YUMA Yuma Energy Inc New

Yuma Energy, Inc.

(Exact name of registrant as specified in its charter)

 

DELAWARE (State or other jurisdiction of incorporation)

94-0787340 (IRS Employer Identification No.)

PART I. FINANCIAL INFORMATION

 

Item 1.    Financial Statements.

 

Yuma Energy, Inc.

 

CONSOLIDATED BALANCE SHEETS

 

	March 31,
	2017	December 31,
	(Unaudited)	2016
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$ 2,927,494	$ 3,625,686
Accounts receivable, net of allowance for doubtful accounts:
Trade	5,485,155	4,827,798
Officers and employees	60,461	68,014
Other	1,903,274	1,757,337
Commodity derivative instruments	478,242	-
Prepayments	757,111	1,063,418
Other deferred charges	309,789	284,305
Total current assets	11,921,526	11,626,558
OIL AND GAS PROPERTIES (full cost method):
Proved properties	490,389,144	488,723,905
Unproved properties - not subject to amortization	5,473,755	3,656,989
	495,862,899	492,380,894
Less: accumulated depreciation, depletion and amortization	(413,471,472 )	(410,440,433 )
Net oil and gas properties	82,391,427	81,940,461
OTHER PROPERTY AND EQUIPMENT:
Land, buildings and improvements	1,600,000	1,600,000
Other property and equipment	7,034,591	7,136,530
	8,634,591	8,736,530
Less: accumulated depreciation and amortization	(5,436,568 )	(5,349,145 )
Net other property and equipment	3,198,023	3,387,385
OTHER ASSETS AND DEFERRED CHARGES:
Commodity derivative instruments	674,431	-
Deposits	467,592	467,306
Other noncurrent assets	486,326	517,201
Total other assets and deferred charges	1,628,349	984,507
TOTAL ASSETS	$ 99,139,325	$ 97,938,911

 

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

 

 

4

 

 

Yuma Energy, Inc.

 

CONSOLIDATED BALANCE SHEETS– CONTINUED

 

	March 31,
	2017	December 31,
	(Unaudited)	2016
LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Current maturities of debt	$ 344,315	$ 599,341
Accounts payable, principally trade	11,375,720	11,009,631
Commodity derivative instruments	250,592	1,340,451
Asset retirement obligations	383,830	376,735
Other accrued liabilities	3,179,182	2,572,680
Total current liabilities	15,533,639	15,898,838
LONG-TERM DEBT	39,500,000	39,500,000
OTHER NONCURRENT LIABILITIES:
Asset retirement obligations	9,951,122	9,819,648
Commodity derivative instruments	-	1,215,551
Total other noncurrent liabilities	9,951,122	11,035,199
COMMITMENTS AND CONTINGENCIES (Note 13)
EQUITY
Preferred stock
Series D Convertible ($.001 par value, 7,000,000 authorized, 1,807,385
issued as of March 31, 2017 and 1,776,718 issued as of December 31, 2016)	1,808	1,777
Common stock
($.001 par value, 100 million shares authorized, 12,211,256 issued as of
March 31, 2017 and 12,201,884 issued as of December 31, 2016)	12,211	12,202
Paid-in capital	44,268,868	43,877,563
Treasury stock at cost (1,109 shares as of March 31, 2017 and -0- shares as
of December 31, 2016)	(4,170 )	-
Accumulated earnings (deficit)	(10,124,153 )	(12,386,668 )
Total equity	34,154,564	31,504,874
TOTAL LIABILITIES AND EQUITY	$ 99,139,325	$ 97,938,911

 

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

 

 

5

 

 

Yuma Energy, Inc.

 

CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

 

	Three Months Ended March 31,
	2017	2016
REVENUES:
Sales of natural gas and crude oil	$ 7,144,424	$ 2,178,932
EXPENSES:
Lease operating and production costs	2,661,264	986,697
General and administrative – stock-based compensation	51,735	196,924
General and administrative – other	2,176,002	2,165,514
Depreciation, depletion and amortization	3,140,940	1,788,225
Asset retirement obligation accretion expense	138,569	52,059
Impairment of oil and gas properties	-	9,847,887
Gain on asset sales	(555,642 )	-
Other	-	3,188
Total expenses	7,612,868	15,040,494
LOSS FROM OPERATIONS	(468,444 )	(12,861,562 )
OTHER INCOME (EXPENSE):
Net gains from commodity derivatives	3,556,783	456,314
Interest expense	(496,091 )	(42,708 )
Other, net	36,408	-
Total other income (expense)	3,097,100	413,606
INCOME (LOSS) BEFORE INCOME TAXES	2,628,656	(12,447,956 )
Income tax expense	26,531	2,602
NET INCOME (LOSS)	2,602,125	(12,450,558 )
PREFERRED STOCK:
Dividends paid in kind	339,610	320,279
NET INCOME (LOSS) ATTRIBUTABLE TO
COMMON STOCKHOLDERS	$ 2,262,515	$ (12,770,837 )
INCOME (LOSS) PER COMMON SHARE:
Basic	$ 0.19	$ (1.71 )
Diluted	$ 0.16	$ (1.71 )
WEIGHTED AVERAGE NUMBER OF
COMMON SHARES OUTSTANDING:
Basic	12,211,256	7,454,062
Diluted	14,056,170	7,454,062

 

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

 

 

6

 

 

Yuma Energy, Inc.

 

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

(Unaudited)

 

	Preferred Stock		Common Stock		Paid-in Capital	Treasury Stock	Accumulated Deficit	Stockholders' Equity
	Shares	Value	Shares	Value
December 31, 2016	1,776,718	$ 1,777	12,201,884	$ 12,202	$ 43,877,563	$ -	$ (12,386,668 )	$ 31,504,874
Net income							2,602,125	2,602,125
Payment of Series "D" dividends in kind	30,667	31	-	-	339,579	-	(339,610 )	-
Stock awards vested	-	-	9,372	9	(9 )	-	-	-
Amortization of stock-based compensation	-	-	-	-	51,735	-	-	51,735
Treasury stock - employee tax payment	-	-	-	-	-	(4,170 )	-	(4,170 )
March 31, 2017	1,807,385	$ 1,808	12,211,256	$ 12,211	$ 44,268,868	$ (4,170 )	$ (10,124,153 )	$ 34,154,564

 

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

 

 

7

 

 

Yuma Energy, Inc.

 

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

 

	Three Months Ended March 31,
	2017	2016
CASH FLOWS FROM OPERATING ACTIVITIES:
Reconciliation of net loss to net cash provided by (used in) operating activities:
Net loss	$ 2,602,125	$ (12,450,558 )
Depreciation, depletion and amortization of property and equipment	3,140,940	1,788,225
Impairment of oil and gas properties	-	9,847,887
Amortization of debt issuance costs	81,843	-
Net deferred income tax benefit	-	2,602
Stock-based compensation expense	51,735	196,924
Settlement of asset retirement obligations	-	(12,324 )
Accretion of asset retirement obligation	138,569	52,059
Bad debt expense	-	3,188
Net gains from commodity derivatives	(3,556,783 )	(456,314 )
Gain on sales of fixed assets	(555,642 )	-
Changes in assets and liabilities:
(Increase) decrease in accounts receivable	(795,740 )	1,445,512
Decrease in prepaids, deposits and other assets	306,021	232,729
Decrease in accounts payable and other current and
non-current liabilities	(461,542 )	(1,542,241 )
NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES	951,526	(892,311 )
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures for oil and gas properties	(2,053,826 )	(4,663,114 )
Proceeds from sale of oil and gas properties and other fixed assets	641,056	-
Derivative settlements	98,700	535,488
NET CASH USED IN INVESTING ACTIVITIES	(1,314,070 )	(4,127,626 )
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings	-	4,000,000
Repayments of borrowings	(255,026 )	-
Debt issuance costs	(76,452 )	-
Treasury stock repurchases	(4,170 )	-
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES	(335,648 )	4,000,000
NET DECREASE IN CASH AND CASH EQUIVALENTS	(698,192 )	(1,019,937 )
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD	3,625,686	4,064,094
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$ 2,927,494	$ 3,044,157
Supplemental disclosure of cash flow information:
Interest payments (net of interest capitalized)	$ 264,542	$ 42,709
Income tax payments	$ -	$ -
Supplemental disclosure of significant non-cash activity:
(Increase) decrease in capital expenditures financed by accounts payable	$ (1,434,132 )	$ (1,613,607 )

 

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

 

 

8

 

 

YUMA ENERGY, INC.

NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

 

NOTE 1 – Organization and Basis of Presentation

 

Organization

 

Yuma Energy, Inc., a Delaware corporation (“Yuma” and collectively with its subsidiaries, the “Company”), is an independent Houston-based exploration and production company focused on acquiring, developing and exploring for conventional and unconventional oil and natural gas resources, primarily in the U.S. Gulf Coast, the Permian Basin of west Texas and California. The Company has employed a 3-D seismic-based strategy to build an inventory of development and exploration prospects. The Company’s operations are currently focused on onshore properties located in southern Louisiana, southeastern Texas, and the Permian Basin of west Texas. In addition, the Company has non-operated positions in the East Texas Eagle Ford and Woodbine and the Bakken Shale in North Dakota, and operated positions in Kern and Santa Barbara Counties in California.

 

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

 

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

 

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

 

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

 

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

 

 

9

 

 

Basis of Presentation

 

The accompanying unaudited consolidated financial statements of the Company and its wholly owned subsidiaries have been prepared in accordance with Article 8-03 of Regulation S-X for interim financial statements required to be filed with the Securities and Exchange Commission (“SEC”). The information furnished herein reflects all adjustments that are, in the opinion of management, necessary for the fair presentation of the Company’s Consolidated Balance Sheets as of March 31, 2017, and December 31, 2016; the Consolidated Statements of Operations for the three months ended March 31, 2017 and 2016; the Consolidated Statements of Changes in Equity for the three months ended March 31, 2017; and the Consolidated Statements of Cash Flows for the three months ended March 31, 2017 and 2016. The Company’s balance sheet at December 31, 2016 is derived from the audited consolidated financial statements of the Company at that date.

 

The preparation of financial statements in conformity with the generally accepted accounting principles of the United States of America (“GAAP”) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. For further information, see Note 2 in the Notes to Consolidated Financial Statements contained in the Company’s Annual Report on Form 10-K for the year ended December 31, 2016.

 

Interim period results are not necessarily indicative of results of operations or cash flows for the full year and accordingly, certain information normally included in financial statements and the accompanying notes prepared in accordance with GAAP has been condensed or omitted. These financial statements should be read in conjunction with the Company’s Annual Report on Form 10-K for the year ended December 31, 2016. The Company has evaluated events or transactions through the date of issuance of these unaudited consolidated financial statements.

 

NOTE 2 – Changes in Accounting Principles

 

Not Yet Adopted

 

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

 

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

 

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

 

 

10

 

 

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

 

Recently adopted

 

The FASB issued ASU 2017-01, “Business Combinations (Topic 805): Clarifying the Definition of a Business,” which assists in determining whether a transaction should be accounted for as an acquisition or disposal of assets or as a business. This ASU provides a screen that when substantially all of the fair value of the gross assets acquired, or disposed of, are concentrated in a single identifiable asset, or a group of similar identifiable assets, the set will not be considered a business. If the screen is not met, a set must include an input and a substantive process that together significantly contribute to the ability to create an output to be considered a business. This ASU is effective for annual and interim periods beginning in 2018 and is required to be adopted using a prospective approach, with early adoption permitted for transactions not previously reported in issued financial statements. The Company adopted this ASU on January 1, 2017, and expects that the adoption of this ASU could have a material impact on future consolidated financial statements as goodwill would not be allocated to divestitures or recorded for acquisitions that are not considered to be businesses.

 

The FASB issued ASU 2016-09, “Compensation—Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting,”   which   simplifies the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, classification on the statement of cash flows, and accounting for forfeitures. The Company adopted this ASU on January 1, 2017, and it will not have a material impact on the Company’s future consolidated financial statements.

 

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

 

NOTE 3 – Asset Impairments

 

The Company’s oil and natural gas properties are accounted for using the full cost method of accounting, under which all productive and nonproductive costs directly associated with property acquisition, exploration and development activities are capitalized. These capitalized costs (net of accumulated DD&A and deferred income taxes) of proved oil and natural gas properties are subject to a full cost ceiling limitation. The ceiling limits these costs to an amount equal to the present value, discounted at 10%, of estimated future net cash flows from estimated proved reserves less estimated future operating and development costs, abandonment costs (net of salvage value) and estimated related future income taxes. In accordance with SEC rules, prices used are the 12 month average prices, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12 month period prior to the end of the reporting period, unless prices are defined by contractual arrangements. Prices are adjusted for “basis” or location differentials. Prices are held constant over the life of the reserves. The Company’s first quarter of 2017 full cost ceiling calculation was prepared by using (i) $47.61 per barrel for oil, and (ii) $2.73 per MMBTU for natural gas as of March 31, 2017. If unamortized costs capitalized within the cost pool exceed the ceiling, the excess is charged to expense and separately disclosed during the period in which the excess occurs. Amounts thus required to be written off are not reinstated for any subsequent increase in the cost center ceiling. During the three month periods ended March 31, 2017 and 2016, the Company recorded full cost ceiling impairments after income taxes of $-0- and $9.8 million, respectively.

 

 

11

 

 

NOTE 4 – Asset Retirement Obligations

 

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

 

The following table summarizes the Company’s asset retirement obligation transactions recorded during the three months ended March 31, 2017 in accordance with the provisions of FASB ASC Topic 410, “Asset Retirement and Environmental Obligations” :

 

	Three Months Ended
	March 31, 2017
Asset retirement obligations at December 31, 2016	$ 10,196,383
Liabilities incurred	-
Liabilities settled	-
Liabilities sold	-
Accretion expense	138,569
Revisions in estimated cash flows	-
Asset retirement obligations at March 31, 2017	$ 10,334,952

 

Based on expected timing of settlements, $383,830 of the asset retirement obligation is classified as current at March 31, 2017.

 

NOTE 5 – Fair Value Measurements

 

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

 

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

 

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

 

 

12

 

 

	Fair value measurements at March 31, 2017
		Significant
	Quoted prices	other	Significant
	in active	observable	unobservable
	markets	inputs	inputs
	(Level 1)	(Level 2)	(Level 3)	Total
Assets:
Commodity derivatives – oil	$ -	$ 1,264,880	$ -	$ 1,264,880
Commodity derivatives – gas	-	(112,207 )	-	$ (112,207 )
Total assets	$ -	$ 1,152,673	$ -	$ 1,152,673
Liabilities:
Commodity derivatives – oil	$ -	$ (68,532 )	$ -	$ (68,532 )
Commodity derivatives – gas	-	319,124	-	$ 319,124
Total liabilities	$ -	$ 250,592	$ -	$ 250,592

 

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

 

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

 

Debt – The Company’s debt is recorded at the carrying amount on its Consolidated Balance Sheets (see Note 10 – Debt and Interest Expense). The carrying amount of floating-rate debt approximates fair value because the interest rates are variable and reflective of market rates.

 

Asset Retirement Obligations – The Company estimates the fair value of AROs based on discounted cash flow projections using numerous estimates, assumptions and judgments regarding such factors as the existence of a legal obligation for an ARO, amounts and timing of settlements, the credit-adjusted risk-free rate to be used and inflation rates (see Note 4 – Asset Retirement Obligations).

 

NOTE 6 – Commodity Derivative Instruments

 

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

 

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

 

 

13

 

 

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

 

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

 

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

 

Counterparty Credit Risk – Commodity derivative instruments expose the Company to counterparty credit risk. The Company’s commodity derivative instruments are with Société Générale (“SocGen”) and BP Energy Company, both of which are rated “A” by Standard and Poor’s and “A2” by Moody’s. 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 March 31, 2017 are provided below. Natural gas prices are New York Mercantile Exchange (“NYMEX”) Henry Hub prices, and crude oil prices are NYMEX West Texas Intermediate (“WTI”).

 

	2017	2018	2019
	Settlement	Settlement	Settlement
NATURAL GAS (MMBtu):
Swaps
Volume	1,748,574	1,451,734	-
Price	$ 3.13	$ 3.00	-
3-way collars
Volume	132,587	-	-
Ceiling sold price (call)	$ 3.38	-	-
Floor purchased price (put)	$ 3.02	-	-
Floor sold price (short put)	$ 2.47	-	-
CRUDE OIL (Bbls):
Swaps
Volume	105,214	195,152	156,320
Price	$ 52.24	$ 53.17	$ 53.77
3-way collars
Volume	83,023	-	-
Ceiling sold price (call)	$ 77.00	-	-
Floor purchased price (put)	$ 60.00	-	-
Floor sold price (short put)	$ 45.00	-	-

 

 

14

 

 

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

 

	Fair value as of
	March 31, 2017	December 31, 2016
Asset commodity derivatives:
Current assets	$ 896,651	$ 734,464
Noncurrent assets	678,470	54,380
	1,575,121	788,844
Liability commodity derivatives:
Current liabilities	(669,000 )	(2,074,915 )
Noncurrent liabilities	(4,040 )	(1,269,931 )
	(673,040 )	(3,344,846 )
Total commodity derivative instruments	$ 902,081	$ (2,556,002 )

 

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

 

	Three Months Ended March 31,
	2017	2016
Derivative settlements	$ 98,700	$ 535,488
Mark to market on commodity derivatives	3,458,083	(79,174 )
Net gains (losses) from commodity derivatives	$ 3,556,783	$ 456,314

 

NOTE 7 – Preferred Stock

 

The Company issued an aggregate of 1,754,179 shares of Series D Preferred Stock as part of the completion of the Davis Merger to former holders of Series A Preferred Stock, which is convertible into shares of the Company’s common stock. Each share of Series D Preferred Stock is convertible into a number of shares of common stock determined by dividing the original issue price, which was $11.0741176, by the conversion price, which is currently $11.0741176. The conversion price is subject to adjustment for stock splits, stock dividends, reclassification, and certain issuances of common stock for less than the conversion price. As of March 31, 2017, the Series D Preferred Stock had a liquidation preference of approximately $20.0 million and a conversion rate of $11.0741176 per share. The Series D Preferred Stock provides for cumulative dividends of 7.0% per annum, payable in-kind. The Company issued 30,667 shares of Series D Preferred Stock as in-kind dividends for the period from January 1, 2017 through March 31, 2017.

 

NOTE 8 – Stock-Based Compensation

 

2014 Long-Term Incentive Plan

 

On October 26, 2016, the Company assumed the Yuma California 2014 Long-Term Incentive Plan (the “2014 Plan”), which was approved by the shareholders of Yuma California. The shareholders of Yuma California originally approved the 2014 Plan at the special meeting of shareholders on September 10, 2014 and the subsequent amendment to the 2014 Plan at the special meeting of shareholders on October 26, 2016. Under the 2014 Plan, Yuma may grant stock options, restricted stock awards (“RSAs”), restricted stock units (“RSUs”), stock appreciation rights (“SARs”), performance units, performance bonuses, stock awards and other incentive awards to employees of Yuma and its subsidiaries and affiliates. Yuma may also grant nonqualified stock options, RSAs, RSUs, SARs, performance units, stock awards and other incentive awards to any persons rendering consulting or advisory services and non-employee directors of Yuma and its subsidiaries, subject to the conditions set forth in the 2014 Plan. Generally, all classes of Yuma’s employees are eligible to participate in the 2014 Plan.

 

 

15

 

 

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

 

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

 

At March 31, 2017, 2,152,920 shares of the 2,495,000 shares of common stock originally authorized under active share-based compensation plans remained available for future issuance. The Company generally issues new shares to satisfy awards under employee share-based payment plans. The number of shares available is reduced by awards granted.

 

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

 

Restricted Stock and Stock Appreciation Rights – RSAs and SARs granted to officers, directors and employees generally vest in one-third increments over a three-year period, and are contingent on the recipient’s continued employment. During the three months ended March 31, 2017, the Company granted -0- RSAs and -0- SARs.

 

Total share-based compensation expenses recognized for the three months ended March 31, 2017 and 2016 were $51,735 and $196,924, respectively, and are reflected in general and administrative expenses in the Consolidated Statements of Operations.

 

NOTE 9 – Earning Per Common Share

 

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

 

 

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A reconciliation of earnings per common share is as follows: 

 

	Three Months Ended March 31,
	2017	2016
Net income (loss) attributable to common stockholders	$ 2,262,515	$ (12,770,837 )
Weighted average common shares outstanding
Basic	12,211,256	7,454,062
Add potentially dilutive securities:
Unvested restricted stock awards	67,855	-
Stock appreciation rights	-	-
Stock options	-	-
Series A preferred stock	-	-
Series D preferred stock	1,777,059	-
Diluted weighted average common shares outstanding	14,056,170	7,454,062
Net income (loss) per common share:
Basic	$ 0.19	$ (1.71 )
Diluted	$ 0.16	$ (1.71 )

 

For the three months ended March 31, 2016, the Company excluded 235,646 shares of unvested RSAs, 337,452 stock options and 1,686,115 shares of Series A Preferred Stock in calculating diluted earnings per share, as the effect was anti-dilutive.

 

NOTE 10 – Debt and Interest Expense

  

Long-term debt consisted of the following:

 

	March 31,	December 31,
	2017	2016
Senior credit facility	$ 39,500,000	$ 39,500,000
Installment loan due 7/15/17 originating from the financing of
insurance premiums at 4.38% interest rate	344,315	599,341
Total debt	39,844,315	40,099,341
Less: current maturities	(344,315 )	(599,341 )
Total long-term debt	$ 39,500,000	$ 39,500,000

 

Senior Credit Facility

 

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

 

The initial borrowing base of the credit facility was $44.0 million, which was reaffirmed as of January 1, 2017. The borrowing base is subject to redetermination on April 1st and October 1st of each year, as well as special redeterminations described in the Credit Agreement. The April 2017 redetermination is still in process. The amounts borrowed under the Credit Agreement bear annual interest rates at either (a) the London Interbank Offered Rate (“LIBOR”) plus 3.00% to 4.00% or (b) the prime lending rate of SocGen plus 2.00% to 3.00%, depending on the amount borrowed under the credit facility and whether the loan is drawn in U.S. dollars or Euro dollars. The interest rate for the credit facility at March 31, 2017 was 4.54% and was based on LIBOR. Principal amounts outstanding under the credit facility are due and payable in full at maturity on October 26, 2019. All of the obligations under the Credit Agreement, and the guarantees of those obligations, are secured by substantially all of the Company’s assets. Additional payments due under the Credit Agreement include paying a commitment fee to the Lender in respect of the unutilized commitments thereunder. The commitment rate is 0.50% per year of the unutilized portion of the borrowing base in effect from time to time. The Company is also required to pay customary letter of credit fees.

 

 

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

 

In addition, the Credit Agreement requires the Company to maintain the following financial covenants: a current ratio of not less than 1.0 to 1.0, a ratio of total debt to earnings before interest, taxes, depreciation, depletion, amortization and exploration expenses (“EBITDAX”) ratio of not greater than 3.5 to 1.0, a ratio of EBITDAX to interest expense for the four fiscal quarters ending on the last day of the fiscal quarter immediately preceding such date of determination to be less than 2.75 to 1.0, and cash and cash equivalent investments together with borrowing availability under the Credit Agreement of at least $3.0 million. For fiscal quarters ending prior to and not including the fiscal quarter ending December 31, 2017, EBITDAX will be calculated using an annualized EBITDAX and interest expense will be calculated using an annualized interest expense. Annualized EBITDAX is defined in the Credit Agreement as follows: (a) EBITDAX for the four-fiscal quarter period ending March 31, 2017 will be deemed to equal EBITDAX for the two-fiscal quarter period comprising the fiscal quarter ending December 31, 2016 and the fiscal quarter ending March 31, 2017, multiplied by two (2); and (b) EBITDAX for the four-fiscal quarter period ending June 30, 2017 will be deemed to equal EBITDAX for the three-fiscal quarter period comprising the fiscal quarter ending December 31, 2016, the fiscal quarter ending March 31, 2017 and the fiscal quarter ending June 30, 2017, multiplied by four-thirds (4/3). Annualized interest expense is defined in the Credit Agreement as follows: (a) interest expense for the four-fiscal quarter period ending on December 31, 2016 will be deemed to equal interest expense for such fiscal quarter multiplied by four (4); (b) interest expense for the four-fiscal quarter period ending March 31, 2017 will be deemed to equal interest expense for the two-fiscal quarter period comprising the fiscal quarter ending December 31, 2016 and the fiscal quarter ending March 31, 2017, multiplied by two (2); and (c) interest expense for the four-fiscal quarter period ending June 30, 2017 will be deemed to equal interest expense for the three-fiscal quarter period comprising the fiscal quarter ending December 31, 2016, the fiscal quarter ending March 31, 2017 and the fiscal quarter ending June 30, 2017, multiplied by four-thirds (4/3). The Credit Agreement contains customary affirmative covenants and defines events of default for credit facilities of this type, including failure to pay principal or interest, breach of covenants, breach of representations and warranties, insolvency, judgment default, and a change of control. Upon the occurrence and continuance of an event of default, the Lender has the right to accelerate repayment of the loans and exercise its remedies with respect to the collateral. As of March 31, 2017 and December 31, 2016, the Company was in compliance with the covenants under the Credit Agreement.

 

NOTE 11 – Stockholders’ Equity

 

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

 

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

 

NOTE 12 – Income Taxes

 

The Company’s effective tax rate for the three months ended March 31, 2017 and 2016 was 1.01% and (.02%), respectively. The difference between the statutory federal income taxes calculated using a U.S. Federal statutory corporate income tax rate of 35% and the Company’s effective tax rate of 1.01% for the three months ended March 31, 2017 is related to the valuation allowance on the deferred tax assets and state income taxes. The difference between the statutory federal income taxes calculated using a U.S. Federal statutory corporate income tax rate of 35% and the Company’s effective tax rate of (.02%) for the three months ended March 31, 2016 is primarily related to the full valuation allowance against its Federal and Louisiana net deferred tax assets.

 

 

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As of March 31, 2017, the Company had federal and state net operating loss carryforwards of approximately $130.0 million which expire between 2022 and 2035. Of this amount, approximately $61.3 million is subject to limitation under Section 382 of the Internal Revenue Code of 1986, as amended, which could result in some amounts expiring prior to being utilized. Realization of a deferred tax asset is dependent, in part, on generating sufficient taxable income prior to expiration of the loss carryforwards.

 

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

 

NOTE 13 – Commitments and Contingencies

 

Joint Development Agreement

 

On March 27, 2017, the Company entered into a Joint Development Agreement with Firethorn Petroleum, LLC and Carnes Natural Gas, Ltd., both unaffiliated entities, covering an area of approximately 52 square miles (33,280 acres) in Yoakum County, Texas. In connection with the agreement, the Company acquired an 87.5% interest in approximately 2,269 existing gross (1,985 net) leasehold acres. As the operator of the property covered by this agreement, the Company is committed to spend an additional $1.5 million. The Company intends to acquire additional leasehold acreage and begin drilling its first joint venture well in 2017.

 

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. See Part II, Item 1 – “Legal Proceedings” below for further details.

 

NOTE 14 – Subsequent Events

 

Yuma and its subsidiary, Pyramid Oil LLC have executed a Purchase, Sale, Settlement and Release Agreement with Texican Energy Corporation dated effective April 26, 2017. By virtue of said agreement, the Company has received $180,000 and conveyed its interest in all of the leasehold acreage, wells, and equipment in the Cat Canyon Prospect in Santa Barbara County, California, to Texican Energy Corporation. The Company retained the obligation to plug and abandon one well on the property and clean up its location pad area. See Part II, Item 1 – “Legal Proceedings” below for further details.

 

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

 

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with the accompanying unaudited consolidated financial statements and related notes thereto, included in Part I, Item 1 of this Quarterly Report on Form 10-Q and should further be read in conjunction with our Annual Report on Form 10-K for the year ended December 31, 2016.

 

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

 

19

 

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, the Permian Basin of west Texas and California. 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 properties located in southern Louisiana, southeastern Texas and recently, in the Permian basin of west Texas. In addition, we have non-operated positions in the East Texas Eagle Ford and Woodbine and 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.”

 

Full Cost Ceiling Test Impairment

 

We did not incur an impairment in the first quarter of 2017. If prices remain at current levels, subject to numerous factors and inherent limitations, and all other factors remain constant, the Company does not expect to incur a non-cash full cost impairment during the second quarter of 2017. There are numerous uncertainties inherent in the estimation of proved reserves and accounting for oil and natural gas properties in future periods. Our estimated second quarter 2017 full cost ceiling calculation has been prepared by substituting (i) $48.91 per barrel for oil, and (ii) $3.03 per MMBtu for natural gas for the expected realized prices as of June 30, 2017. The forecasted average realized price was based on the average realized price for sales of crude oil, natural gas liquids and natural gas on the first calendar day of each month for the first 11 months and an estimate for the twelfth month based on a quoted forward price. Changes to our reserves and future production were made due to changing the effective date of the evaluation from March 31, 2017 to June 30, 2017. All other inputs and assumptions have been held constant. Accordingly this estimate accounts for the impact of more current commodity prices in the second quarter of 2017 utilized in our full cost ceiling calculation.

 

Reincorporation and Davis Merger

 

On October 26, 2016, Yuma Energy, Inc., a California corporation (“Yuma California”), merged with and into the Company resulting in the reincorporation from California to Delaware (the “Reincorporation Merger”). In connection with the Reincorporation Merger, Yuma California converted each outstanding share of its 9.25% Series A Cumulative Redeemable Preferred Stock, no par value per share (the “Yuma California Series A Preferred Stock”), into 35 shares of its common stock, no par value per share (the “Yuma California Common Stock”), and then each share of Yuma California Common Stock was exchanged for one-twentieth of one share of common stock, $0.001 par value per share, of the Company (the “common stock”). Immediately after the Reincorporation Merger on October 26, 2016, a wholly owned subsidiary of the Company merged (the “Davis Merger”) with and into Davis Petroleum Acquisition Corp., a Delaware corporation (“Davis”), in exchange for approximately 7,455,000 shares of common stock and 1,754,179 shares of Series D Convertible preferred stock, $0.001 par value per share (the “Series D preferred stock”). The Series D preferred stock had an aggregate liquidation preference of approximately $19.4 million and a conversion rate of $11.0741176 per share at the closing of the Davis Merger, and will be paid dividends in the form of additional shares of Series D preferred stock at a rate of 7% per annum. As a result of the Davis Merger, the former holders of Davis common stock received approximately 61.1% of the then outstanding common stock of the Company and thus acquired voting control. Although the Company was the legal acquirer, for financial reporting purposes the Davis Merger was accounted for as a reverse acquisition of the Company by Davis.

 

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

 

 

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Results of Operations

 

Production

 

The following table presents the net quantities of oil, natural gas and natural gas liquids produced and sold by us for the three months ended March 31, 2017 and 2016, and the average sales price per unit sold.

 

	Three Months Ended March 31,
	2017	2016
Production volumes:
Crude oil and condensate (Bbls)	76,397	34,718
Natural gas (Mcf)	899,427	400,365
Natural gas liquids (Bbls)	33,474	30,262
Total (Boe) (1)	259,776	131,708
Average prices realized:
Crude oil and condensate (per Bbl)	$ 49.95	$ 29.95
Natural gas (per Mcf)	$ 2.84	$ 1.96
Natural gas liquids (per Bbl)	$ 23.15	$ 11.69

(1)

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

 

Revenues

 

The following table presents our revenues for the three months ended March 31, 2017 and 2016.

 

	Three Months Ended March 31,
	2017	2016
Sales of natural gas and crude oil:
Crude oil and condensate	$ 3,815,932	$ 1,039,687
Natural gas	2,553,443	785,610
Natural gas liquids	775,049	353,635
Total revenues	$ 7,144,424	$ 2,178,932

 

Sale of Crude Oil and Condensate

 

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

 

Crude oil volumes were 120.0% higher for the three months ended March 31, 2017 than the crude oil volumes sold during the three months ended March 31, 2016. The increase was due primarily to the Davis Merger, as Yuma’s crude oil volumes contributed 46,960 barrels of oil to the March 31, 2017 total sales volumes. Also contributing to the increase was the Cameron Canal field (7,221 barrels), offset by lower production on the El Halcon field (5,151 barrels). Realized crude oil prices experienced a 66.8% increase from the three months ended March 31, 2016 compared to the three months ended March 31, 2017.

 

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. Natural gas liquids 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.

 

 

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For the three months ended March 31, 2017 compared to the three months ended March 31, 2016, we experienced a 124.7% increase in natural gas volumes sold and a 10.6% increase in natural gas liquids sold. The increase was due primarily to the Davis Merger, as Yuma’s natural gas volumes contributed 401,358 Mcf to the March 31, 2017 total sales volumes. Also contributing to the increase was the Cameron Canal field (157,545 Mcf), offset by lower production on the Chalktown field (26,359 Mcf). During the same period, realized natural gas prices increased by 44.9% and realized natural gas liquids prices increased by 98.0%.

 

Expenses

 

Lease Operating Expenses

 

Our lease operating expenses (“LOE”) and LOE per Boe for the three months ended March 31, 2017 and 2016, are set forth below:

 

	Three Months Ended March 31,
	2017	2016
Lease operating expenses	$ 1,697,908	$ 629,988
Severance, ad valorem taxes and marketing	963,356	356,709
Total LOE	$ 2,661,264	$ 986,697
LOE per Boe	$ 10.24	$ 7.49
LOE per Boe without severance, ad valorem taxes and marketing	$ 6.54	$ 4.78

 

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.

 

The 169.7% increase in total LOE for the three months ended March 31, 2017 compared to the three months ended March 31, 2016 was due to the Davis Merger, as Yuma’s lease operating costs contributed $1,660,408 to the total LOE for the quarter. The LOE costs related to the Davis properties increased by $14,159. LOE per barrel of oil equivalent increased by 36.7% for the same period of the prior year generally due to the Yuma properties having higher per unit operating costs than the Davis properties.

 

General and Administrative Expenses

 

Our general and administrative (“G&A”) expenses for the three months ended March 31, 2017 and 2016, are summarized as follows:

 

	Three Months Ended March 31,
	2017	2016
General and administrative:
Stock-based compensation	$ 51,735	$ 196,924
Other	2,596,922	2,539,963
Capitalized	(420,920 )	(374,449 )
Net other	2,176,002	2,165,514
Net general and administrative expenses	$ 2,227,737	$ 2,362,438

 

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

 

 

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For the three months ended March 31, 2017, net G&A expenses of $2,227,737, were 5.7% lower than the amount for the three months ended March 31, 2016. The decrease in G&A expenses was primarily attributed to a decrease in stock-based compensation of $145,189.

 

Depreciation, Depletion and Amortization

 

Our depreciation, depletion and amortization (“DD&A”) for oil and gas properties for the three months ended March 31, 2017 and 2016, is summarized as follows:

 

	Three Months Ended March 31,
	2017	2016
DD&A	$ 3,031,039	$ 1,644,791
DD&A per Boe	$ 11.67	$ 12.49

 

DD&A increased by 84.3% for the three months ended March 31, 2017 compared to the three months ended March 31, 2016. The increase resulted primarily from the increase in the net quantities of crude oil and natural gas sold.

 

Impairment of Oil and Natural Gas Properties

 

We utilize the full cost method of accounting to account for our oil and natural gas exploration and development activities. Under this method of accounting, we are required on a quarterly basis to determine whether the book value of our oil and natural gas properties (excluding unevaluated properties) is less than or equal to the “ceiling,” based upon the expected after tax present value (discounted at 10%) of the future net cash flows from our proved reserves. Any excess of the net book value of our oil and natural gas properties over the ceiling must be recognized as a non-cash impairment expense. We recorded a full cost ceiling test impairment of $-0- and $9.8 million for the three months ended March 31, 2017 and 2016, respectively. The impact of low commodity prices that adversely affected estimated proved reserve volumes and future estimated revenues was the primary contributor to the ceiling impairments. Changes in production rates, levels of reserves, future development costs, transfers of unevaluated properties, and other factors will determine our actual ceiling test calculation and impairment analyses in future periods.

 

Interest Expense

 

Our interest expense for the three months ended March 31, 2017 and 2016, is summarized as follows:

 

	Three Months Ended March 31,
	2017	2016
Interest expense	$ 540,641	$ 42,708
Interest capitalized	(44,550 )	-
Net	$ 496,091	$ 42,708
Bank debt	$ 39,500,000	$ 4,000,000

 

Interest expense (net of amounts capitalized) increased $453,383 for the three months ended March 31, 2017 over the same period in 2016 as a result of higher borrowings following the Davis Merger on October 26, 2016.

 

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

 

 

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Income Tax Expense

 

The following summarizes our income tax expense (benefit) and effective tax rates for the three months ended March 31, 2017 and 2016:

 

	Three Months Ended March 31,
	2017	2016
Consolidated net income (loss) before income taxes	$ 2,628,656	$ (12,447,956 )
Income tax expense	$ 26,531	$ 2,602
Effective tax rate	1.01 %	(0.02 %)

 

Additionally, differences between the U.S. federal statutory rate of 35% and our effective tax rates are due to the tax effects of valuation allowances recorded against our deferred tax assets, state income taxes, and non-deductible expenses. Refer to Note 12 – Income Taxes in the Notes to the Unaudited Consolidated Financial Statements included in Part I of this report.

 

Liquidity and Capital Resources

 

Our primary and potential sources of liquidity include cash on hand, cash from operating activities, borrowings under our revolving credit facility, proceeds from the sales of assets, and potential proceeds from capital market transactions, including the sale of debt and equity securities. Our cash flows from operating activities are subject to significant volatility due to changes in commodity prices, as well as variations in our production. We are subject to a number of factors that are beyond our control, including commodity prices, our bank’s determination of our borrowing base, production declines, and other factors that could affect our liquidity and ability to continue as a going concern.  

 

Cash Flows from Operating Activities

 

Net cash provided by operating activities was $951,526 for the three months ended March 31, 2017 compared to $892,311 in cash used during the same period in 2016. This increase was primarily caused by increased revenue as a result of higher sales volumes due to the Davis Merger and realized commodity prices, offset by increases in lease operating expenses. Funds were also used for changes in assets and liabilities including a decrease of $461,542 in accounts payable and other liabilities.

 

One of the primary sources of variability in our cash flows from operating activities is fluctuations in commodity prices, the impact of which we partially mitigate by entering into commodity derivatives. Sales volume changes also impact cash flow. Our cash flows from operating activities are also dependent on the costs related to continued operations.

 

Cash Flows from Investing Activities

 

During the three months ended March 31, 2017, we had a total of $1,314,070 of cash used in oil and natural gas investing activities. Of that, $1,001,444 was related to the SL 18090 #2 well and $744,401 was spent on lease acquisition costs related to the Permian Basis acquisition. Also, $420,920 was capitalized G&A related to land, geological and geophysical costs.

 

During the three months ended March 31 2016, cash used in investing activities included $4,663,114 of capital expenditures, a majority of which were related to the drilling and completion of the EE Broussard #1.

 

Cash Flows from Financing Activities

 

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

 

 

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At March 31, 2017, we had a $44.0 million conforming borrowing base under our credit facility with $39.5 million advanced, leaving a borrowing capacity of $4.5 million.

 

Other than the credit facility, we had debt of $344,315 at March 31, 2017 from installment loans financing oil and natural gas property insurance premiums. We had a cash balance of $2,927,494 at March 31, 2017.

 

Credit Facility

 

See Note 10 – Debt and Interest Expense in the Notes to the Unaudited Consolidated Financial Statements in Item 1 of this report for detailed information regarding our revolving credit facility.

 

Hedging Activities

 

Current Commodity Derivative Contracts

 

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

 

Fair Market Value of Commodity Derivatives

 

	March 31, 2017		December 31, 2016
	Oil	Natural Gas	Oil	Natural Gas
Assets
Current	$ 711,350	$ (233,108 )	$ -	$ -
Noncurrent	$ 553,530	$ 120,901	$ -	$ -
Liabilities
Current	$ 68,532	$ (319,124 )	$ (24,140 )	$ (1,316,311 )
Noncurrent	$ -	$ -	$ (932,857 )	$ (282,694 )

 

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 Note 6 – Commodity Derivative Instruments in Item 1 of this report.

 

The fair market value of our commodity derivative contracts in place at March 31, 2017 and December 31, 2016 were $902,081 and ($2,556,002), respectively.

 

Off Balance Sheet Arrangements

 

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

 

Item 3. Quantitative and Qualitative Disclosures About Market Risk.

 

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

 

Item 4. Controls and Procedures.

 

Evaluation of disclosure controls and procedures.

 

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

  

As of March 31, 2017, we carried out an evaluation, under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Exchange Act Rule 13a-15(e)). Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that, as of March 31, 2017 our disclosure controls and procedures were effective.

 

Changes in internal control over financial reporting .

 

There were no changes in our internal control over financial reporting that occurred during the three month period ended March 31, 2017 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

 

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PART II. OTHER INFORMATION

 

Item 1.    Legal Proceedings.

 

From time to time, we are a party to various legal proceedings arising in the ordinary course of business. While the outcome of these matters cannot be predicted with certainty, we are not currently a party to any proceeding that we believe, if determined in a manner adverse to us, could have a potential material adverse effect on our financial condition, results of operations, or cash flows.

 

For a description of various legal and administrative matters to which we are a party, see Item 3 of our Annual Report on Form 10-K for the year ended December 31, 2016. There have been no material changes to those matters as of the date of this report, except as detailed below.

 

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

 

In September 2015, a suit was filed against the Company and Pyramid Oil LLC (“Pyramid”) 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 alleged that the 1950 Community Oil and Gas Lease between them and Pyramid has expired by non-production.  The Company claimed 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 filed a First Amended Cross Complaint against Texican Energy Corporation (“Texican”) and Everett Lawley alleging interference with contractual relations and prospective economic relations, and violation of the California Uniform Trade Secrets Act.

 

             Pyramid and Texican entered into a Purchase, Sale, Settlement and Release Agreement dated April 26, 2017, wherein Pyramid and Texican settled their claims against each other and Pyramid sold all of its interest in the leases, wells, equipment, etc. to Texican. Pyramid retained certain P&A and clean-up obligations on the Ontiveros property, and will address those obligations and seek a dismissal of the lawsuit with Ontiveros now that the subject properties have been assigned to Texican.

 

Item 1A. Risk Factors.

 

In addition to the other information set forth in this report, you should carefully consider the factors discussed in Part 1, “Item 1A – Risk Factors” in our Annual Report for the year ended December 31, 2016 on Form 10-K, which could materially affect our business, financial condition or future results. The risks described in our 2016 Annual Report on Form 10-K may not be the only risks facing our Company. There are no updates to our risk factors as disclosed in our Annual Report on Form 10-K for the year ended December 31, 2016. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial may materially adversely affect our business, financial condition and/or operating results.

 

 

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

 

	Total Number of Shares Purchased (1)	Average Price Paid Per Share	Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Maximum Number (or of Approximate Dollar Value) Shares that May Yet Be Purchased Under the Plans or Programs
January 2017	1,109	3.76	-	-
February 2017	-	-	-	-
March 2017	-	-	-	-

 

(1)

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

 

Item 3. Defaults upon Senior Securities.

 

None.

 

Iem 4. Mine Safety Disclosures.

 

Not Applicable.

 

Item 5. Other Information.

 

None.

 

 

27

 

 

Item 6. Exhibits.

EXHIBIT INDEX

 

FOR

 

Form 10-Q for the quarter ended March 31, 2017.

Incorporated by Reference

Exhibit No.

Description

Form

SEC File No.

Exhibit

Filing Date

Filed Herewith

Furnished Herewith

31.1

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

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

 

 

28

 

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: May 11, 2017		Title:		Chief Executive Officer (Principal Executive Officer)
		By:		/s/ James J. Jacobs
Date: May 11, 2017		Name:		James J. Jacobs
		Title:		Chief Financial Officer (Principal Financial Officer)

 

 

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