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EX-99.7 - UNAUDITED PRO FORMA - Yuma Energy, Inc.yuma_ex997.htm
EX-99.3 - UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS - Yuma Energy, Inc.yuma_ex993.htm
 

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
FORM 8-K/A
(Amendment No. 2)
 
CURRENT REPORT
Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
 
Date of Report: October 26, 2016
(Date of earliest event reported)
 
Yuma Energy, Inc.
(Exact name of registrant as specified in its charter)
 
 
 
 
 
 
DELAWARE
(State or other jurisdiction
of incorporation)
 
0001672326
(Commission File Number)
 
94-0787340
(IRS Employer Identification No.)
 
1177 West Loop South, Suite 1825
Houston, Texas 77027
(Address of principal executive offices) (Zip Code)
 
(713) 968-7000
(Registrant’s telephone number, including area code)
 
 
 
 
 
(Former name or former address, if changed since last report)
 
 
Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:
 
 
Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)  
 
 
 
 
 
Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)  
 
 
 
 
 
Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))  
 
 
 
 
 
Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))  
 

 
 
 
 
Explanatory Note
 
As previously disclosed in its Current Report on Form 8-K filed on November 1, 2016 and as amended by Amendment No. 1 filed on November 3, 2016 (collectively, the “Prior 8-K”) with the Securities and Exchange Commission (the “SEC”), on October 26, 2016, Yuma Energy, Inc., a Delaware corporation (the “Company”), completed the agreement and plan of merger and reorganization dated as of February 10, 2016, and as amended on September 2, 2016 (the “Merger Agreement”), with Yuma Energy, Inc., a California corporation (“Yuma California”), Yuma Merger Subsidiary, Inc., a Delaware corporation and wholly-owned subsidiary of the Company (“Merger Subsidiary”), and Davis Petroleum Acquisition Corp. (“Davis”), providing for the merger of Yuma California with and into the Company (the “Reincorporation Merger”) and the merger of Merger Subsidiary with and into Davis (the “Merger”).
 
The Company is filing this Amendment No. 2 (“Amendment No. 2”) to the Prior 8-K to include (i) the unaudited consolidated financial statements of Davis as of and for the nine months ended September 30, 2016 and 2015, (ii) the unaudited consolidated financial statements of Yuma California for the three and nine months ended September 30, 2016 and 2015, incorporated by reference, and (iii) the pro forma financial statements giving effect to the Merger. Further, the Company has incorporated by reference into this Amendment No. 2 the audited financial statements of Yuma California for the years ended December 31, 2015, 2014 and 2013. Finally, the Company has incorporated by reference to this Amendment No. 2 the audited financial statements of Davis for the years ended December 31, 2015 and 2014. Except as set forth herein, this Amendment No. 2 does not amend, modify or update the disclosure contained in the Prior 8-K.
 
Item 2.01.   Completion of Acquisition or Disposition of Assets.
 
On February 10, 2016 and as amended on September 2, 2016 (the “First Amendment”), Yuma California, the Company, Merger Subsidiary, and Davis entered into the Merger Agreement pursuant to which (i) Yuma California would merge with and into the Company (the “Reincorporation Merger”), the separate corporate existence of Yuma California would cease and the Company would be the successor or surviving corporation of the Reincorporation Merger, and (ii) following the Reincorporation Merger, Merger Subsidiary would merge with and into Davis (the “Merger”), with Davis being the successor or surviving corporation of the Merger and a wholly owned subsidiary of the Company. The Reincorporation Merger and the Merger were completed on October 26, 2016. The Company issued press releases regarding the Reincorporation Merger and the Merger, which are attached to this Current Report on Form 8-K as Exhibits 99.1 and 99.2, respectively.
 
Immediately prior to the consummation of the Reincorporation Merger, each share of Series A Preferred Stock was converted into 35 shares of Yuma California Common Stock, which included any accrued and unpaid dividends on the Series A Preferred Stock as of immediately prior to the consummation of the Reincorporation Merger. The conversion was approved by the shareholders of Yuma California.
 
As part of the consummation of the Reincorporation Merger, a 1-for-20 reverse stock split was effected, whereby (i) each share of Yuma California Common Stock was converted into one-twentieth of one share of Common Stock; (ii) each option to acquire Yuma California Common Stock granted pursuant to Yuma California 2006 Equity Incentive Plan (the “2006 Plan”) and outstanding immediately prior to the consummation of the Reincorporation Merger was automatically converted into the right to receive one-twentieth of one share of Common Stock for each share of Yuma California Common Stock subject to such option, on the same terms and conditions applicable to the option to purchase Common Stock, except that the exercise price of such option was multiplied by twenty; (iii) each outstanding share of restricted stock of Yuma California granted pursuant to the Yuma California 2011 Stock Option Plan (the “2011 Plan”) or Yuma California’s 2014 Long-Term Incentive Plan (the “2014 Plan”) was automatically converted into the right to receive one-twentieth of one share of Common Stock, on the same terms applicable to such restricted stock award; and (iv) each stock appreciation right granted pursuant to the 2014 Plan outstanding immediately prior to the consummation of the Reincorporation Merger, whether vested or unvested, exercisable or unexercisable, was automatically converted into the right to receive one-twentieth of one share of Common Stock for each share of Yuma California Common Stock subject to such stock appreciation right, on the same terms and conditions applicable to the stock appreciation right, except that the exercise price was multiplied by twenty.
 
Upon consummation of the Merger, Davis became a wholly owned subsidiary of the Company and holders of Davis common stock received, in exchange for such shares of common stock approximately 61.1% or approximately 7,455,000 shares of the outstanding shares of Common Stock and the holders of Davis preferred stock received approximately 1,754,000 shares of the Company’s Series D Convertible Preferred Stock, $0.001 par value per share (the “Series D Preferred Stock”), with a liquidation preference of approximately $19.4 million and a conversion rate of $11.0471176 per share as described in the Certificate of Designation of the Series D Preferred Stock (the “Certificate of Designation”) filed with the Delaware Secretary of State on October 26, 2016.
 
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The foregoing description of the Reincorporation Merger and the Merger is only a summary, does not purport to be complete, and is qualified in its entirety by reference to the Merger Agreement and the First Amendment, included with the Prior 8-K as Exhibit 2.1 and Exhibit 2.1(a), respectively, and incorporated herein by reference.
 
The foregoing description of the Certificate of Designation is only a summary, does not purport to be complete, and is qualified in its entirety by reference to the Certificate of Designation, included with the Prior 8-K as Exhibit 3.3 and incorporated herein by reference.
 
Immediately following the consummation of the Merger, the Company had approximately 12,201,000 shares of Common Stock issued and outstanding. The Common Stock began trading on the NYSE MKT under the symbol “YUMA” on October 27, 2016. Pursuant to Rule 12g-3(a) adopted under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), Yuma became the successor issuer of the Company and thereby assumed its obligations under Section 12(b) of the Exchange Act.
 
MANAGEMENT’S DISCUSSION AND ANALYSIS
OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS OF DAVIS
 
The following discussion should be read in conjunction with the consolidated financial statements of Davis and the notes thereto included elsewhere in this Current Report on Form 8-K. The discussion includes certain forward-looking statements. For a discussion of important factors which could cause actual results to differ materially from the results referred to in the forward-looking statements, see “Risk Factors – Risks Relating to Davis’ Business” and “Cautionary Note Regarding Forward-Looking Statements” in Yuma California’s and Davis’ definitive proxy statement/prospectus (the “Proxy Statement/Prospectus”), included in the Company’s registration statement on Form S-4, as amended (the “Form S-4”), which Form S-4 was declared effective by the SEC on September 22, 2016.
 
Overview
 
Davis’ financial results depend upon many factors, but are largely driven by the volume of its oil and gas production and the price that it receives for that production.  Generally, producing oil and gas properties begin their productive life at initial oil and gas production rates that decline over time based on reservoir characteristics, although operators may employ certain procedures to enhance production.  Davis’ various producing properties have different reservoir characteristics that may be expected to result in different levels of future production and different rates of future decline.  As reserves are produced and sold, Davis must locate and develop, or acquire, new oil and natural gas reserves to replace those being depleted by production. 
 
Davis’ Lac Blanc field is a deep, high-pressure, conventional, South Louisiana development with good-to-excellent reservoir quality.  Production is primarily natural gas from relatively high porosity and permeability formations through a pressure-depletion drive mechanism which allows relatively few boreholes to drain large volumes. Davis has experienced moderate but relatively steady decline rates at Lac Blanc over the life of the field to date and Davis anticipates the continuation of such declines.   
 
The Chalktown field is an oily, tight-sand, Southeast Texas resource play developed using horizontal wells and multi-stage hydraulic fracturing.  Well performance is characterized by high initial production rates followed by the relatively steep production decline rates.  An aggressive drilling program is required to maintain the field production rate because of the characteristically high rate of production decline.
 
Davis’ Cameron Canal field is a conventional, South Louisiana field with good-to-excellent reservoir quality that produces both oil and gas, but it is not as deep as the Lac Blanc field and reservoir volumes are not anticipated to be as large as some of those in the Lac Blanc field.   Davis anticipates moderate but steady decline rates in the Cameron Canal field.
 
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Critical Accounting Policies and Estimates
 
Oil and Gas Reserves
 
Davis’ engineering estimates of proved oil and natural gas reserves directly impact financial accounting estimates, including DD&A and the full cost ceiling limitation.
 
Davis’ estimates of proved oil and gas reserves constitute those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. At the end of each year, Davis’ proved reserves are estimated by independent petroleum engineers. These estimates, however, represent projections based on geologic and engineering data. Reserve engineering is a subjective process of estimating underground accumulations of oil and gas that are difficult to measure. The accuracy of any reserve estimate is a function of the quantity and quality of available data, engineering and geological interpretation and professional judgment. Estimates of economically recoverable oil and gas reserves and future net cash flows necessarily depend upon a number of variable factors and assumptions, such as historical production from the area compared with production from other producing areas, the assumed effect of regulations by governmental agencies, and assumptions governing future oil and gas prices, future operating costs, severance taxes, development costs and workover costs. The future drilling costs associated with reserves assigned to proved undeveloped locations may ultimately increase to the extent that these reserves may be later determined to be uneconomical.
 
Davis reports the value of its proved oil and natural gas reserves under both the standardized measure of discounted future net cash flows and under a non-GAAP financial measure known as PV-10 which reflect the estimated value of future net cash flows from such reserves under certain oil and gas commodities prices. Davis accounts for its oil and gas producing activities using the full cost method of accounting. Accordingly, the value of Davis’ oil and gas properties on its financial statements reflects the historical cost of finding and developing proved reserves, net of accumulated depreciation, depletion and amortization and related deferred taxes, not the value of such reserves or their associated net cash flows. The carrying value of Davis’ oil and gas properties on its consolidated financial statements is limited, however, to the full cost ceiling (described below), which is the deemed value of such properties based on estimated future net cash flows assuming certain future oil and gas commodities prices. Any significant inaccuracy in the assumptions affecting the estimated quantity and value of the reserves and/or the rate of depletion of such oil and gas properties could affect the carrying value of Davis’ oil and gas properties.
 
Oil and Gas Properties
 
Davis accounts for its oil and gas producing activities using the full cost method of accounting as prescribed by the SEC.  Accordingly, all costs incurred in the acquisition, exploration, and development of proved oil and gas properties, including the costs of abandoned properties, dry holes, geophysical costs, and annual lease rentals, are capitalized.  Internal costs that are directly related to finding and developing oil and gas properties are also capitalized.  All general corporate costs are expensed as incurred.  Sales or other dispositions of oil and gas properties are accounted for as adjustments to capitalized costs with no gain or loss recorded unless the relationship of cost to proved reserves would significantly change.  Depletion of evaluated oil and gas properties is computed on the units-of-production method based on proved reserves.  The net capitalized costs of proved oil and gas properties are subject to a quarterly full cost ceiling limitation in which the costs are not allowed to exceed their related estimated future net revenues using the twelve-month average of the first-day-of-the-month reference prices as adjusted for location and quality differentials and discounted at 10%, net of tax considerations.  Costs associated with unevaluated properties are excluded from the full cost pool until a determination is made as to whether proved reserves can be attributed to the related properties.  Unevaluated properties are evaluated periodically to determine whether the costs incurred should be reclassified to the full cost pool and thereby subject to amortization.
 
Capitalized costs of oil and gas properties, net of accumulated depreciation, depletion and amortization and related deferred taxes, are limited to the estimated future net cash flows from proved oil and gas reserves, discounted at 10%, plus the lower of cost or fair value of unproved properties, as adjusted for related income tax effects (the full cost ceiling). If capitalized costs exceed the full cost ceiling, the excess is charged to write-down of oil and gas properties in the quarter in which the excess occurs.
 
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Given the volatility of oil and gas prices, it is probable that Davis’ estimate of discounted future net cash flows from estimated proved oil and gas reserves will change in the near term. If oil or gas prices decline further, even for only a short period of time, or if Davis has downward revisions to its estimated volumes of proved reserves, it is possible that further write-downs of oil and gas properties could occur.
 
Asset Retirement Obligations
 
Davis records a liability equal to the fair value of the estimated cost to retire an asset.  The asset retirement obligation (“ARO”) liability is recorded in the period in which the obligation meets the definition of a liability.  When an ARO liability is recorded, Davis increases the carrying amount of the related long-lived asset by an amount equal to the original liability.  The liability is then accreted to its expected value each period, and the capitalized cost is depreciated over the useful life of the long-lived asset.  Any difference between costs incurred upon settlement of an asset retirement obligation and the recorded liability is recognized as an increase or decrease to proved properties, similar to how Davis recognizes gains and losses on divested oil and gas properties.  The ARO is based on a number of assumptions requiring judgment.  Davis cannot predict the type of revisions to these assumptions that will be required in future periods or the availability of additional information, including prices for oil field services, technological changes, governmental requirements, and other factors.
 
Deferred Taxes
 
Deferred income taxes are provided to reflect the tax consequences in future years of differences between the financial statement and tax bases of assets and liabilities. A valuation allowance is established to reduce deferred tax assets if it is more likely-than-not that the related tax benefits will not be realized.
 
Commodity Hedging Contracts and Other Derivatives
 
Davis periodically enters into derivative contracts to hedge future crude oil and natural gas production in order to mitigate the risk of market price fluctuations.  All derivatives are recognized on the balance sheet and measured at fair value.  Davis does not designate its derivative contracts as hedges, as defined in ASC 815, Derivatives and Hedging, and accordingly, recognizes changes in fair value, both realized and unrealized, as (gains) loss on derivative instruments in its income statement. Cash flows are only impacted to the extent the actual settlements under the contracts result in Davis making a payment to or receiving a payment from the counterparty.
 
Davis uses a variety of derivative instruments, such as swaps, collars, puts, calls and various combinations of these instruments, which may be utilized to manage exposure to the volatility of oil and gas commodity prices. Currently, Davis does not use derivatives to manage its exposure to fluctuations in interest rates.
 
The derivatives instruments Davis has in place are not classified as hedges for accounting purposes. These derivative contracts are reflected at fair value on Davis’ balance sheet and are marked-to-market each quarter with fair value gains and losses, both realized and unrealized, recognized currently as a gain or loss on mark-to-market derivative contracts on the income statement. Consequently, Davis expects continued volatility in its reported earnings as changes occur in the NYMEX index. Cash flow is only impacted to the extent the actual settlements under the contracts result in making or receiving a payment from the counterparty.
 
The estimation of fair values of derivative instruments requires substantial judgment. Valuation calculations incorporate estimates of future NYMEX prices, discount rates and price movements. As a result, Davis calculates the fair value of its commodity derivatives using an independent third-party’s valuation model that utilizes market-corroborated inputs that are observable over the term of the derivative contract. Davis’ fair value calculations also incorporate an estimate of the counterparties’ default risk for derivative assets and an estimate of its default risk for derivative liabilities. Davis also uses third-party valuations to determine the fair values of the contracts that are reflected on its consolidated balance sheets. Realized and unrealized gains and losses are also included in income (expense) on its consolidated statements of operations.
 
Results of Operations for the Three and Nine Months Ended September 30, 2016 and 2015
 
Davis’ results of operations are significantly affected by fluctuations in oil and gas prices. The following table reflects Davis’ production and average prices for crude oil, natural gas and natural gas liquids. These historical results are not necessarily indicative of results to be expected in future periods.
 
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Three Months Ended September 30,
 
 
Nine Months Ended September 30,
 
 
 
2016
 
 
2015
 
 
2016
 
 
2015
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Production
 
 
 
 
 
 
 
 
 
 
 
 
Oil - Bbls
  32,242 
  47,452 
  106,257 
  178,470 
NGL - Bbls
  23,903 
  35,894 
  74,282 
  101,951 
Natural Gas - Mcf
  507,521 
  635,996 
  1,553,906 
  2,053,827 
Total BOE
  140,732 
  189,345 
  439,523 
  622,726 
Total - Mcfe
  844,391 
  1,136,072 
  2,637,140 
  3,736,353 
 
    
    
    
    
Revenue
    
    
    
    
 
    
    
    
    
Oil
 $1,400,837 
 $2,233,659 
 $4,172,477 
 $8,875,276 
NGL 
  398,264 
  386,811 
  1,111,402 
  1,907,523 
Natural Gas
  1,249,148 
  1,705,874 
  3,295,258 
  5,744,057 
Total
 $3,048,249 
 $4,326,344 
 $8,579,137 
 $16,526,856 
 
    
    
    
    
Average Sales Price
    
    
    
    
Oil – per Bbl
 $43.45 
 $47.07 
 $39.27 
 $49.73 
NGL – per Bbl
 $16.66 
 $10.78 
 $14.96 
 $18.71 
Natural Gas – per Mcf
 $2.46 
 $2.68 
 $2.12 
 $2.80 
Total – per BOE
 $21.66 
 $22.85 
 $19.52 
 $26.54 
Total – per Mcfe
 $3.61 
 $3.81 
 $3.25 
 $4.42 
 
(1) 
Thousand cubic feet equivalent on the basis of one barrel of oil or natural gas liquids equal to six thousand cubic feet (Mcf) of natural gas.
 
(2) 
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.
 
Comparison of Results of Operations for the Three and Nine Months Ended September 30, 2016 and 2015
 
For the three months ended September 30, 2016, Davis had a net loss of $(1.9 million), or $(0.01) per diluted share compared to a net loss of $(0.5 million), or $(0.00) per diluted share in the same period of 2015.
 
Davis had a net loss of $(28.0 million), or $(0.19) per diluted share for the nine months ended September 30, 2016 compared to a net loss of $(7.9 million), or $(0.05) per diluted share for the same period in 2015. The 2016 net loss was impacted by impairments of oil and gas properties (ceiling test write-downs) in the amount of $17.6 million in the first nine months of 2016 compared with write-downs of $3.7 million for the same period in 2015.
 
Revenue
 
Oil and gas revenue for the three months ended September 30, 2016 was $3.0 million compared to $4.3 million for the same period in 2015.  Davis’ realized oil price of $43.45 per Bbl for the three months ended September 30, 2016 was a 7.7% decrease from the $47.07 per Bbl realized for the three months ended September 30, 2015.  Production was 140,732 Boe for the three months ended September 30, 2016 compared to 189,345 Boe for the same period in 2015.  Total production decreased primarily as a result of normal production declines (45,251 Boe), sold and abandoned wells (2,439 Boe) and a well shut-in for recompletion (28,289 Boe) and was partially offset by 27,366 Boe of production from the recently completed E.E. Broussard #1 ST2 well in the Cameron Canal field.
 
Oil and gas revenue for the nine months ended September 30, 2016 was $8.6 million compared to $16.5 million for the same period in 2015.  Davis’ realized oil price of $39.27 per Bbl for the nine months ended September 30, 2016 was a 21.0% decrease from $49.73 per Bbl realized for the nine months ended September 30, 2015.  Production of 439,523 Boe for the nine months ended September 30, 2016 compared to 622,726 Boe for the nine months ended September 30, 2015.  Total production decreased primarily as a result of normal production declines (126,485 Boe), sold and abandoned wells (38,358 Boe) and a well shut-in for recompletion (95,243 Boe) and was partially offset by 76,883 Boe of production from the recently completed E.E. Broussard #1 ST2 well in the Cameron Canal field.
 
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Prices
 
The average realized natural gas price per Mcf for the three months ended September 30, 2016 was $2.46 compared to $2.68 for the same period of 2015. Average realized oil price per Bbl for the three months ended September 30, 2016 was $43.45 compared to $47.07 for the same period of 2015, and the average realized natural gas liquids price per Bbl was $16.66 for the three months ended September 30, 2016 compared to $10.78 for the same period of 2015. Stated on a Boe basis, unit prices received during 2016 were 5.2% lower than the prices received during 2015.
 
The average realized natural gas price per Mcf for the nine months ended September 30, 2016 was $2.12 compared to $2.80 for the same period of 2015. Average realized oil price per Bbl for the nine months ended September 30, 2016 was $39.27 compared to $49.73 for the same period of 2015, and the average realized natural gas liquids price per Bbl was $14.96 for the nine months ended September 30, 2016 compared to $18.71 for the same period of 2015. Stated on a Boe basis, unit prices received during 2016 were 26.5% lower than the prices received during 2015.
 
Lease Operating Expenses
 
 
 
Three Months Ended September 30,
 
 
Nine Months Ended September 30,
 
($ in thousands, except per Boe amounts)
 
2016
 
 
2015
 
 
2016
 
 
2015
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Lease operating expenses
 $1,034 
 $1,330 
 $2,682 
 $4,822
Production taxes
  189 
  260 
  588 
  970 
Total LOE
 $1,223 
 $1,590 
 $3,270 
 $5,792
 
    
    
    
    
LOE per BOE
 $8.69 
 $8.40 
 $7.44 
 $9.30 
LOE per BOE without production taxes
 $7.35 
 $7.02 
 $6.10 
 $7.74 
 
Lease operating expenses and production taxes decreased 23.1% to $1,223 thousand in the three months ended September 2016 from $1,590 thousand in the same period of 2015 primarily due to the cost savings associated with de-manning the Lac Blanc platform ($95 thousand), sold and abandoned wells ($31 thousand), as well as normal production declines ($170 thousand). The decrease in total production taxes was primarily due to lower commodity prices.
 
For the nine months ended September 30, 2016, lease operating expenses and production taxes decreased 44% from the same period in 2015 primarily due to the cost savings associated with de-manning the Lac Blanc platform ($498 thousand), sold and abandoned wells ($1,284 thousand), as well as normal production declines ($358 thousand). The decrease in total production taxes was primarily due to lower commodity prices. The majority of Davis’ properties that are subject to severance taxes are assessed on the oil and gas sales value.
 
General and Administrative Expenses
 
 
 
Three Months Ended September 30,
 
 
Nine Months Ended September 30,
 
($ in thousands)
 
2016
 
 
2015
 
 
2016
 
 
2015
 
General and administrative:
 
 
 
 
 
 
 
 
 
 
 
 
Stock-based compensation
 $380 
 $188 
 $3,381 
 $745 
Capitalized
  - 
  - 
  (1,716)
  - 
Net stock-based compensation
  380 
  188 
  1,665 
  745 
 
    
    
    
    
Other
  2,218 
  1,694 
  10,090 
  7,197 
Capitalized
  (480)
  (426)
  (1,795)
  (1,416)
Net other
  1,738 
  1,268 
  8,295 
  5,781 
Net general and administrative expenses
 $2,118 
 $1,456 
 $9,960 
 $6,526 
 
 
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General and administrative expenses were $2.1 million for the three months ended September 30, 2016 compared to $1.5 million for the same period of 2015. Included in general and administrative expenses for 2016 were severance expenses of $0.4 million, merger-related costs of $0.5 million, and share-based compensation costs, net of amounts capitalized, of $0.4 million, compared to $0.2 million in 2015.
 
General and administrative expenses were $10.0 million for the nine months ended September 30, 2016 compared to $6.5 million in the same period of 2015. Included in general and administrative expenses for 2016 were severance expenses of $3.9 million, merger-related costs of $1.5 million, share-based compensation costs, net of amounts capitalized of $1.7 million, compared to $0.8 million in 2015. Davis capitalized $3.3 million of its general and administrative costs during 2016 compared to $1.0 million in 2015. Davis expects ongoing general and administrative expenses to decrease further in 2016 as a result of termination of employment of all non-essential personnel in anticipation of the merger.
 
Depreciation, Depletion and Amortization
 
 
 
Three Months Ended September 30,
 
Nine Months Ended September 30,
 
 
 
2016
 
 
2015
 
 
2016
 
 
2015
 
($ in thousands, except DD&A per BOE)
 
 
 
 
 
 
 
 
 
 
 
 
Production - BOE
  140,732 
  189,345 
  439,523 
  622,726 
Depreciation, depletion, and amortization
 $1,525 
 $4,051 
 $5,356 
 $14,386 
DD&A per BOE
 $10.84 
 $21.39 
 $12.19 
 $23.10 
 
Depreciation, depletion and amortization (“DD&A”) expenses for the three months ended September 30, 2016 totaled $1.5 million, or $10.84 per Boe compared to $4.1 million, or $21.39 per Boe, during the same period of 2015. DD&A expenses for the nine months ended September 30, 2016 totaled $5.4 million, or $12.19 per Boe compared to $14.4 million, or $23.10 per Boe, during the same period for the nine months ended September 30 for both2015. The decrease in the per unit DD&A rate was primarily the result of ceiling test write-downs for the nine months ended September 30 in both 2015 ($3.7 million) and 2016 ($17.6 million).
 
At September 30, 2016, the prices used in computing the estimated future net cash flows from Davis’ estimated proved reserves averaged $2.31 per Mcf of natural gas with respect to Louisiana and Gulf of Mexico properties, $2.30 per Mcf of natural gas with respect to with respect to Texas properties and $41.97 per barrel of oil and natural gas liquids, in each case adjusted by field for quality, transportation fees and market differentials. As a result of lower average commodity prices and their negative impact on Davis’ estimated proved reserves and estimated future net cash flows, Davis recognized a ceiling test write-down of approximately $17.6 million in the nine-month period of 2016 and $3.7 million in the same period of 2015.
 
Interest Expense
 
Interest expense decreased 53% to $81 thousand during the three months ended September 30, 2016 from $172 thousand during the same period of 2015. Interest expense totaled $195 thousand during the nine months ended September 30, 2016 compared to $478 thousand in the same period of 2015. The decrease in 2016 was due to lower amounts outstanding under Davis’ senior bank credit facility.
 
Income Tax Expense
 
Income tax expense during the nine months ended September 30, 2016, totaled $7 thousand compared to an income tax benefit of $4.2 million during 2015. Davis typically provides for income taxes at a statutory rate of 35% adjusted for permanent differences expected to be realized, primarily statutory depletion, non-deductible stock compensation expenses and state income taxes.
 
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At September 30, 2016, the effective tax rate of 0.02% is less than the statutory tax rate of 35% because Davis has recorded a full valuation allowance against its federal and Louisiana net deferred tax assets. The income tax expense of $7 thousand is related to Texas deferred taxes.
 
Liquidity and Capital Resources
 
Davis’ principal requirements for cash, other than working capital needs for existing operations, are costs of development of oil and gas properties, retirement of debt and the acquisition of oil and gas properties. Davis has historically funded its development program, debt repayments and acquisitions with cash flow from operations, bank financing, property divestitures and joint ventures with industry partners. Davis believes its liquidity and capital resources are sufficient to meet its obligations.
 
Cash Flow
 
 
 
Nine Months Ended September 30,
 
($ in thousands)
 
2016
 
 
2015
 
Net cash provided by (used in) operating activities
 $(908)
 $10,360 
Net cash used in investing activities
 $(8,578)
 $(15,431)
Net cash provided by (used in) financing activities
 $8,591 
 $(1,210)
 
Credit Facility
 
Davis’ senior bank credit facility provides for secured senior revolving credit availability of up to $9.0 million as of July 1, 2016 from a bank group led by Bank of America, N.A., subject to compliance with financial and other covenants.  In January 2013, the termination date of the senior bank credit facility was extended to January 4, 2016, in July 2015, the termination date of the senior bank credit facility was extended to July 6, 2016, and on July 1, 2016, the termination date of the senior bank credit facility was extended to September 30, 2016. On September 26, 2016, Davis completed the Sixth Amendment, which extended the maturity date to November 15, 2016.  Davis’ obligations under its senior bank credit facility are secured by a security interest in substantially all of its oil and gas properties. At September 30, 2016, Davis had $9.0 million of borrowings under its senior bank credit facility.
 
Nine Months Ended September 30, 2016 Compared to the Nine Months Ended September 30, 2015
 
In 2016, cash used in investing activities included $9.9 million of capital expenditures, a majority of which were related to the drilling of the E.E. Broussard #1 ST2 in the Cameron Canal field which began production in April 2016. These expenditures were partially offset by Davis’ receipt of $1.3 million of derivative settlements. In 2015, cash used in investing activities included $23.0 million of capital expenditures partially offset by Davis’ receipt of $7.3 million of derivative settlements.
 
Net cash provided by financing activities in 2016 consisted of borrowings under the revolving credit facility of $9.0 million. Net cash used in financing activities in 2015 consisted of borrowings under the revolving credit facility of $10.0 million offset by repayments under the revolving credit facility of $11.0 million.
 
Davis has financed its acquisition, exploration and development activities to date principally through cash flow from operations, bank borrowings and sales of assets. As of September 30, 2016, Davis had approximately $3.2 million of cash on hand and had $9.0 million outstanding under its senior bank credit facility. At such date, Davis had no availability under its senior bank credit facility, subject to compliance with the financial covenants thereunder.
 
Prices for oil and natural gas are subject to many factors beyond Davis’ control, such as weather, the overall condition of the global financial markets and economies, relatively minor changes in the outlook of supply and demand, and the actions of OPEC. Oil and natural gas prices have a significant impact on Davis’ cash flows available for capital expenditures and its ability to borrow and raise additional capital. The amount Davis can borrow under its senior bank credit facility is subject to periodic re-determination based in part on changing expectations of future prices. Lower prices may also reduce the amount of oil and natural gas that Davis can economically produce. Lower prices and/or lower production may decrease revenues, cash flows and the borrowing base under the senior bank credit facility, thus reducing the amount of financial resources available to meet Davis’ capital requirements. Davis’ ability to comply with the covenants in its debt agreements is dependent upon the success of its exploration and development program and upon factors beyond its control, such as oil and natural gas prices.
 
 
9
 
Derivative Instruments
 
Davis periodically seeks to reduce its exposure to commodity price volatility by hedging a portion of production through commodity derivative instruments.
 
The level of derivative activity Davis engages in depends on its view of market conditions, available derivative prices and operating strategy. A variety of derivative instruments, such as swaps, collars, puts, calls and various combinations of these instruments, may be utilized to manage exposure to the volatility of oil and gas commodity prices.
 
When engaging in oil and gas commodities swaps, Davis is required to pay the difference between the floating price and the fixed price (when the floating price exceeds the fixed price) regardless of whether Davis has sufficient production to cover the quantities specified in the hedge. Significant reductions in production at times when the floating price exceeds the fixed price could require Davis to make payments under certain hedge agreements even though such payments are not offset by sales of production. Hedging may also prevent Davis from receiving the full advantage of increases in oil or gas prices above the fixed amount specified in the hedge.
 
As of September 30, 2016, Davis had entered into the following contracts:
 
Production Period
Instrument Type
Daily Volumes
 
Weighted Average Price
 
Natural Gas:
 
 
 
 
 
2016
Natural Gas Swap
3,000 MMBtu
 $4.05 
 
    
Crude Oil:
 
 
    
October 2016 – December 2016
Three-Way Collar
400 Bbls
 $30.00 – 40.00 – 50.00
 
 
A “Three-Way Collar” combines a sold put, a purchased put and a sold call. The purchased put and sold put establish a floating minimum price and the sold call establishes a maximum price Davis will receive for the volumes under contract.
 
The fair market value of Davis’ commodity derivative contracts in place at September 30, 2016 and 2015, were $0.2 million and $3.6 million, respectively.
 
 
Item 9.01.
Financial Statements and Exhibits
 
(a)           
Financial Statements of Business Acquired.
 
The unaudited consolidated financial statements of Davis as of and for the nine months ended September 30, 2016 and 2015 are attached hereto as Exhibit 99.3 and incorporated herein by reference. The audited consolidated financial statements of Davis for the years ended December 31, 2015 and 2014 are attached hereto as Exhibit 99.4 and incorporated herein by reference.
 
The unaudited consolidated financial statements of Yuma California as of and for the three and nine months ended September 30, 2016 and 2015 are attached hereto as Exhibit 99.5 and incorporated herein by reference. The audited consolidated financial statements of Yuma California for the years ended December 31, 2015, 2014 and 2013 are attached hereto as Exhibit 99.6 and incorporated herein by reference.
 
(b)            
Pro Forma Financial Information.
 
The unaudited pro forma condensed consolidated combined balance sheet of the Company as of September 30, 2016 and the unaudited pro forma condensed consolidated combined statements of operations for the twelve months ended December 31, 2015 and the nine months ended September 30, 2016 are attached hereto as Exhibit 99.7 and are incorporated herein by reference. These unaudited pro forma financial statements give effect to the Merger on October 26, 2016, on the basis, and subject to the assumptions, set forth in accordance with Article 11 of Regulation S-X.
 
(d)            
Exhibits.
 
The following exhibits are included with this Amendment No. 2 to the Current Report on Form 8-K/A:
 
10
 
 
 
Exhibit No.
 
Description
 
 
 
 
 
Unaudited consolidated financial statements of Davis Petroleum Acquisition Corp. as of and for the nine months ended September 30, 2016 and 2015.
 
 
 
99.4
 
Audited consolidated financial statements of Davis Petroleum Acquisition Corp. for the years ended December 31, 2015 and 2014 (incorporated by reference from the Registrant’s Registration Statement on Form S-4 (Commission File No. 333-212103) declared effective on September 22, 2016).
 
 
 
99.5
 
Unaudited consolidated financial statements of Yuma Energy, Inc., a California corporation, as of and for the three and nine months ended September 30, 2016 and 2015 (incorporated by reference from the Quarterly Report on Form 10-Q of Yuma Energy, Inc. (File No.: 001-32989) filed with the SEC on November 14, 2016).
 
 
 
99.6
 
Audited consolidated financial statements of Yuma Energy, Inc., a California corporation, for the years ended December 31, 2015, 2014 and 2013 (incorporated by reference from the Registrant’s Registration Statement on Form S-4 (Commission File No. 333-212103) declared effective on September 22, 2016).
 
 
 
 
Unaudited pro forma condensed consolidated combined balance sheet of Yuma Energy, Inc., a Delaware corporation, as of September 30, 2016, and unaudited pro forma condensed consolidated combined statements of operations of Yuma Energy, Inc. for the twelve months ended December 31, 2015 and the nine months ended September 30, 2016.
 
 
11
 
SIGNATURE
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 hereunto duly authorized.
 
 
 
 
 
 
 
YUMA ENERGY, INC.
 
 
 
 
 
 
 
 
By:  
/s/ Sam L. Banks
 
 
 
Name:  
Sam L. Banks
 
Date: January 9, 2017
 
Title:  
President and Chief Executive Officer
 
 
 
 
 
12
 
EXHIBIT INDEX
 
Exhibit No.
 
Description
 
 
 
 
 
Unaudited consolidated financial statements of Davis Petroleum Acquisition Corp. as of and for the nine months ended September 30, 2016 and 2015.
 
 
 
99.4
 
Audited consolidated financial statements of Davis Petroleum Acquisition Corp. for the years ended December 31, 2015 and 2014 (incorporated by reference from the Registrant’s Registration Statement on Form S-4 (Commission File No. 333-212103) declared effective on September 22, 2016).
 
 
 
99.5
 
Unaudited consolidated financial statements of Yuma Energy, Inc., a California corporation, as of and for the three and nine months ended September 30, 2016 and 2015 (incorporated by reference from the Quarterly Report on Form 10-Q of Yuma Energy, Inc. (File No.: 001-32989) filed with the SEC on November 14, 2016).
 
 
 
99.6
 
Audited consolidated financial statements of Yuma Energy, Inc., a California corporation, for the years ended December 31, 2015, 2014 and 2013 (incorporated by reference from the Registrant’s Registration Statement on Form S-4 (Commission File No. 333-212103) declared effective on September 22, 2016).
 
 
 
 
Unaudited pro forma condensed consolidated combined balance sheet of Yuma Energy, Inc., a Delaware corporation, as of September 30, 2016, and unaudited pro forma condensed consolidated combined statements of operations of Yuma Energy, Inc. for the twelve months ended December 31, 2015 and the nine months ended September 30, 2016.
 
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