average

 

 

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

	Fair value as of
	September 30,	December 31,
	2016	2015
Asset commodity derivatives:
Current assets	$ 1,420,921	$ 3,069,115
Noncurrent assets	326,656	1,841,120
	1,747,577	4,910,235
Liability commodity derivatives:
Current liabilities	(478,669 )	(411,068 )
Noncurrent liabilities	(153,364 )	(770,579 )
	(632,033 )	(1,181,647 )
Total commodity derivative instruments	$ 1,115,544	$ 3,728,588

 

Sales of natural gas and crude oil on the Consolidated Statements of Operations are comprised of the following:

 

	Three Months Ended		Nine Months Ended
	September 30,		September 30,
	2016	2015	2016	2015
Sales of natural gas and crude oil	$ 3,151,626	$ 4,649,009	$ 9,207,636	$ 14,756,582
Gain realized from sale of commodity
derivatives	-	-	-	4,030,000
Other gains (losses) realized on
commodity derivatives	488,409	432,825	2,205,216	1,084,610
Unrealized gains (losses) on
commodity derivatives	(40,473 )	3,460,825	(2,613,044 )	(1,847,371 )
Total revenue from natural gas and crude oil	$ 3,599,562	$ 8,542,659	$ 8,799,808	$ 18,023,821

 

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

 

	Nine Months Ended		Year Ended
	September 30, 2016		December 31, 2015
	Before tax	After tax	Before tax	After tax
Balance, beginning of period	$ -	$ -	$ 63,091	$ 38,801
Sale of unexpired contracts previously subject
to hedge accounting rules	-	-	(119,917 )	(73,749 )
Other reclassifications due to expired contracts
previously subject to hedge accounting rules	-	-	56,826	34,948
Balance, end of period	$ -	$ -	$ -	$ -

 

NOTE 6 – ASSET IMPAIRMENTS

 

Oil and natural gas prices have remained low in the first three quarters of 2016 and, as a result, the Company recognized a non-cash asset impairment charge of $11,015,589 to write down oil and gas properties for the three months ended June 30, 2016. In addition, the Company recognized a non-cash asset impairment of $4,927,508 to write off goodwill for the three months ended June 30, 2015. The Company did not incur an impairment for the three months ended September 30, 2016.

 

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NOTE 7 – PREFERRED STOCK

 

The Company’s shares of 9.25% Series A Cumulative Redeemable Preferred Stock, no par value per share, with a liquidation preference of $25.00 per share (the “Series A Preferred Stock”), traded on the NYSE MKT under the symbol “YUMAprA” prior to the Series A Conversion. Holders of the Series A Preferred Stock were entitled to receive, when, as and if declared by the Board of Directors, cumulative dividends at the rate of 9.25% per annum (the dividend rate) based on the liquidation price of $25.00 per share of the Series A Preferred Stock, payable monthly in arrears on each dividend payment date, with the first payment date of December 1, 2014. The Series A Preferred Stock is presented in the permanent equity section of the financial statements. Due to the current depressed commodity price environment, as well as other factors which have adversely affected the Company’s cash flows and liquidity, the monthly dividends on the Series A Preferred Stock were suspended beginning with the month ended November 30, 2015. Pursuant to the Company’s credit facility, the Company was precluded from making dividend payments on its Series A Preferred Stock. The Company’s articles of incorporation as of September 30, 2016 provided that any unpaid dividends will accumulate. While the accumulation did not result in presentation of a liability on the balance sheet, the accumulated dividends were deducted from the Company’s net income (or added to its net loss) in the determination of income (loss) attributable to common shareholders and, as appropriate, the corresponding computation of earnings (loss) per share. As of September 30, 2016, the Company had accumulated a total of $1,175,628 in unpaid preferred stock dividends, attributable to the Series A Preferred Stock. As part of the Reincorporation Merger, the Series A Preferred Stock, including all of the accumulated and unpaid dividends, was converted into common stock. See Note 15 – Subsequent Events for additional information.

 

NOTE 8 – EARNINGS (LOSS) PER COMMON SHARE

 

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

Potentially dilutive securities for the computation of diluted weighted average shares outstanding (adjusted for the 1-for-20 reverse stock split as described in Note 15 – Subsequent Events) are as follows:

	Three Months Ended		Nine Months Ended
	September 30,		September 30,
	2016	2015	2016	2015
Restricted Stock Awards	74,261	78,716	99,315	68,691
Restricted Stock Units	-	4,771	-	4,771
	74,261	83,487	99,315	73,462

 

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

 

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NOTE 9 – DEBT AND INTEREST EXPENSE

 

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

 

The Company has borrowings which require, among other things, compliance with certain financial ratios. Due to operating losses the Company has sustained during recent quarters as a result of the prolonged weak commodity price environment and other factors, the Company was not in compliance with the trailing four quarter funded debt to EBITDA financial ratio covenant under its credit facility at September 30, 2015, December 31, 2015, March 31, 2016, June 30, 2016 and September 30, 2016, its current ratio as of June 30, 2016 and September 30, 2016, as well as its EBITDA to interest expense ratio as of December 31, 2015, March 31, 2016, June 30, 2016 and September 30, 2016. In addition, the Company was not in compliance due to its going concern opinion at March 31, 2016 and June 30, 2016, as well as its failure to maintain a certain financial bank as its principal depository bank. On May 20, 2016, the Company remedied its compliance with regard to the depository bank. On December 30, 2015, Exploration entered into the Ninth Amendment to the credit agreement which provided for a $29.8 million conforming borrowing base, with an automatic reduction to $20.0 million on May 31, 2016, and waived the compliance with the trailing four quarter funded debt to EBITDA and EBITDA to interest expense financial ratio covenants or any other events of default under the credit facility for the quarters ended September 30, 2015 and December 31, 2015. On June 6, 2016 and effective as of May 31, 2016, Exploration entered into the Tenth Amendment as amended on August 25, 2016, which maintained the borrowing base at $29.8 million and automatically reduced the borrowing base to $20.0 million on the earliest of (i) September 23, 2016, if the Form S-4 filed with the SEC pursuant to the pending Merger Agreement had not been declared effective by such date; (ii) the date that was forty-seven days after the date the Form S-4 had been declared effective by the SEC; (iii) October 31, 2016; and (iv) in the event of the termination of the merger agreement. As of September 30, 2016, the Company had a working capital deficit of $32.5 million inclusive of the Company’s outstanding debt under its credit facility, which was fully drawn with no additional borrowing capacity available.

Upon the closing of the Merger discussed in Note 15 – Subsequent Events, the outstanding balance under the credit facility was assumed by Yuma Delaware in a new credit facility. Under the new credit facility, which was entered into in connection with the Merger, Yuma Delaware is in compliance with the credit facility. This new credit facility supersedes the Company’s previous credit agreement and non-compliance matters discussed above.

 

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

	Three Months Ended		Nine Months Ended
	September 30,		September 30,
	2016	2015	2016	2015
Credit agreement	$ 323,735	$ 314,177	$ 841,112	$ 835,584
Credit agreement commitment fees	-	6,301	-	31,460
Amortization of
credit agreement loan costs	60,489	73,146	518,479	209,903
Insurance installment loan	-	4,400	1,961	9,597
Other interest charges	3,066	39	8,095	1,062
Capitalized interest	(141,931 )	(266,949 )	(395,244 )	(750,107 )
Total interest expense	$ 245,359	$ 131,114	$ 974,403	$ 337,499

 

NOTE 10 – MERGER WITH PYRAMID OIL COMPANY AND GOODWILL

 

On September 10, 2014, a wholly owned subsidiary of Pyramid merged with and into Yuma Energy, Inc., a Delaware corporation (“Yuma Co.”), in exchange for 66,336,701 shares of common stock (prior to the 1-for-20 reverse stock split as described in Note 15 – Subsequent Events) and Pyramid changed its name to “Yuma Energy, Inc.” (the “Pyramid merger”). As a result of the Pyramid merger, the former Yuma Co. stockholders received approximately 93% of the then outstanding common stock of the Company and thus acquired voting control. Although the Company was the legal acquirer, for financial reporting purposes the Pyramid merger was accounted for as a reverse acquisition of Pyramid by Yuma Co. The transaction qualified as a tax-deferred reorganization under Section 368(a) of the Internal Revenue Code of 1986, as amended (the “Code”).

 

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

 

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

 

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NOTE 11 – INCOME TAXES

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

	Three Months Ended		Nine Months Ended
	September 30,		September 30,
	2016	2015	2016	2015
Consolidated net income (loss)
before income taxes	$ (2,162,873 )	$ 239,243	$ (22,135,882 )	$ (16,928,915 )
Income tax expense (benefit)	(47,429 )	329,653	(1,272,664 )	(3,605,839 )
Effective tax rate	2.2 %	138 %	5.7 %	21.3 %

 

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

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

 

NOTE 12 – CONTINGENCIES

Certain Legal Proceedings

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

 

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

 

On July 9, 2014, Nabors Drilling USA, L.P. and other Nabors entities and Yuma Energy, Inc. and several of its wholly owned subsidiaries were named in a lawsuit filed in the District Court of Harris County, Texas, in the 80 th Judicial District, concerning the death of an employee of Timco Services during the drilling of the Crosby 12-1 well. All of the Yuma-related entities, except for Exploration, were voluntarily dismissed from the lawsuit by the Plaintiffs. The Company has tendered its defense to its liability insurance carriers who are responding. There has been one unsuccessful mediation session. Depositions are still ongoing. Defense counsel intends to file a motion seeking dismissal of the claims against Exploration, which is currently being finalized. Management believes that the Company is not liable, and has adequate insurance to meet any potential claim from this suit.

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

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

 

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

 

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

 

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

 

Environmental Remediation Contingencies

 

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

 

Board of Commissioners of the Southeast Louisiana Flood Protection Authority-East, et al. v. Tennessee Gas Pipeline Company, LLC, et al.

 

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

 

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

 

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

 

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

 

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

 

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

 

On October 24, 2016, Texas Southeastern Gas Gathering Company (“TGG”), a subsidiary of the Company, was named as a defendant in an action by Vintage Assets, Inc. in the United States District Court for the Eastern District of Louisiana. Vintage claims that its property, located in Plaquemines Parish, has been damaged by the widening of canals used by the defendants. Between 1953 and 1970, the defendants’ predecessors received multiple right-of-way servitudes on Vintage’s property, which authorized the construction and operation of pipelines and dredge canals. The defendants dredged canals and laid pipelines pursuant to the rights of way agreements. Vintage alleges that its property has suffered damage because of defendants’ failure to maintain the pipeline canals and banks. Further Vintage alleges that this failure has caused ecological damages and loss of acreage due to erosion. The action is currently scheduled for trial in September 2017. Management intends to defend the plaintiffs’ claims vigorously and has notified its insurance carrier of the claim.  TGG sold all of its assets to High Point Gas Gathering in 2010.  At this point in the legal process, no evaluation of the likelihood of an unfavorable outcome or associated economic loss can be made; therefore no liability has been recorded on the Company’s books.

 

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 books.

 

 

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Audits

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. Exploration is currently waiting on the Department of Revenue’s final audit results. The exposure related to this audit is not currently determinable.

NOTE 13 – GREATER MASTERS CREEK FIELD AREA

 

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

 

In addition, during the first quarter of 2016, the Company received notice from the operator of certain wells in Rapides and Vernon Parishes, Louisiana, that certain wells in which the Company has an interest were shut-in due to current economic conditions. The operator has since sold its interest. The subsequent operator has not restarted production from eight of these wells, and the leases associated with the shut-in wells have expired, reducing the Company’s acreage by 4,686 gross (1,389 net) acres.

 

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

On April 4, 2016, the Company entered into an amendment effective March 1, 2016 to an oil and gas lease in the Greater Masters Creek Field area with a certain mineral owner for acreage that was not held by production as of March 31, 2016. The total acreage is approximately 25,139 acres and, by virtue of the Company conducting certain location clean-up operations, the lease has now been extended until December 31, 2016. This extension is subject to certain additional performance criteria, including the posting of a bond to cover P&A costs for wells located on this mineral owner’s property, and plugging and abandoning six of the mineral owner’s wells by December 31, 2016 at an estimated net cost of $426,000. The lease may be extended until June 30, 2017 by paying a rental of $628,450, or by spudding a new well before December 31, 2016. If the leased acreage expires, the Company’s proved reserves from year-end 2015 would be reduced by approximately 5,096 MBoe, the number of operated proved undeveloped locations and operated non-proved locations would be reduced by 13 and 16, respectively.

 

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NOTE 14 – TEXAS SOUTHEASTERN GAS MARKETING COMPANY

 

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

 

NOTE 15 – SUBSEQUENT EVENTS

 

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

Davis Agreement and Plan of Merger and Reorganization

On October 26, 2016, the shareholders of the Company approved, among other proposals, (i) the conversion (the “Series A Conversion”) of the 9.25% Series A Cumulative Redeemable Preferred Stock, no par value per share of the Company (the “Series A Preferred Stock”), into common stock, no par value per share of the Company (the “common stock”), at a rate of 35 shares of common stock for each share of Series A Preferred Stock; (ii) the reincorporation of the Company from California to Delaware pursuant to a merger (the “Reincorporation Merger”) of the Company with and into Yuma Energy, Inc., a Delaware corporation and wholly owned subsidiary of the Company (“Yuma Delaware”); and (iii) the merger (the “Merger”) of Yuma Merger Subsidiary, Inc., a Delaware corporation and wholly owned subsidiary of Yuma Delaware (“Merger Subsidiary”), with and into Davis Petroleum Acquisition Corp., a Delaware corporation (“Davis”) with Davis surviving as a wholly owned subsidiary of Yuma Delaware. The Company issued approximately 19,411,000 shares of common stock as a result of the Series A Conversion. Immediately following the Series A Conversion, each share of common stock was exchanged for one-twentieth of one share of common stock, $0.001 par value per share of Yuma Delaware (the “Yuma Delaware Common Stock”) as part of the Reincorporation Merger.

New Credit Facility

Upon the closing of the Merger discussed above, the entire outstanding balance under the credit facility was assumed by Yuma Delaware in a new credit facility (“the Credit Agreement”). The Credit Agreement provides for a $75.0 million 3-year revolving credit facility with SG Americas Securities, LLC (“SG Americas”) as Lead Arranger and Bookrunner, SocGen as Administrative Agent and the lenders party thereto. The Credit Agreement replaces the Company’s existing credit agreement. The initial borrowing base of the Credit Agreement is $44.0 million, and is subject to redetermination as of January 1, 2017 as well as April 1st and October 1st of each year. As of October 26, 2016, Yuma Delaware had approximately $39.5 million outstanding under the Credit Agreement. The incremental $9.7 million of debt outstanding at October 26, 2016 under the new Credit Agreement from the Company's outstanding debt balance of $29.8 million at September 30, 2016 was primarily the result of paying off Davis' outstanding debt balance of $9.0 million at Bank of America, accrued interest under the old credit facilities, as well as fees associated with the new Credit Agreement. All of the obligations under the Credit Agreement, and the guarantee of those obligations, are secured by substantially all of the assets of Yuma Delaware and customary financial covenants have been made.

 

 

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Item 2.   

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

 

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

 

Cautionary Statement Regarding Forward-Looking Statements

 

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

 

●

our ability to repay outstanding loans when due;

 

●

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

 

●

reductions in the borrowing base under our credit facility;

 

●

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

 

●

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

 

●

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

 

●

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

●

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

●

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

 

 

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●

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

●

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

●

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

●

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

●

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

●

our ability to replace our oil and natural gas reserves;

●

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

●

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

●

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

●

environmental risks;

●

drilling and operating risks;

●

exploration and development risks;

●

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

●

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

●

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

●

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

●

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

●

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

●

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

●

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

●

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

 

 

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

 

Overview

 

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

 

Recent Developments

 

Agreement and Plan of Merger and Reorganization

 

On October 26, 2016, the shareholders of the Company approved, among other proposals, (i) the conversion (the “Series A Conversion”) of the 9.25% Series A Cumulative Redeemable Preferred Stock, no par value per share of the Company (the “Series A Preferred Stock”), into common stock, no par value per share of the Company (the “common stock”), at a rate of 35 shares of common stock for each share of Series A Preferred Stock; (ii) the reincorporation of the Company from California to Delaware pursuant to a merger (the “Reincorporation Merger”) of the Company with and into Yuma Energy, Inc., a Delaware corporation and wholly owned subsidiary of the Company (“Yuma Delaware”); and (iii) the merger (the “Merger”) of Yuma Merger Subsidiary, Inc., a Delaware corporation and wholly owned subsidiary of Yuma Delaware (“Merger Subsidiary”), with and into Davis Petroleum Acquisition Corp., a Delaware corporation (“Davis”) with Davis surviving as a wholly owned subsidiary of Yuma Delaware. The Company issued approximately 19,411,000 shares of common stock as a result of the Series A Conversion. Immediately following the Series A Conversion, each share of common stock was exchanged for one-twentieth of one share of common stock, $0.001 par value per share of Yuma Delaware (the “Yuma Delaware Common Stock”) as part of the Reincorporation Merger. Upon the closing of the Merger, the outstanding balance under the credit facility was assumed by Yuma Delaware as part of a new credit facility.

 

Commodity Prices

 

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

 

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Full Cost Ceiling Test Impairment

 

Oil and natural gas prices have remained low in the first three quarters of 2016 and, as a result, we recognized an $11.0 million non-cash asset impairment in the second quarter of 2016 which has negatively impacted our results of operations and equity.  We did not incur an impairment in the third quarter of 2016.  If prices remain at current levels, subject to numerous factors and inherent limitations, and all other factors remain constant, the Company (stand-alone, pre-merger) does not expect to incur a non-cash full cost impairment during the fourth quarter of 2016.  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 2016 full cost ceiling calculation has been prepared by substituting (i) $42.47 per barrel for oil, and (ii) $2.48 per MMBtu for natural gas for the expected realized prices as of December 31, 2016. The forecasted average realized price was based on the average realized price for sales of crude oil, natural gas liquids and natural gas on the first calendar day of each month for the first 11 months and an estimate for the twelfth month based on a quoted forward price. Changes to our reserves and future production were made due to changing the effective date of the evaluation from September 30, 2016 to December 31, 2016. 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 2016 utilized in our full cost ceiling calculation.

 

Critical Accounting Policies

 

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

 

Market Conditions

 

Prevailing prices for the crude oil, natural gas and natural gas liquids (“NGLs”) that we produce significantly impact our revenues and cash flows. The benchmark prices for crude oil, natural gas and NGLs were significantly lower in the first nine months of 2016 compared to the same period in 2015; as a result, we experienced significant declines in our price realizations associated with those benchmarks. Additional detail on market conditions, including our average price realizations and benchmarks for crude oil, natural gas and NGLs relative to our operating segments, follows.

 

Liquidity Considerations

 

As part of the closing of the Merger on October 26, 2016, Yuma Delaware entered into a new credit facility and the outstanding balance under our credit facility was assumed in that new credit facility by Yuma Delaware (“the Credit Agreement”). The Credit Agreement provides for a $75.0 million 3-year revolving credit facility with SG Americas Securities, LLC (“SG Americas”) as Lead Arranger and Bookrunner, SocGen as Administrative Agent and the lenders party thereto. The Credit Agreement replaces our existing credit agreement. The initial borrowing base of the Credit Agreement is $44.0 million, and is subject to redetermination as of January 1, 2017 as well as April 1st and October 1st of each year. As of October 26, 2016, Yuma Delaware had approximately $39.5 million outstanding under the Credit Agreement. The incremental $9.7 million of debt outstanding at October 26, 2016 under the new Credit Agreement from the Company's outstanding debt balance of $29.8 million at September 30, 2016 was primarily the result of paying off Davis' outstanding debt balance of $9.0 million at Bank of America, accrued interest under the old credit facilities, as well as fees associated with the new Credit Agreement. All of the obligations under the Credit Agreement, and the guarantee of those obligations, are secured by substantially all of the assets of Yuma Delaware and customary financial covenants have been made.

 

 

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Sales and Other Operating Revenues

 

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

 

	Three Months Ended September 30,		Nine Months Ended September 30,
	2016	2015	2016	2015
Production volumes:
Crude oil and condensate (Bbl)	47,079	61,938	155,986	186,531
Natural gas (Mcf)	340,189	497,868	1,148,587	1,488,408
Natural gas liquids (Bbl)	12,613	20,899	41,771	54,838
Total (Boe) (1)	116,390	165,815	389,188	489,437
Average prices realized:
Excluding commodity derivatives:
Crude oil and condensate (per Bbl)	$ 42.49	$ 46.10	$ 37.51	$ 50.52
Natural gas (per Mcf)	$ 2.72	$ 2.72	$ 2.28	$ 2.77
Natural gas liquids (per Bbl)	$ 17.94	$ 18.61	$ 17.71	$ 19.20
Including commodity derivatives:
Crude oil and condensate (per Bbl)	$ 53.46	$ 51.41	$ 49.24	$ 66.25
Natural gas (per Mcf)	$ 2.64	$ 2.93	$ 2.61	$ 4.24
Natural gas liquids (per Bbl)	$ 17.94	$ 18.61	$ 17.71	$ 19.20

 

(1)

Barrels of oil equivalent have been calculated on the basis of six thousand cubic feet (Mcf) of natural gas equal to one barrel of oil equivalent (Boe).

 

The following table presents our revenues for the three and nine months ended September 30, 2016 and 2015.

 

	Three Months Ended September 30,		Nine Months Ended September 30,
	2016	2015	2016	2015
Sales of natural gas and crude oil:
Crude oil and condensate	$ 2,000,373	$ 2,855,530	$ 5,851,235	$ 9,423,519
Natural gas	924,994	1,340,877	2,616,440	4,112,065
Natural gas liquids	226,259	388,966	739,961	1,053,076
Realized gain (loss) on commodity derivatives	488,409	432,824	2,205,216	5,114,609
Unrealized gain (loss) on commodity derivatives	(40,473 )	3,460,825	(2,613,044 )	(1,847,371 )
Gas marketing sales	-	63,637	-	167,923
Total revenues	$ 3,599,562	$ 8,542,659	$ 8,799,808	$ 18,023,821

 

Sale of Crude Oil and Condensate

 

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

 

Crude oil volumes sold were 24.0% lower for the three months ended September 30, 2016 than the crude oil volumes sold during the same period in 2015. This decrease was a result of reduced production levels at Bayou Hebert field due to facility maintenance as well as downtime due to flooding in the area. In addition, the Livingston field experienced reduced production due to flooding, and Main Pass 2 was affected by salt water disposal restrictions. Production in Bayou Hebert field, Livingston field and Main Pass 2 has been restored to normal levels. Realized crude oil prices decreased 7.8% from the three months ended September 30, 2015 compared to the three months ended September 30, 2016.

 

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For the nine months ended September 30, 2016, crude oil volumes sold were 16.4% lower than the same period in 2015. This decrease was the result of shut-in wells in both operated and non-operated wells in the Greater Masters Creek Field and the reasons listed above for the three months ended September 30, 2016. It is not anticipated that production will be restored from the operated and non-operated Greater Masters Creek Field wells due to low commodity prices. Realized crude oil prices were 25.8% lower for the nine months ended September 30, 2016 compared to the same period in 2015.

 

Sale of Natural Gas and Natural Gas Liquids

 

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

 

For the three months ended September 30, 2016 compared to the same period in 2015, we experienced a 31.7% decrease in natural gas volumes sold and a 39.6% decrease in NGLs sold primarily due to reduced production levels at Bayou Hebert field due to facility maintenance as well as downtime due to flooding in the area, and partially offset by production from the Talbot 23-1 recompletion to Marg Tex 1 that happened late in the quarter. Production in Bayou Hebert field has been restored to previous levels and the Talbot 23-1 well continues to produce from the Marg Tex 1 zone at expected levels. During the same period, realized natural gas prices did not change and realized prices for NGLs decreased by 3.6%.

 

For the nine months ended September 30, 2016, natural gas volumes sold decreased by 22.8% and volumes of NGLs sold decreased by 23.8% compared to the same period in 2015. This decrease was due primarily to the reasons stated above for the three months ended September 30, 2016, natural declines in production from other gas wells, and additional down time at Bayou Hebert field while restoring salt water disposal capacity. During the same period, realized natural gas prices decreased by 17.7% and realized prices for NGLs decreased by 7.8%.

 

Gas Marketing

 

Gas marketing sales are natural gas volumes purchased from certain of our operated wells and the aggregated volumes sold with a mark-up of $.03 per MMBtu. Our wholly owned subsidiary, Texas Southeastern Gas Marketing Company (“Marketing”), purchased and sold natural gas on our behalf and on behalf of our working interest partners. In early 2016, we discontinued Marketing due to a lack of volumes and the associated costs of running the company (see Item 1. Unaudited Condensed Notes to the Consolidated Financial Statements, Note 14 – Texas Southeastern Gas Marketing Company).

 

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  Lease Operating Expenses

 

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

 

	Three Months Ended September 30,		Nine Months Ended September 30,
	2016	2015	2016	2015
Lease operating expenses	$ 1,178,134	$ 1,816,325	$ 3,757,500	$ 6,254,493
Severance, ad valorem taxes and marketing	620,734	902,594	1,934,577	2,913,767
Total LOE	$ 1,798,868	$ 2,718,919	$ 5,692,077	$ 9,168,260
LOE per Boe	$ 15.46	$ 16.40	$ 14.63	$ 18.73
LOE per Boe without severance, ad valorem taxes and marketing	$ 10.12	$ 10.95	$ 9.65	$ 12.78

 

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

 

The 33.8% decrease in total LOE for the three months ended September 30, 2016 compared to the same period in 2015 was primarily due to our continued operating cost reduction initiatives implemented in our Greater Masters Creek Field, Main Pass 2 and 4, and California. LOE per Boe decreased by 5.7% for the same period generally due to enhancement projects that kept production stable and the cost reduction programs mentioned above.

 

For the nine months ended September 30, 2016, total LOE decreased by 37.9% compared to the same period in 2015, due primarily to the reasons state above for the three months ended September 30, 2016 which led to a decrease in LOE per Boe of 21.9% for the same period.

 

Re-engineering and Workovers

 

Re-engineering and workover expenses include the costs to restore or enhance production in current producing zones as well as costs of significant non-recurring operations.

 

Workover expenses for the three months ended September 30, 2016 and 2015 totaled $132,708 and $1,136, respectively. Workover expenses were incurred in the third quarter of 2016 to repair salt water disposal restrictions at Main Pass 2 and to repair artificial lift in Livingston field. All the 2015 re-engineered facilities upgrades and artificial lift optimization projects in our operated fields continue to reduce the number of workovers, down time, and nonrecurring operations overall. LOE per Boe, including re-engineering and workovers, for the three months ended September 30, 2016 and 2015 totaled $16.60 and $16.40, respectively, a 1.2% increase.

 

For the nine months ended September 30, 2016 and 2015, workover expenses totaled $132,708 and $555,628, respectively. High workover expenses were incurred in the first half of 2015 to restore facilities and salt water disposal at Main Pass 4 and artificial lift in Livingston Field. LOE per Boe, including re-engineering and workovers, for the nine months ended September 30, 2016 and 2015 totaled $14.97 and $19.87, respectively, a 24.7% decrease.

 

 

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General and Administrative Expenses

 

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

 

	Three Months Ended September 30,		Nine Months Ended September 30,
	2016	2015	2016	2015
General and administrative
Stock-based compensation	$ 196,561	$ 385,712	$ 943,127	$ 2,958,952
Capitalized stock-based comp	(7,350 )	(47,093 )	(33,818 )	(748,002 )
Net stock-based compensation	189,211	338,619	909,309	2,210,950
Other G&A	1,981,792	2,431,148	7,000,903	7,218,426
Capitalized other G&A	(400,173 )	(557,664 )	(1,258,079 )	(1,828,567 )
Net other G&A	1,581,619	1,873,484	5,742,824	5,389,859
Net general and administrative	$ 1,770,830	$ 2,212,103	$ 6,652,133	$ 7,600,809

 

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

 

For the three months ended September 30, 2016, G&A expenses inclusive of amounts capitalized were $638,507 (22.7%) lower than the amount for the same period in 2015. This decrease in G&A expenses was primarily attributed to a $290,200 decrease in salary expenses due to a 21.4% staff reduction, a $189,151 decrease in stock-based compensation, a $168,354 decrease in consulting fees, a $70,939 decrease in audit and accounting fees, offset by $176,871 in increased non-recurring professional costs associated with the Davis merger during 2016. .

 

For the nine months ended September 30, 2016, G&A expenses inclusive of amounts capitalized were $2,233,348 (21.9%) lower than the same period in 2015. Costs for the Davis merger of $1,046,652 increased G&A costs for the current nine-month period; however, this increase was offset by a $1,872,173 decrease in stock-based compensation, a $596,094 decrease in salaries due to staff reductions, and a $453,312 decrease in consulting fees.

 

Depreciation, Depletion and Amortization

 

Our depreciation, depletion and amortization (“DD&A”) and DD&A per Boe for the three and nine months ended September 30, 2016 and 2015 is summarized as follows:

 

	Three Months Ended September 30,		Nine Months Ended September 30,
	2016	2015	2016	2015
Depreciation, Depletion and Amortization	$ 1,711,043	$ 3,123,812	$ 6,178,248	$ 11,020,278
DD&A per Boe	$ 14.70	$ 18.84	$ 15.87	$ 22.52

 

DD&A per Boe decreased by 22.0% and 29.5% for the three and nine months ended September 30, 2016 compared to the same periods in 2015. Decreases in 2016 production compared to 2015 caused corresponding decreases to depletion (see preceding Sales discussion for production detail). In addition, future development costs, a component of the depletion base, are down from the September 30, 2015 projection. Depressed commodity prices are the primary cause for the reduction in projected future development costs.

 

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Interest Expense

 

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

 

	Three Months Ended September 30,		Nine Months Ended September 30,
	2016	2015	2016	2015
Interest expense	$ 387,290	$ 398,063	$ 1,369,647	$ 1,087,606
Interest capitalized	(141,931 )	(266,949 )	(395,244 )	(750,107 )
Net	$ 245,359	$ 131,114	$ 974,403	$ 337,499
Bank debt	$ 29,800,000	$ 29,700,000	$ 29,800,000	$ 29,700,000

 

Gross interest expense decreased $10,773 for the three months ended September 30, 2016 and increased $282,041 for the nine months ended September 30, 2016 over the same periods in 2015. The increased amortization of debt costs related to the acceleration of the maturity dates under our credit facility pursuant to the Ninth and Tenth Amendments increased interest expense in the first nine months of 2016 as compared to 2015 by $308,576. Capitalized interest decreased $125,018 and $354,863 for the three and nine months ended September 30, 2016 from the same periods in 2015, driven by a decrease in our unevaluated properties, which is the basis of our capitalized interest calculation.

 

Income Tax Expense

 

We recorded an income tax benefit of $1,272,664 on a pre-tax net loss of $22,135,882 resulting in an effective tax rate of 5.7% for the nine months ended September 30, 2016. For the nine months ended September 30, 2015, we recorded an income tax benefit of $3,605,839 on a pre-tax loss of $16,928,915, resulting in an effective tax rate of 21.3%.

 

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

 

Liquidity and Capital Resources

 

Cash Flows

 

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

 

	Nine Months Ended September 30,
	2016	2015
Cash flows provided by (used in) operating activities	$ (804,695 )	$ (4,280,324 )
Cash flows used in investing activities	(2,247,852 )	(10,010,324 )
Cash flows provided by (used in) financing activities	(470,716 )	7,780,430
Net increase (decrease) in cash	$ (3,523,263 )	$ (6,510,218 )

 

Cash Flows from Operating Activities

 

Cash flows from operations for the nine months ended September 30, 2016 increased by $3,475,629, or 81.2%, over the same period in 2015 primarily due to changes in working capital and decreases in lease operating expenses, somewhat offset by lower revenue from decreased production and lower commodity prices as mentioned earlier.

 

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Cash Flows from Investing Activities

 

Oil and natural gas investing activities decreased by $7,762,472 or 77.5% in the nine months ended September 30, 2016 compared to the same period in 2015. The decrease was primarily due to a reduction in capital expenditures in 2016 compared to 2015.

 

During the nine months ended September 30, 2016, we invested $2,588,455 in lease acquisition costs and capital expenditures related to a recompletion, workovers, P&A activity and software.  Lease acquisition costs primarily included capitalized G&A and capitalized interest associated with the North Austin Chalk and Cat Canyon prospects.   Notable projects include the DS&B 121 well recompletion for a cost of $166,935, Starns 38 #1 ESP installation with costs of $70,726, P&A costs of $309,052 for four Crosby SWD wells and the McRight 11 #1, as well as the removal of various Greater Masters Creek Field facilities totaling $76,496.  We had six property sales during the period ended September 30, 2016 resulting in $340,603 in net proceeds.

 

During the nine months ended September 30, 2015, the Amazon 3-D Project accounted for $3,964,620 of our total oil and natural gas investing activities. Of that, $3,682,212 was spent on the drilling of the Talbot 23-1 well and related Anaconda prospect costs. At the Greater Masters Creek Field, $1,672,681 was spent primarily on the workover of the Bullock A-1 and the completion of the Crosby 14-1 and its salt water disposal well. At the Livingston 3-D Project, $1,377,842 was spent, with most of the expenditures going to the completion of the Blackwell 39-1 well and related Musial prospect costs, along with capital workovers to add electric submersible pumps to two wells.

 

Cash Flows from Financing Activities

 

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

 

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

 

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

 

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

 

 

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Other than the credit facility, we had debt of $0 and $263,635 at September 30, 2016 and December 31, 2015, respectively, from installment loans financing oil and natural gas property insurance premiums. We had a cash balance of $1,831,928 at September 30, 2016.

 

Credit Facility

 

Upon the closing of the Merger discussed in Item 1. Unaudited Condensed Notes to the Consolidated Financial Statements, Note 15 – Subsequent Events, the entire outstanding balance under the credit facility was assumed by Yuma Delaware in a new credit facility (“the Credit Agreement”). The Credit Agreement provides for a $75.0 million 3-year revolving credit facility with SG Americas Securities, LLC (“SG Americas”) as Lead Arranger and Bookrunner, SocGen as Administrative Agent and the lenders party thereto. The Credit Agreement replaces our existing credit agreement. The initial borrowing base of the Credit Agreement is $44.0 million, and is subject to redetermination as of January 1, 2017 as well as April 1st and October 1st of each year. As of October 26, 2016, Yuma Delaware had approximately $39.5 million outstanding under the Credit Agreement. The incremental $9.7 million of debt outstanding at October 26, 2016 under the new Credit Agreement from the Company's outstanding debt balance of $29.8 million at September 30, 2016 was primarily the result of paying off Davis' outstanding debt balance of $9.0 million at Bank of America, accrued interest under the old credit facilities, as well as fees associated with the new Credit Agreement. All of the obligations under the Credit Agreement, and the guarantee of those obligations, are secured by substantially all of the assets of Yuma Delaware and customary financial covenants have been made.

Hedging Activities

 

Current Commodity Derivative Contracts

 

We seek to reduce our sensitivity to oil and gas price volatility and secure favorable debt financing terms by entering into commodity derivative transactions which may include fixed price swaps, price collars, puts, calls and other derivatives. We believe our hedging strategy should result in greater predictability of internally generated funds, which in turn can be dedicated to capital development projects and corporate obligations. 

 

Fair Market Value of Commodity Derivatives

 

	September 30, 2016		December 31, 2015
	Oil	Gas	Oil	Gas
Assets
Current	$ 1,016,583	$ -	$ 2,393,032	$ 265,015
Noncurrent	177,724	-	1,049,661	20,880
Liabilities
Current	$ -	$ (74,331 )	$ -	$ -
Noncurrent	-	(4,432 )	-	-

 

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

 

The fair market value of our commodity derivative contracts in place at September 30, 2016 and December 31, 2015 were net assets of $1,115,544 and $3,728,588, respectively. Please see Item 1. Unaudited Condensed Notes to the Consolidated Financial Statements, Note 5 – Commodity Derivative Instruments, for additional information on our commodity derivatives.

 

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Commitments and Contingencies

 

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

 

	Debt (1)	Commodity Derivatives (2)	Operating Leases	Asset Retirement Obligations
2016	$ 29,800,000	$ 301,930	$ 146,060	$ 243,711
2017	-	813,614	564,732	111,620
2018	-	-	2,264	3,718,130
2019	-	-	-	2,164,714
2020	-	-	-	208,427
Thereafter	-	-	-	2,369,004
Totals	$ 29,800,000	$ 1,115,544	$ 713,056	$ 8,815,606

 

(1)

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

 

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

 

Off Balance Sheet Arrangements

 

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

 

Item 3. Quantitative and Qualitative Disclosures about Market Risk.

 

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

 

Item 4. Controls and Procedures.

 

Evaluation of disclosure controls and procedures.

 

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

 

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

 

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Changes in internal control over financial reporting .

 

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

 

Remedial Action

 

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

 

PART II. OTHER INFORMATION

 

Item 1. Legal Proceedings.

 

A description of our legal proceedings is included in Item 1. Unaudited Condensed Notes to the Consolidated Financial Statements, Note 12 – Contingencies, and is incorporated herein by reference.

 

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

 

Item 1A. Risk Factors.

 

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

 

 

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

 

 The following table sets forth information regarding our acquisition of shares of common stock for the periods presented (adjusted for the 1-for-20 reverse stock split as described in Item 1. Unaudited Condensed Notes to the Consolidated Financial Statements, Note 15 – Subsequent Events).

 

	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 2016	951	$ 5.51	-	-
August 2016	-	-	-	-
September 2016	-	-	-	-

 

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

 

Item 3.  Defaults upon Senior Securities.

 

We were in violation of three of the financial covenants under our credit facility at September 30, 2016. Under the new credit facility, which was entered into in connection with the Merger, Yuma Delaware is in compliance with the credit facility. This new credit facility supersedes the Company’s previous credit agreement and non-compliance matters discussed above. See Item 1. Unaudited Condensed Notes to the Consolidated Financial Statements, Note 2 – Liquidity Considerations.

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

 

Item 4.  Mine Safety Disclosure.

 

Not Applicable.

 

Item 5.  Other Information.

 

None.

 

 

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Item 6.   Exhibits.

EXHIBIT INDEX

FOR

 

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

Incorporated by Reference

Exhibit No.

Description

Form

SEC File No.

Exhibit

Filing Date

Filed Herewith

Furnished Herewith

2.1

Agreement and Plan of Merger and Reorganization dated as of February 10, 2016, by and among Yuma Energy, Inc., Yuma Delaware Merger Subsidiary, Inc., Yuma Merger Subsidiary, Inc. and Davis Petroleum Acquisition Corp.

8-K/A

001-32989

2.1

February 16, 2016

2.1(a)

First Amendment to the Agreement and Plan of Merger and Reorganization dated as of September 2, 2016, by and among Yuma Energy, Inc., Yuma Delaware Merger Subsidiary, Inc., Yuma Merger Subsidiary, Inc. and Davis Petroleum Acquisition Corp.

8-K

001-32989

2.1

September 6, 2016

31.1

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

X

31.2

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

X

32.1

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

X

32.2

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

X

101.INS

XBRL Instance Document.

X

101.SCH

XBRL Schema Document.

X

101.CAL

XBRL Calculation Linkbase Document.

X

101.DEF

XBRL Definition Linkbase Document.

X

101.LAB

XBRL Label Linkbase Document.

X

101.PRE

XBRL Presentation Linkbase Document.

X

 

 

 

 

39

 

SIGNATURES

 

 

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

 

 

		YUMA ENERGY, INC.
		By:	/s/ Sam L. Banks
		Name:	Sam L. Banks
Date: November 14, 2016		Title:	President and Chief Executive Officer (Principal Executive Officer)
		By:	/s/ James J. Jacobs
Date: November 14, 2016		Name:	James J. Jacobs
		Title:	Chief Financial Officer (Principal Financial Officer)

 

 

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