8-K/A

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.

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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
99.3	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).
99.7	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
99.3	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).
99.7	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.

 13

EX-99.3

Exhibit 99.3

DAVIS PETROLEUM ACQUISITION CORP.

CONSOLIDATED FINANCIAL STATEMENTS

SEPTEMBER 30, 2016

Table of Contents

Consolidated Balance Sheets	1
Consolidated Income Statements	2
Consolidated Statements of Cash Flows	3
Consolidated Statements of Changes in Stockholders’ Equity	4
Notes to the Consolidated Financial Statements	5

DAVIS PETROLEUM ACQUISITION CORP.

CONSOLIDATED BALANCE SHEETS

(Unaudited)

	September 30,	December 31,
	2016	2015
($ in thousands)
ASSETS
Current:
Cash	$3,169	$4,064
Accounts receivable	1,515	5,112
Joint interest advances paid	25	175
Derivative asset	230	1,711
Other current assets	804	877
Total current assets	5,743	11,939
Property, plant, and equipment:
Oil and gas properties - full cost method
Proved properties	436,960	425,767
Unevaluated properties	179	179
Other	9,035	9,034
Less: Accumulated depreciation, depletion, amortization and impairment	(412,264)	(389,345)
Total property, plant and equipment, net	33,910	45,635
Other assets	53	405
Deferred income taxes	1,419	1,426
TOTAL ASSETS	$41,125	$59,405
LIABILITIES
Current:
Accounts payable and accrued expenses	$2,111	$3,936
Current portion of long-term debt	9,000	-
Oil and gas revenues and royalties payable	210	439
Joint interest advances received	143	475
Current portion of asset retirement obligations	696	185
Total current liabilities	12,160	5,035
Asset retirement obligations	4,873	5,147
Other long-term liabilities	-	95
TOTAL LIABILITIES	17,033	10,277
Commitments and contingencies (Note 15)
STOCKHOLDERS' EQUITY
Common stock, par value $0.01 per share (authorized 400,100,000 shares; issued 224,084,069 and 223,584,069 as of September 30, 2016 and December 31, 2015, respectively)	2,241	2,236
Preferred stock, par value $0.01 per share (authorized 50,000,000 shares; issued 35,151,454 and 33,367,187 as of September 30, 2016 and December 31, 2015, respectively)	352	334
Treasury Stock, at cost; 73,983,561 at June 30, 2016 and 72,111,216 at December 31, 2015	(41,759)	(41,350)
Paid-in capital	211,624	207,284
Accumulated deficit	(148,366)	(119,376)
Total Stockholders' Equity	24,092	49,128
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$41,125	$59,405

See accompanying Notes to the Consolidated Financial Statements

1

DAVIS PETROLEUM ACQUISITION CORP.

CONSOLIDATED INCOME STATEMENTS

FOR THE NINE MONTHS ENDED SEPTEMBER 30

(Unaudited)

	Nine Months Ended
	September 30,
	2016	2015
($ in thousands)
REVENUES	$8,611	$16,664
EXPENSES
Lease operating and production costs	2,682	4,822
Production taxes	588	970
Depreciation, depletion and amortization	5,356	14,386
Impairment of oil and gas properties	17,561	3,661
General and administrative	9,960	6,526
Accretion expense	159	132
Other operating expense (income)	(35)	299
(Gain) loss on derivative instruments	161	(2,515)
Total expenses	36,432	28,281
LOSS FROM OPERATIONS	(27,821)	(11,617)
Other (income) and expense:
Interest and other income	(15)	(16)
Interest expense	195	478
Loss before income taxes	(28,001)	(12,079)
Income tax expense - current	-	-
Income tax expense (benefit) - deferred	7	(4,206)
NET LOSS	$(28,008)	$(7,873)
Earnings (Loss) Per Share
Basic	$(0.19)	$(0.05)
Diluted	$(0.19)	$(0.05)
Weighted Average Shares Outstanding (in thousands)
Basic	150,103	148,993
Diluted	150,103	148,993

See accompanying Notes to the Consolidated Financial Statements

2

DAVIS PETROLEUM ACQUISITION CORP.

CONSOLIDATED STATEMENTS OF CASH FLOWS

FOR THE NINE MONTHS ENDED SEPTEMBER 30

(Unaudited)

	2016	2015
($ in thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$(28,008)	$(7,873)
Adjustments to reconcile net income to net cash provided
operating activities:
Depreciation, depletion and amortization	5,356	14,386
Impairment of oil and gas properties	17,561	3,661
Net deferred income tax expense (benefit)	7	(4,206)
Stock-based compensation expense	1,665	746
Accretion expense	159	132
Derivative instruments (gain) loss	161	(2,515)
Working capital changes:
Decrease in accounts receivable	3,044	3,013
Decrease in other current and long-term assets	426	6,594
Decrease in accounts payable, accrued expenses and
other non-current liabilities	(870)	(5,579)
Decrease in oil and gas revenues payable	(229)	(296)
Increase (decrease) in joint interest advances	(180)	2,297
Net cash provided by (used in) operating activities	(908)	10,360
CASH FLOWS FROM INVESTING ACTIVITIES:
Acquisitions	-	(1,401)
Capital expenditures	(9,898)	(23,042)
Proceeds from the sale of properties	-	1,710
Derivative settlements	1,320	7,302
Net cash used in investing activities	(8,578)	(15,431)
CASH FLOWS FROM FINANCING ACTIVITIES:
Repayments on Senior Credit Facility	-	(11,000)
Borrowings on Senior Credit Facility	9,000	10,000
Treasury stock repurchases	(409)	(210)
Net cash provided by (used in) financing activities	8,591	(1,210)
Net decrease in cash	(895)	(6,281)
Cash - beginning of the period	4,064	10,477
Cash - end of the period	$3,169	$4,196

See accompanying Notes to the Consolidated Financial Statements

3

DAVIS PETROLEUM ACQUISITION CORP.

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

(Unaudited)

	Common Stock		Preferred Stock	Treasury Stock	Paid-in Capital	Accumulated Deficit	Stockholders' Equity
($ in thousands)	Shares	Value
December 31, 2015	223,584	$2,236	$334	$(41,350)	$207,284	$(119,376)	$49,128
Net loss	-	-	-	-	-	(28,008)	(28,008)
Payment of dividends in kind	-	-	18	-	964	(982)	-
Restricted stock grants, net of cancelations	500	5	-	-	3,155	-	3,160
Treasury stock - employee tax payment	-	-	-	(409)	-	-	(409)
Amortization of stock-based compensation	-	-	-	-	221	-	221
September 30, 2016	224,084	$2,241	$352	$(41,759)	$211,624	$(148,366)	$24,092

See accompanying Notes to the Consolidated Financial Statements

4

DAVIS PETROLEUM ACQUISITION CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Summary of Significant Accounting Policies

Organization and Nature of Operations

Davis Petroleum Acquisition Corp. (“DPAC”) is a Delaware corporation formed on January 18, 2006, for the purpose of acquiring the common stock of Davis Petroleum Corp., Davis Offshore L.P. and Davis Petroleum Pipeline LLC. In August 2014, the Company sold its interest in Davis Offshore L.P. Hereinafter, DPAC and its wholly-owned subsidiaries are collectively referred to as “Davis” or the “Company.”

Davis is an independent private oil and gas exploration, development, acquisitions and production company. The Company is focused primarily on opportunities in the onshore Gulf Coast region of Louisiana and Texas, where it has developed significant technical, operational and commercial expertise. Davis also regularly evaluates opportunities to expand its activities to other areas that may offer attractive exploration and development potential.

On February 10, 2016 and as amended on September 2, 2016, the Company entered into a definitive merger agreement (the “Merger Agreement”) with Yuma Energy, Inc., a California corporation (“Yuma”), and Yuma Energy, Inc., a Delaware corporation (“Yuma Delaware”). Under the terms of the definitive agreement, Yuma reincorporated in Delaware, implemented a one-for-twenty reverse split of its common stock, and converted each share of its existing Series A preferred stock into 35 shares of common stock prior to giving effect for the reverse split (1.75 shares post reverse split). Following these actions, Yuma issued additional shares of common stock in an amount sufficient to result in approximately 61.1% of the common stock being owned by the current common stockholders of Davis. In addition, Yuma issued approximately 1.75 million shares of a new Series D preferred stock to existing Davis preferred stockholders, which has a conversion price of approximately $11.074 per share, after giving effect for the reverse split. The Series D preferred stock had a liquidation preference of approximately $19.4 million at closing, and will be paid dividends in the form of additional Series D preferred stock at a rate of 7% per annum. The merger was completed on October 26, 2016.

Principles of Consolidation and Reporting

The interim consolidated financial statements of the Company are unaudited and include the accounts of DPAC and its wholly-owned subsidiaries. The year-end condensed balance sheet was derived from audited financial statements, but does not include all disclosures required by accounting principles generally accepted in the United States of America. The Company proportionately consolidates its interests in oil and gas joint ventures. All significant intercompany transactions have been eliminated in consolidation. In the opinion of management, all adjustments, consisting of normal recurring adjustments necessary for a fair statement, have been included. Management has made certain estimates and assumptions that affect reported amounts in the condensed consolidated financial statements and disclosures of contingencies. Actual results may differ from those estimates. The results for interim periods are not necessarily indicative of annual results.

Accounting Estimates

The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and 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. The most significant estimates pertain to proved natural gas and crude oil reserves and related cash flow estimates used in impairment tests of oil and gas properties and other long-lived assets, estimates of future development costs, income taxes, valuation of derivative instruments, dismantlement and abandonment costs, valuation of assets acquired and liabilities incurred in business combinations, estimates relating to certain natural gas and crude oil revenues and expenses, as well as estimates of expenses related to stock-based compensation, legal, environmental, and other contingencies. Actual results could differ from those estimates.

5

New Accounting Requirements

In March 2016, the Financial Accounting Standards Board (FASB) issued guidance regarding the simplification of share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. The guidance is effective for annual periods beginning after December 15, 2017, and interim periods beginning after December 15, 2018 with early adoption permitted for private entities. The guidance is effective for annual and interim periods beginning after December 31, 2016 with early adoption permitted for public entities. We are currently evaluating the impact of this guidance on our financial statements.

In February 2016, the FASB issued guidance regarding the accounting for leases. The guidance requires recognition of most lease assets and liabilities by lessees for those leases classified as operating leases. The guidance requires lessees and lessors to recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach. The guidance is effective for interim and annual periods beginning after December 15, 2019 for private entities and after December 15, 2018 for public entities. We are currently evaluating the impact of this guidance on our financial statements.

In January 2016, the FASB issued guidance regarding several broad topics related to the recognition and measurement of financial assets and liabilities. The guidance is effective for annual periods beginning after December 31, 2018 and interim periods beginning after December 15, 2019 for private entities. The guidance is effective for interim and annual periods beginning after December 15, 2017 for public entities. We are currently evaluating the impact of this guidance on our financial statements.

In August 2014, the FASB issued guidance regarding disclosures of uncertainties about an entity's ability to continue as a going concern. The guidance applies prospectively to all entities, requiring management 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 and to disclose certain information when substantial doubt is raised. The guidance is effective for interim and annual periods ending on or after December 15, 2016. We will adopt this guidance in the fourth quarter of 2016. We are currently evaluating the impact of this guidance on our financial statements.

In May 2014, the FASB issued guidance regarding the accounting for revenue from contracts with customers. The guidance may be applied retrospectively or using a modified retrospective approach to adjust retained earnings (deficit). In July 2015, the FASB approved a one-year deferral of the effective date for this guidance, which is now effective for annual periods after December 15, 2018 and interim periods after December 15, 2019 for private entities and effective for interim and annual periods beginning on or after December 15, 2017 for public entities. We are currently evaluating the impact of this guidance on our financial statements.

6

2. Accounts Receivable

Accounts receivable consisted of the following:

	September 30,	December 31,
	2016	2015
($ in thousands)
Natural gas and crude oil sales	$1,074	$4,286
Joint interest billings	441	826
Less: allowance for doubtful accounts	-	-
Accounts receivable	$1,515	$5,112

3. Other Current Assets

Other current assets consisted of the following:

	September 30,	December 31,
	2016	2015
($ in thousands)
Prepaid insurance	$15	$153
Other	789	724
Total other current assets	$804	$877

4. Property, Plant, and Equipment, net

Oil and Gas Properties

The following table sets forth the capitalized costs and associated accumulated depreciation, depletion and amortization (including impairments), relating to the Company’s oil and gas production, exploration, and development activities at:

($ in thousands)	September 30, 2016	December 31, 2015
Proved properties	$436,960	$425,767
Less: accumulated depreciation, depletion, amortization and impairment	(404,553)	(381,988)
Proved properties, net	32,407	43,779
Unproved properties
Unevaluated properties	179	179
Total unproved properties	179	179
Oil and gas properties, net	$32,586	$43,958

Under the full cost method, the Company is subject to quarterly calculations of a “ceiling” or limitation on the amount of costs associated with its oil and gas properties. This ceiling limits such capitalized costs to the present value using a 10% discount rate of estimated future cash flows from proved oil and natural gas reserves reduced by future operating expenses, development expenditures, abandonment costs (net of salvage values) and estimated future income taxes thereon. The ceiling calculation requires the Company to price its future oil and gas production at the twelve-month average of the first-day-of-the-month reference prices as adjusted for location and quality differentials. The Company recorded a ceiling test write-down of $17.6 million and $3.7 million for the nine months ended September 30, 2016 and 2015, respectively.

7

Other

Other property and equipment consists of the following:

	Useful	September 30,	December 31,
	life (years)	2016	2015
($ in thousands)
Plants and pipeline systems	10	$4,599	$4,599
Buildings	10	179	179
Furniture and fixtures	1-7	667	667
Automobiles	3	158	158
Software and IT equipment	3-5	2,006	2,006
Leasehold improvements	5	1,425	1,425
		9,034	9,034
Less: accumulated depreciation and amortization		(7,710)	(7,357)
Other property and equipment, net		$1,324	$1,677

5. Commodity Hedging Contracts

The Company is exposed to various market risks, including volatility in oil and gas commodity prices and interest rates. The level of derivative activity we engage in depends on our 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. Currently, the Company does not use derivatives to manage its exposure to fluctuations in interest rates.

All derivative instruments are recorded on the balance sheet at fair value. If a derivative does not qualify as a hedge or is not designated as a hedge, the changes in fair value, both realized and unrealized, are recognized in our income statement as (gains) loss on derivative instruments. Cash flows are only impacted to the extent the actual settlements under the contracts result in the Company making a payment to or receiving a payment from the counterparty. The Company’s derivative instruments in place are not classified as hedges for accounting purposes.

Period	Instrument Type	Average Daily Volumes	Average Fixed Price
October 2016 - December 2016	Natural Gas Swap	3,000 MMBtu	$4.05
October 2016 - December 2016	Crude Oil Three-Way-Collar	400 Bbl	$30 - 40 - 50

Balance Sheet

At September 30, 2016 and December 31, 2015, the Company had the following outstanding commodity derivative contracts recorded in its consolidated balance sheets ($ in thousands):

		Estimated Fair Value
		September 30,	December 31,
Instrument Type	Balance Sheet Classification	2016	2015
Natural Gas/Crude Oil Swaps/Collars	Derivative asset - short-term	$230	$1,711
Total derivative instruments		$230	$1,711

8

6. Fair Value Measurements of Assets and Liabilities

Authoritative guidance on fair value measurements defines fair value, establishes a framework for measuring fair value and stipulates the related disclosure requirements. The Company follows a three-level hierarchy, prioritizing and defining the types of inputs used to measure fair value.

The three levels of the fair value hierarchy are as follows:

Level 1 — Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 1 primarily consists of financial instruments such as exchange-traded derivatives, marketable securities and listed equities.

Level 2 — Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reported date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data, or are supported by observable levels at which transactions are executed in the marketplace. Instruments in this category generally include non-exchange-traded derivatives such as commodity swaps, basis swaps, options, and collars.

Level 3 — Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value.

The Company’s commodity derivative instruments are recorded at fair value on a recurring basis in its consolidated balance sheets with fair value changes recorded in the consolidated statements of income. The following table presents, for each fair value hierarchy level, the Company’s commodity derivative assets and liabilities measured at fair value on a recurring basis as of September 30, 2016 and December 31, 2015:

	Recurring Fair Value Measures
	As of September 30, 2016
($ in thousands)	Level 1	Level 2	Level 3
Natural Gas Swaps	$-	$290	$-
Crude Oil Three-Way Collars	-	(60)	-
Total	$-	$230	$-

	Recurring Fair Value Measures
	As of December 31, 2015
($ in thousands)	Level 1	Level 2	Level 3
Natural Gas Swaps	$-	$1,711	$-
Crude Oil Swaps		-
Total	$-	$1,711	$-

Derivatives listed above are carried at fair value. The fair value amounts on the consolidated balance sheets associated with the Company’s derivatives resulted from Level 2 fair value methodologies, which are based on observable market data for similar instruments.

9

This observable data includes the forward curve for commodity prices based on quoted markets prices and prospective volatility factors related to changes in commodity prices, as well as the credit standing of the counterparty involved, the impact of credit enhancements and the impact of the Company’s non-performance risk on derivative liabilities, or the non-performance risk of the Company’s counterparties on derivative assets, both of which are derived using credit default swap values.

Authoritative guidance also requires certain fair value disclosures for financial instruments other than derivatives, including the Company’s long-term debt. The borrowings were $9.0 million as of September 30, 2016 and there were no borrowings as of December 31, 2015. The amounts outstanding under our revolving credit facility are stated at cost, which approximates fair value.

Fair Value of Financial Instruments

The carrying value of cash and cash equivalents, accounts receivable, accounts payable, and other payables approximate their respective fair market values due to their short maturities.

7. Accounts Payable and Accrued Expenses

Accounts payable and accrued expenses consisted of the following at:

	September 30,	December 31,
	2016	2015
($ in thousands)
Trade payables	$312	$669
Accrued expenses	1,799	3,267
Total accounts payable	$2,111	$3,936

8. Income Taxes

The following summarizes the Company’s income tax expense (benefit) and effective tax rates (in thousands):

	Nine Months Ended
	September 30,
	2016	2015
Pre tax book income (loss)	$(28,001)	$(12,079)
Income tax expense (benefit)	7	(4,206)
Effective tax rate	0.02%	34.82%

For the nine months ended September 30, 2016, the effective tax rate of 0.02% is less than the statutory tax rate of 35% because the Company 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 against which the Company has not recorded a valuation allowance.

9. Long-term Debt

Senior Credit Facility

In December 2008, the Company amended and restated its senior credit agreement (the “Senior Credit Facility”) with a financial institution.  The SeniorCredit Facility was amended to increase the total capacity from $50 million to $125 million, subject to borrowing base limitations, and extend the term an additional four years.  In April 2011, the SeniorCredit Facility was amended to add an additional lender. In January 2013, the Company completed the Second Amendment to Amended and Restated Credit Agreement.  This amendment extended the maturity date to January 4, 2016. In July 2015 it was extended until July 6, 2016 and on July 1, 2016 it was amended and extended until September 30, 2016. On September 26, 2016 the Company completed the Sixth Amendment which extended the maturity date to November 15, 2016.

10

The borrowing base is determined at least semiannually and at December 31, 2015 was $24 million.  On May 17, 2016, the Company’s borrowing base was redetermined at $10.0 million and subsequently on July 1, 2016 when the Credit Facility was amended, the borrowing base was redetermined at $9.0 million.  Long-term debt as of September 30, 2016 was $9.0 million.

Revolving tranches under the Senior Credit Facility bear interest, at the Company’s election, at a prime rate or LIBOR rate, plus in each case an applicable margin.  In addition, a commitment fee is payable on the unused portion of the lender’s commitment.  The applicable interest rate margin varies from 1.25% to 2.00% in the case of borrowings based on the prime rate, and from 2.25% to 3.00% in the case of borrowings based on the LIBOR rate, depending on the utilization level in relation to the borrowing base.

For the nine months ended September 30, 2016 and 2015, the weighted average interest rate on the Senior Credit Facility was 2.67% and 2.50%, respectively.

The Senior Credit Facility is collateralized by mortgages on substantially all of the Company’s oil and gas properties and contains customary financial and other covenants, the most restrictive of which requires the Company’s ratio of consolidated current assets to consolidated current liabilities to be no less than 1.00 to 1.00 at the end of any quarter.  In addition, the Company is subject to covenants limiting dividends, transactions with affiliates, incurrence of debt, changes of control, asset sales, and affirmative representations regarding the absence of material adverse changes, and liens on properties.  The Company was in compliance with all debt covenants at September 30, 2016 and December 31, 2015.

New Senior Credit Facility

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

11

10. Stockholders’ Equity

Series A Convertible Preferred Stock

During the nine months ended September 30, 2016 and 2015, the Company issued 1,784,267 and 1,658,468 shares of Preferred Stock, respectively, as paid in-kind dividends. As of September 30, 2016, there were 35,151,454 shares of preferred stock outstanding.

11. Share-Based Compensation

Total share-based compensation expense recognized for the nine months ended September 30, 2016 and 2015 was $1,665 thousand ($3,380 less $1,715 capitalized) and $745 thousand, respectively, and is reflected in general and administrative expenses in the Consolidated Income Statement.

12. Earnings Per Share

Basic earnings per common share is computed by dividing net income (loss) attributable to common stock by the weighted average number of common shares outstanding during each year. The diluted earnings per share calculation adds to the weighted average number of common shares outstanding: the incremental shares that would have been outstanding assuming the exercise of dilutive stock options, the vesting of unvested restricted shares of common stock and the assumed conversion of convertible preferred stock.

	Nine Months Ended
	September 30,
	2016	2015
Net loss	$(28,008)	$(7,873)
Weighted average common shares - Basic	150,103	148,993
Effect of exercise of stock options (1)	-	-
Effective of conversion of preferred stock (2)	33,962	31,683
Weighted average common shares - Diluted	184,065	180,676
Earnings (loss) per common share
Basic	$(0.19)	$(0.05)
Diluted	$(0.19)	$(0.05)
(1)There were 6,804 thousand and 6,153 thousand stock options in 2016 and 2015, respectively
that were not included in the diluted shares outstanding as they were all out-of-the money.
(2)The effect of conversion of preferred stock was not included in the calculation of earnings per share
for all periods presented as they would have been anti-dilutive.

12

13. Supplemental Cash Flow Information

The following is additional information concerning supplemental disclosures of cash payments and non-cash investing and financing activities:

	Nine Months Ended
	September 30,
	2016	2015
(In thousands)
Cash paid for interest, net of amounts capitalized	$194	$311
Change in accrued capital expenditures	(498)	(13,098)

14. Revision of Previously Issued Financial Statements

During the preparation of Davis’ September 30, 2016 consolidated financial statements and the associated September 30, 2016 unaudited pro forma condensed consolidated combined statements of Yuma Delaware reflecting the merger between Davis and Yuma Delaware that was completed on October 26, 2016, Davis management identified certain errors related to the Company’s historical impairment calculations. These errors related to the Company’s failure to add back future cash outflows associated with abandonment cost in its calculation of the ceiling test, as well as the Company’s failure to update its fourth quarter 2015 ceiling test calculation for certain period-end financial reporting journal entries. In addition, two journal entries related to the Company’s accrued capital expenditures and prepaid AFE amounts were identified as not having been made in the third quarter of 2015. The Company assessed the materiality of these errors on the Company's previously issued statements, in accordance with the SEC’s Staff Bulletin No. 99 (“SAB 99”) and the SEC’s Staff Accounting Bulletin No. 108 (“SAB 108”), and concluded that the errors were not material to any previously issued financial statements. However, the Company has elected to correct these errors by revising its previously issued financial statements. The net effect of correcting these errors resulted in a reduction in impairment expense of $2.467 million and a reduction in depletion expense of $274,000 for the year ended December 31, 2015. Also, during the third quarter of 2015, the Company recognized a reduction of Accounts Payable and Proved Properties of $780,212 as well as a reduction to the Company’s Joint Interest Billing Prepaid account of $227,818 offset by an increase in Proved Properties for the same amount. For the six months ended June 30, 2016, the net effect of correcting the errors was a reduction in impairment expense of $971,000, offset by an increase in depletion expense of $201,000, for a net adjustment of $770,000. For the three months ended June 30, 2016, the net effect of correcting the errors was a reduction in impairment expense of $117,000, offset by an increase in depletion expense of $124,000, for a net adjustment of $7,000. These revisions had no impact on the Company’s subtotal of net cash provided by (used in) operating activities for the twelve months ended December 31, 2015 or the six months ended June 30, 2016.

The Company is revising its previously issued (i) consolidated balance sheet as of December 31, 2015, (ii) consolidated statements of operations, consolidated statements of changes in equity and consolidated statements of cash flows for the year ended December 31, 2015, and (iii) unaudited financial information for the quarter ended June 30, 2015 and for all subsequent quarters through June 30, 2016, along with certain related notes (the “Revision”).

The tables below illustrate the impact of the Revision on the Company’s consolidated financial statements, each as compared with the amounts presented in the original Form S-4 and related quarterly information previously filed with the SEC.

The following table represents a summary of the as previously reported balances, adjustments to correct the errors and revised balances on the Company’s consolidated balance sheets by impacted financial statement line item for the years 2016 and 2015 as of each quarter end:

13

	As of
	June 30, 2016
	(unaudited) ($ thousands)
	As Reported	Adjustment	As Revised
Joint interest advances paid	253	(228)	25
Total current assets	7,181	(228)	6,953
Proved properties	436,696	(552)	436,144
Less: Accumulated depreciation, depletion, amortization, and impairment	(414,237)	3,511	(410,726)
Total property, plant and equipment, net	31,673	2,958	34,631
Total Assets	40,711	2,730	43,441
Accounts payable and accrued expenses	3,094	(780)	2,314
Total current liabilities	13,770	(780)	12,990
Total liabilities	18,618	(780)	17,838
Accumulated deficit	(149,667)	3,511	(146,156)
Total stockholders’ equity	22,093	3,511	25,604
Total liabilities and stockholders’ equity	40,711	2,730	43,441

	As of
	December 31, 2015
	($ thousands)
	As Reported	Adjustment	As Revised
Joint interest advances paid	403	(228)	175
Total current assets	12,167	(228)	11,939
Proved properties	426,320	(553)	425,767
Less: Accumulated depreciation, depletion, amortization, and impairment	(392,086)	2,741	(389,345)
Total property, plant and equipment, net	43,447	2,188	45,635
Total Assets	57,444	1,961	59,405
Accounts payable and accrued expenses	4,716	(780)	3,936
Total current liabilities	5,815	(780)	5,035
Total liabilities	11,057	(780)	10,277
Accumulated deficit	(122,117)	2,741	(119,376)
Total stockholders’ equity	46,387	2,741	49,128
Total liabilities and stockholders’ equity	57,444	1,961	59,405

14

The following table represents a summary of the as previously reported balances, adjustments and revised balances on the Company’s consolidated statements of operations by financial statement line item for the periods ended:

	Three Months Ended
	March 31, 2016			June 30, 2016
	(unaudited) ($ thousands)			(unaudited) ($ thousands)
	As Reported	Adjustment	As Revised	As Reported	Adjustment	As Revised
Depreciation, depletion and amortization	1,710	78	1,788	1,921	124	2,045
Impairment of oil and gas properties	10,702	(854)	9,848	7,819	(117)	7,702
Total expenses	15,366	(776)	14,590	17,012	6	17,018
LOSS FROM OPERATIONS	(13,180)	776	(12,404)	(13,649)	(6)	(13,655)
NET LOSS BEFORE INCOME TAXES	(13,223)	776	(12,447)	(13,707)	(6)	(13,713)
NET LOSS	(13,226)	776	(12,450)	(13,677)	(6)	(13,683)
NET LOSS ATTRIBUTABLE TO COMMON STOCKHOLDERS	(13,226)	776	(12,450)	(13,677)	(6)	(13,683)
EARNINGS (LOSS) PER COMMON SHARE:
Basic	(0.09)	0.01	(0.08)	(0.09)	(0.00)	(0.09)
Diluted	(0.09)	0.01	(0.08)	(0.09)	(0.00)	(0.09)

15

	Six Months Ended
	June 30, 2016
	(unaudited) ($ thousands)
	As Reported	Adjustment	As Revised
Depreciation, depletion and amortization	3,632	201	3,833
Impairment of oil and gas properties	18,520	(971)	17,549
Total expenses	32,378	(770)	31,608
LOSS FROM OPERATIONS	(26,829)	770	(26,059)
NET LOSS BEFORE INCOME TAXES	(26,930)	770	(26,160)
Income tax (expense) benefit	(27)	-	(27)
NET LOSS	(26,903)	770	(26,133)
NET LOSS ATTRIBUTABLE TO COMMON STOCKHOLDERS	(26,903)	770	(26,133)
EARNINGS (LOSS) PER COMMON SHARE:
Basic	(0.18)	0.01	(0.17)
Diluted	(0.18)	0.01	(0.17)

16

	Year Ended
	December 31, 2015 ($ thousands)
	As Reported	Adjustment	As Revised
Depreciation, depletion and amortization	17,413	(274)	17,139
Impairment of oil and gas properties	42,947	(2,467)	40,480
Total expenses	72,814	(2,741)	70,074
LOSS FROM OPERATIONS	(54,040)	2,741	(51,300)
NET LOSS BEFORE INCOME TAXES	(54,597)	2,741	(51,857)
NET LOSS	(65,058)	2,741	(62,318)
NET LOSS ATTRIBUTABLE TO COMMON STOCKHOLDERS	(65,058)	2,741	(62,318)
EARNINGS (LOSS) PER COMMON SHARE:
Basic	(0.44)	0.02	(0.42)
Diluted	(0.44)	0.02	(0.42)

17

The following table represents a summary of the as previously reported balances, adjustments and revised balances on the Company’s consolidated statements of changes in equity by financial statement line item for the year ended December 31, 2015:

	Year Ended December 31, 2015 ($ thousands)
	As Reported	Adjustment	As Revised
Net loss attributable to Davis Petroleum Acquisition Corp.	(65,058)	2,741	(62,318)
Balance at end of period	(122,118)	2,742	(119,376)
TOTAL EQUITY	46,386	2,742	49,128

The following table represents a summary of the as previously reported balances, adjustments and revised balances on the Company’s consolidated statements of cash flows by financial statement line item for the year ended December 31, 2015:

	Year Ended December 31, 2015 ($ thousands)
	As Reported	Adjustment	As Revised
Net loss	(65,058)	2,741	(62,317)
Depreciation, depletion and amortization	17,413	(274)	17,139
Impairment of oil and gas properties	42,947	(2,467)	40,480

15. Commitments and Contingencies

We are not aware of any commitments or contingencies that warrant disclosure or would materially impact the financial statements.

 18

EX-99.7

Exhibit 99.7

UNAUDITED PRO FORMA CONDENSED CONSOLIDATED COMBINED FINANCIAL INFORMATION OF YUMA DELAWARE

Introduction

On February 10, 2016 and as amended on September 2, 2016, Yuma Energy, Inc., a California corporation, and certain of its wholly-owned subsidiaries (collectively, “Yuma”), and privately-held Davis Petroleum Acquisition Corp. a Delaware corporation (“Davis”), entered into a definitive merger agreement (the “Merger Agreement”) for an all-stock transaction (the “Merger”). The Merger was approved by the shareholders of Yuma and closed on October 26, 2016. Pursuant to the terms of the Merger Agreement, on October 26, 2016, Yuma reincorporated in Delaware (“Yuma Delaware”), and Davis became a direct subsidiary of Yuma Delaware.

As a result of the closing of the Merger, each share of Yuma’s common stock, no par value per share (“Yuma Common Stock”), was converted to one-twentieth of one (1) share (the “Reverse Stock Split”) of Yuma Delaware’s common stock, $0.001 par value per share (“Yuma Delaware Common Stock”). Additionally, each share of Yuma’s existing 9.25% Series A Cumulative Redeemable Preferred Stock, no par value per share (the “Series A Preferred Stock”), was converted into 35 shares of Yuma, before giving effect to the Reverse Stock Split. Following these actions, Yuma Delaware issued 7.46 million shares of Yuma Delaware Common Stock to the former stockholders of Yuma, which resulted in approximately 61.1% of the outstanding Yuma Delaware Common Stock being owned by the former holders of Davis common stock. Yuma Delaware also issued approximately 1.75 million shares of a new Series D Convertible Preferred Stock, $0.001 par value per share (the “Series D Preferred Stock”) to existing Davis preferred stockholders. Upon closing, there was an aggregate of approximately 12.20 million shares of Yuma Delaware Common Stock outstanding (after giving effect to the Reverse Stock Split and conversion of the Series A Preferred Stock to Yuma Common Stock as described above).

At the closing of the Merger, Davis appointed a majority of the board of directors of Yuma Delaware. Four out of the five members of Yuma’s board of directors prior to the closing of the Merger continue to serve on the board of directors of Yuma Delaware, with one of those four directors having been appointed by Davis. Three additional directors were appointed by Davis. The 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 Yuma Delaware Common Stock and majority representation on Yuma Delaware’s board of directors.

The following unaudited pro forma condensed consolidated combined financial statements reflect the combination of the historical consolidated results of both Yuma and Davis, on a pro forma basis to give effect to the following transactions, which are described in further detail below, as if they had occurred on September 30, 2016 for pro forma condensed consolidated combined balance sheet purposes, and on January 1, 2015 for pro forma condensed consolidated combined statement of operations purposes:

●

Purchase Accounting Adjustments. Although Yuma (the public company) is the legal acquirer, Davis (the private company) is the accounting acquirer. Accordingly, the assets and liabilities of Yuma are recorded at their preliminary estimated fair values. The final allocations of the Merger Agreement consideration and the effects of such allocations on Yuma Delaware’s results of operations may differ materially from the preliminary allocations and unaudited pro forma combined amounts included herein.

●

Merger Related Adjustments. Adjustments to reflect the reincorporation and merger of Yuma and Davis into Yuma Delaware or a direct subsidiary thereof.

             The unaudited pro forma condensed consolidated combined balance sheet of Yuma Delaware is based on (i) the unaudited historical consolidated balance sheet of Yuma as of September 30, 2016; and (ii) the unaudited historical consolidated balance sheet of Davis as of September 30, 2016, and includes pro forma adjustments to give effect to the Purchase Accounting Adjustments and Merger Related Adjustments as if they had occurred on September 30, 2016.

The unaudited pro forma condensed consolidated combined statements of operations of Yuma Delaware are based on the audited historical consolidated statements of operations of both Yuma and Davis for the twelve months ended December 31, 2015, and the unaudited historical consolidated statements of operations of both Yuma and Davis for the nine months ended September 30, 2016, having given effect to the Purchase Accounting Adjustments and Merger Related Adjustments as if they had occurred on January 1, 2015.

1

The unaudited pro forma data presented herein reflects events directly attributable to the described transactions and certain assumptions which management believes are reasonable. Such pro forma data is not necessarily indicative of financial results that would have been attained had the described transactions occurred on the dates indicated above, or the results of the combined company that may be achieved in the future. The adjustments are based on currently available information and certain estimates and assumptions. Therefore, the actual results may differ from the pro forma results indicated herein. However, management believes that the assumptions provide a reasonable basis for presenting the significant effects of the transactions as contemplated and that the pro forma adjustments give appropriate effect to those assumptions and are properly applied in the unaudited pro forma condensed consolidated combined financial statements.

The unaudited pro forma condensed consolidated combined financial statements are provided for illustrative purposes only and are not intended to represent or be indicative of the consolidated results of operations or consolidated financial position of Yuma Delaware that would have been recorded had the Merger been completed as of the dates presented, and they should not be taken as representative of the expected future results of operations or financial position of Yuma Delaware. The unaudited pro forma condensed consolidated combined financial statements do not reflect the impacts of any potential operational efficiencies, asset dispositions, cost savings or economies of scale that Yuma Delaware may achieve with respect to the operations of the combined company, except to reflect the reduction in general and administrative expenses related to the termination of certain employees that have been terminated or for which termination has been clearly communicated and whose termination is directly attributable to the Merger. Additionally, the unaudited pro forma statements of operations do not include non-recurring charges or credits, and the related tax effects, which result directly from the Merger.

The unaudited pro forma condensed consolidated combined financial statements have been derived from, and should be read in conjunction with, the historical consolidated financial statements and accompanying notes of both Davis and Yuma Energy, Inc., as included in the Current Report on Form 8-K/A filed with the Securities and Exchange Commission on January 9, 2017.

2

Yuma Delaware

Unaudited Pro Forma Condensed Consolidated Combined Balance Sheet

As of September 30, 2016

			Purchase	Merger
	Yuma	Davis	Accounting	Related		Pro Forma
($ in thousands)	Historical	Historical	Adjustments	Adjustments		Combined
			(a)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$1,832	$3,169	$-	$(2,709)	(b)	$2,292
Accounts receivable, net of allowance for doubtful accounts	3,347	1,515	-	-		4,862
Commodity derivative instruments	1,017	230	-	-		1,247
Prepayments	321	25	-	-		346
Other current assets	30	804	-	-		834
Total current assets	6,547	5,743	-	(2,709)		9,581
OIL AND GAS PROPERTIES (full cost method):
Oil and gas properties	220,668	437,139	(163,856)	-		493,951
Less: accumulated depreciation, depletion and amortization	(134,312)	(404,553)	134,312	-		(404,553)
Net oil and gas properties	86,356	32,586	(29,544)	-		89,398
OTHER PROPERTY AND EQUIPMENT:
Land, buildings and improvements	2,795	6,203	-	-		8,998
Other property and equipment	3,498	2,832	(1,420)	-		4,910
	6,293	9,035	(1,420)	-		13,908
Less: accumulated depreciation and amortization	(2,361)	(7,711)	2,361	-		(7,711)
Net other property and equipment	3,932	1,324	941	-		6,197
OTHER ASSETS AND DEFERRED CHARGES:
Commodity derivative instruments	178	-	-	-		178
Deposits	414	-	-	-		414
Deferred taxes	-	1,419	-	-		1,419
Other noncurrent assets	-	53	-	-		53
Total other assets and deferred charges	592	1,472	-	-		2,064
TOTAL ASSETS	$97,427	$41,125	$(28,603)	$(2,709)		$107,240
LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Current maturities of debt	$29,800	$9,000	$-	$(29,800)	(c)	$-
	-	-	-	(9,000)	(d)
Accounts payable, principally trade	6,379	2,111	-	-		8,490
Commodity derivative instruments	74	-	-	-		74
Asset retirement obligations	244	696	-	-		940
Other accrued liabilities	2,594	353	-	-		2,947
Total current liabilities	39,091	12,160	-	(38,800)		12,451
LONG-TERM DEBT:
Bank debt	-	-	-	29,800	(c)	39,500
	-	-	-	9,000	(d)
	-	-	-	700	(b)
OTHER NONCURRENT LIABILITIES:
Asset retirement obligations	8,572	4,873	-	-		13,445
Commodity derivative instruments	4	-				4
Deferred taxes	145	-	(145)	-		-
Other liabilities	7	-	-	-		7
Total other noncurrent liabilities	8,728	4,873	(145)	-		13,456
EQUITY:
Preferred stock	10,829	352	(10,829)	(352)	(e)	-
Series D convertible preferred stock	-	-	-	2	(e)	2
Common stock	142,725	2,241	(142,725)	(2,241)	(f)	12,201
	-	-	-	12,201	(f)
Treasury stock	-	(41,759)	-	41,759	(f)	-
Accumulated deficit	(103,946)	(148,366)	103,946	148,366	(f)	(3,409)
	-	-	-	(3,409)	(b)
Additional paid-in capital	-	211,624	21,150	(211,624)	(f)	33,039
	-	-	-	11,539	(f)
	-	-	-	350	(e)
Total equity	49,608	24,092	(28,458)	(3,409)		41,833
TOTAL LIABILITIES AND EQUITY	$97,427	$41,125	$(28,603)	$(2,709)		$107,240

The accompanying notes are an integral part of these unaudited pro forma condensed consolidated combined financial statements.

3

Yuma Delaware

Unaudited Pro Forma Condensed Consolidated Combined Statement of Operations

For the Nine Months Ended September 30, 2016

			Purchase		Merger
	Yuma	Davis	Accounting		Related		Pro Forma
(In thousands, except per share amounts)	Historical	Historical	Adjustments		Adjustments		Combined
REVENUES:
Sales of gas and oil	$9,208	$8,611	$-		$-		$17,819
Net gains (losses) from commodity derivatives	(408)	-	-		(161)	(g)	(569)
Total revenues	8,800	8,611	-		(161)		17,250
EXPENSES:
Marketing cost of sales	-	-	-		-		-
Lease operating expenses	5,692	3,270	-		-		8,962
Re-engineering and workovers	133	-	-		-		133
General and administrative – stock-based compensation	909	1,665	-		-		2,574
General and administrative – other	5,743	8,295	-		(1,876)	(h)	12,162
Depreciation, depletion and amortization	6,178	5,356	(1,497)	(i)	-		10,037
Asset retirement obligation accretion expense	318	159	-		-		477
Goodwill impairment	-	-	-		-		-
Impairment of oil and gas properties	11,016	17,561	-		-		28,577
(Gain) Loss on derivative instruments	-	161	-		(161)	(g)	-
Other	(10)	(35)	-		-		(45)
Total expenses	29,979	36,432	(1,497)		(2,037)		62,877
INCOME (LOSS) FROM OPERATIONS	(21,179)	(27,821)	1,497		1,876		(45,627)
OTHER INCOME (EXPENSE):
Interest expense	(974)	(195)	-		(13)	(j)	(1,182)
Other income, net	17	15	-		-		32
Total other income (expense), net	(957)	(180)	-		(13)		(1,150)
NET INCOME (LOSS) BEFORE INCOME TAXES	(22,136)	(28,001)	1,497		1,863		(46,778)
INCOME TAX (EXPENSE) BENEFIT	1,273	(7)	(1,273)	(k)	-		(7)
NET INCOME (LOSS)	$(20,863)	$(28,008)	$224		$1,863		$(46,785)
PREFERRED STOCK, SERIES A AND SERIES B:
Dividends paid in cash, perpetual preferred Series A	-	-	-		-		$-
Dividends in arrears, perpetual preferred Series A	962	-	-		(962)	(l)	-
Accretion, Series A and Series B	-	-	-		-		-
Dividends paid in cash, Series A and Series B	-	-	-		-		-
Dividends paid in kind, Series A and Series B	-	-	-		-		-
Dividends paid in kind, cumulative preferred Series D	-	-	-		1,020	(m)	1,020
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCKHOLDERS	$(21,825)	$(28,008)	$224		$1,805		$(47,805)
LOSS PER COMMON SHARE:
Basic	$(6.04)	$(0.19)	-		-		$(3.92)
Diluted	$(6.04)	$(0.19)	-		-		$(3.92)
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING
Basic	3,611	150,103	-		-		12,201
Diluted	3,611	150,103	-		-		12,201

The accompanying notes are an integral part of these unaudited pro forma condensed consolidated combined financial statements.

4

Yuma Delaware

Unaudited Pro Forma Condensed Consolidated Combined Statement of Operations

For the Twelve Months Ended December 31, 2015

			Purchase		Merger
	Yuma	Davis	Accounting		Related		Pro Forma
(In thousands, except per share amounts)	Historical	Historical	Adjustments		Adjustments		Combined
REVENUES:
Sales of gas and oil	$18,681	$18,774	$-		$-		$37,455
Net gains from commodity derivatives	5,039	-	-		3,319	(g)	8,358
Total revenues	23,720	18,774	-		3,319		45,813
EXPENSES:
Marketing cost of sales	533	-	-		-		533
Lease operating expenses	11,401	7,616	-		-		19,017
Re-engineering and workovers	556	-	-		-		556
General and administrative – stock-based compensation	2,289	933	-		-		3,222
General and administrative – other	7,434	6,875			(4,177)	(h)	10,132
Depreciation, depletion and amortization	13,651	17,139	(9,090)	(i)	-		21,700
Asset retirement obligation accretion expense	605	176	-		-		781
Goodwill impairment	4,928	-	-		-		4,928
Impairment of oil and gas properties	-	40,480	-		-		40,480
(Gain) on derivative instruments	-	(3,319)	-		3,319	(g)	-
Other	468	174	-		-		642
Total expenses	41,865	70,074	(9,090)		(858)		101,991
INCOME (LOSS) FROM OPERATIONS	(18,145)	(51,300)	9,090		4,177		(56,178)
OTHER INCOME (EXPENSE):
Interest expense	(456)	(578)	-		(26)	(j)	(1,060)
Other income, net	36	21	-		-		57
Total other income (expense), net	(420)	(557)	-		(26)		(1,003)
NET INCOME (LOSS) BEFORE INCOME TAXES	(18,565)	(51,857)	9,090		4,151		(57,182)
INCOME TAX (EXPENSE) BENEFIT	3,726	(10,461)	(5,402)	(k)	-		(12,137)
NET INCOME (LOSS)	$(14,839)	$(62,318)	$3,688		$4,151		$(69,318)
PREFERRED STOCK, SERIES A AND SERIES B:
Dividends paid in cash, perpetual preferred Series A	1,047	-	-		(1,047)	(l)	-
Dividends in arrears, perpetual preferred Series A	214	-	-		(214)	(l)	-
Accretion, Series A and Series B	-	-	-		-		-
Dividends paid in cash, Series A and Series B	-	-	-		-		-
Dividends paid in kind, Series A and Series B	-	-	-		-		-
Dividends paid in kind, cumulative preferred Series D	-	-	-		1,360	(m)	1,360
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCKHOLDERS	$(16,100)	$(62,318)	$3,688		$4,052		$(70,678)
LOSS PER COMMON SHARE:
Basic	$(0.23)	$(0.42)	-		-		$(5.79)
Diluted	$(0.23)	$(0.42)	-		-		$(5.79)
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING
Basic	71,014	149,182	-		-		12,201
Diluted	71,014	149,182	-		-		12,201

The accompanying notes are an integral part of these unaudited pro forma condensed consolidated combined financial statements.

5

Notes to the Unaudited Pro Forma Condensed Consolidated Combined Financial Statements

1. Basis of Presentation

The unaudited pro forma condensed consolidated combined balance sheet as of September 30, 2016 is based on the unaudited consolidated balance sheets of both Yuma and Davis as adjusted to reflect the following items as though they had occurred on September 30, 2016:

●

The application of preliminary purchase accounting adjustments based on values assigned to the Yuma assets to be acquired and liabilities to be assumed;

●

The implementation of a one-for-twenty reverse stock split in which each share of Yuma Common Stock, no par value per share, was converted into one-twentieth of one share of Yuma Delaware Common Stock, $0.001 par value per share;

●

The conversion of each share of Yuma Series A Preferred Stock, no par value per share, into 1.75 shares of Yuma Delaware Common Stock, which includes any accrued and unpaid dividends on the Yuma Series A Preferred Stock as of the consummation of the Merger;

●

The issuance of 7.46 million shares of Yuma Delaware Common Stock to former holders of Davis common stock, which results in approximately 61.1% of Yuma Delaware Common Stock being owned by former holders of Davis common stock; and

●

The issuance of approximately 1.75 million shares of a Series D Preferred Stock of Yuma Delaware to former Davis preferred stockholders.

The unaudited pro forma condensed consolidated combined statement of operations for the twelve months ended December 31, 2015 is based on Yuma’s and Davis’ respective audited consolidated statement of operations for such period, with adjustments made to recast such historical operations as if the Merger had occurred on January 1, 2015. The unaudited pro forma condensed consolidated combined statement of operations for the nine months ended September 30, 2016 is based on Yuma’s and Davis’ respective unaudited consolidated statement of operations for such period, with adjustments made to recast such historical operations as if the Merger had occurred on January 1, 2015.

The unaudited pro forma condensed consolidated combined financial statements are presented under the full cost method of accounting. Under this method, exploration activities and the cost of unsuccessful exploratory wells are capitalized. The full cost method also requires that the capitalized costs of successful and unsuccessful exploratory and developmental wells plus the estimated future development costs on a single cost center basis per country be amortized on a unit-of-production basis against total proved reserves.

2. Pro Forma Adjustments

The following adjustments were made in the preparation of the unaudited pro forma condensed consolidated combined balance sheet and unaudited pro forma condensed consolidated combined statement of operations:

(a)

Adjustments to reflect the elimination of Yuma’s total equity, the estimated value of consideration to be paid in the Merger and to adjust, where required, the historical book values of Yuma’s assets and liabilities as of September 30, 2016 to their estimated fair value, in accordance with the acquisition method of accounting.

The estimated fair value of the consideration to be transferred, assets acquired, and liabilities assumed are described below (in thousands):

6

Purchase Consideration
Common stock (1)	$20,883
Stock appreciation rights (2)	85
Stock options (3)	1
Restricted stock awards (4)	181
Restricted stock units (5)	-
Debt (6)	29,800
Total preliminary estimated purchase price	$50,950
Less debt assumed	(29,800)
Net purchase consideration to be allocated	$21,150
Estimated Fair Value of Assets Acquired(7)
Cash	1,832
Other current assets	4,715
Proved natural gas and oil properties(8)	56,212
Unproved natural gas and oil properties(8)	600
Other noncurrent assets	5,465
Total assets acquired	$68,824
Estimated Fair Value of Liabilities Assumed
Current maturities of debt	29,800
Current asset retirement obligation	244
Other current liabilities	9,047
Long-term debt	-
Noncurrent asset retirement obligation	8,572
Other	11
Total liabilities assumed	$47,674
Total net assets acquired	$21,150

(1)

4,746,179 shares of Yuma Common Stock were effectively transferred in connection with the Merger. Those shares were valued at $4.40 per share, which was the last sales price of Yuma Common Stock at October 26, 2016. The October 26, 2016 share price used is the same date as the October 26, 2016 NYMEX strip price applied in Yuma’s most recent engineering reports.

(2)

Yuma’s stock appreciation rights were valued using the binomial lattice model.

(3)

Yuma’s 5,000 stock options were valued at approximately $0.013 per option using the Black-Scholes model.

(4)

18,014 restricted stock awards vested in 2016 and the 78,336 restricted stock awards vesting in 2017 and 2018 were valued at the share price as of October 26, 2016.

(5)

Yuma had no restricted stock units outstanding as of October 26, 2016.

(6)

Debt fair value approximates the related book value at September 30, 2016, as shown on Yuma’s consolidated balance sheet.

(7)

Includes a $6.3 million deferred tax liability and a $20.6 million deferred tax asset, with an offsetting $14.3 million valuation allowance.

(8)

A step-down in basis of Yuma’s natural gas and oil properties was made, even with Yuma’s natural gas and oil properties being impaired as of September 30, 2016 due to the differences in the methodology for an impairment test and the methodology for determining the fair value of net assets acquired. For example, the methodology for an impairment test uses a different discount rate than that used in determining fair value.

(b)

Adjustments to reflect approximately $3.41 million in severance costs and legal and advisory fees directly related to the Merger that were not reflected in the historical financial statements.

(c)

Adjustments to reflect the reclassification of Yuma’s current maturities of debt to long-term debt. On a pro forma combined basis, Yuma Delaware was in compliance with all debt covenants as of the closing of the Merger.

(d)

Adjustments to reflect the extinguishment of Davis’ existing current maturities of debt in connection with Yuma Delaware’s entry into its new long-term credit facility. The new credit facility replaces Yuma’s existing credit agreement and has an initial borrowing base of $44.0 million.

(e)

Adjustment to reflect the issuance of approximately 1.75 million shares of Series D Preferred Stock to former Davis preferred stockholders. The fair value of the Series D Preferred Stock is expected to approximate the carrying value of Davis’ preferred stock as of September 30, 2016.

(f)

Adjustments to reflect the recapitalization of Yuma upon closing of the Merger, after which approximately 12.2 million shares of Yuma Delaware Common Stock were outstanding. In accordance with the acquisition method of accounting, Davis’ existing common stock, treasury stock, accumulated deficit and additional paid-in capital, less the par value of the Yuma Delaware Common Stock received ($0.001 par value per share), will be reclassified to additional paid-in capital of Yuma Delaware.

(g)

Adjustments to conform the historical financial statement presentation of net gains and losses from commodity derivatives.

(h)

Adjustments to reflect the reduction in general and administrative expenses related to the termination of certain employees, as if the Merger had occurred on January 1, 2015. The reduction related to the termination of certain employees includes only those employees that have been terminated or for which termination has been clearly communicated and whose termination is directly attributable to the transaction.

(i)

Adjustments to reflect the calculation of Yuma Delaware depreciation, depletion, and amortization, as if the Merger had occurred on January 1, 2015. The calculations of Yuma Delaware depreciation, depletion and amortization expense for the nine months ended September 30, 2016 and for the twelve months ended December 31, 2015 are included below (in thousands):

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Yuma Delaware Depreciation, Depletion and Amortization for the Nine Months Ended September 30, 2016:
Yuma amortization base (1)	$125,166
Davis amortization base	75,731
Pro forma DD&A recorded for the year ended 12/31/2015 Yuma Delaware amortization base	(21,700) 179,197
Multiplied by: DD&A rate (2)	0.05601
Yuma Delaware 9/30/2016 DD&A	$10,037
(1) Yuma amortization base is the fair value of Yuma’s oil and natural gas properties subject to amortization plus Yuma’s future development costs as of September 30, 2016.
(2) Yuma Delaware combined net production as of September 30, 2016 (Boe)	828,711	=	0.05601
Divided by: Yuma Delaware combined September 30, 2016 total proved reserves	14,794,944

Yuma Delaware Depreciation, Depletion and Amortization for the Twelve Months Ended December 31, 2015:
Yuma amortization base (1)	$173,776
Davis amortization base	125,812
Yuma Delaware amortization base	299,588
Multiplied by: DD&A rate (2)	0.07243
Yuma Delaware 12/31/2015 DD&A	$21,700
(1) Yuma amortization base is the fair value of Yuma’s oil and natural gas properties subject to amortization plus Yuma’s future development costs as of December 31, 2015.
(2) Yuma Delaware combined net 2015 production (Boe)	1,409,039	=	0.07243
Divided by: Yuma Delaware combined January 1, 2015 total proved reserves	19,452,630

(j)

Adjustments to reflect the interest expense associated with the $0.70 million in debt assumed in (b), as if the Merger had occurred on January 1, 2015. An interest rate of 3.75% was assumed on the debt. If the interest rate changed by 1/8%, pro forma interest expense would change by $49,375 on an annual basis and $12,344 on a quarterly basis.

(k)

Adjustments to reflect the change in the income tax expense or benefit for the period presented, as if the Merger had occurred on January 1, 2015.

(l)

Adjustments to reflect the conversion of Series A Preferred Stock to shares of Yuma Delaware common stock, as if the Merger had occurred on January 1, 2015.

(m)

Adjustment to reflect estimated dividends related to the Series D Preferred Stock that would have been paid in-kind to preferred shareholders, as if the Merger had occurred on January 1, 2015.

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 3. Unaudited Pro Forma Supplemental Disclosure of Oil and Natural Gas Operations

The following pro forma standardized measure of the discounted net future cash flows and changes applicable to the combined company’s proved reserves reflect the effect of income taxes.

The pro forma standardized measure of discounted future net cash flows, in management’s opinion, should be reviewed with caution. The basis for this table is the reserve studies prepared by the Yuma’s and Davis’ independent petroleum engineering consultants, and such reserve estimates contain imprecise estimates of quantities and rates of production of reserves. Revisions of previous year estimates can have a significant impact on these results. Also, exploration costs in one year may lead to significant discoveries in later years and may significantly change previous estimates of proved reserves and their valuation. Therefore, the pro forma standardized measure of discounted future net cash flow is not necessarily indicative of the fair value of the combined company’s proved oil and natural gas properties.

The data presented below should not be viewed as representing the expected future cash flows from, or the current value of, existing proved reserves since the computations are based on estimates and assumptions. Reserve quantities cannot be measured with precision and their estimation requires many judgmental determinations and frequent revisions. Actual future prices and costs are likely to be substantially different from the prices and costs utilized in the computation of reported amounts.

The following table provides a pro forma rollforward of the total proved reserves for the twelve months ended December 31, 2015, as well as pro forma proved developed and proved undeveloped reserves at the beginning and end of 2015, as if the Merger had occurred on January 1, 2015 (in Boe).

	Yuma Historical December 31, 2015
	Oil (Bbls)	Natural Gas Liquids (Bbls)	Natural Gas (Mcf)	Total (Boe)
Proved reserves:
Balance, beginning of year	11,532,185	2,479,158	35,259,522	19,887,930
Revisions of previous estimates	(5,095,277)	(501,101)	(11,436,325)	(7,502,432)
Purchases of oil and gas properties and minerals in place	95,362	8,025	264,981	147,551
Extensions and discoveries	630,573	139,088	3,675,358	1,382,221
Sale of oil and gas properties and minerals in place	0	0	0	0
Production	(247,177)	(74,511)	(1,993,842)	(653,995)
Balance, end of year	6,915,666	2,050,659	25,769,694	13,261,274
Proved developed reserves:
Balance, beginning of year	2,034,950	312,532	7,786,537	3,645,238
Balance, end of year	1,801,624	315,935	8,552,249	3,542,934
Proved undeveloped reserves:
Balance, beginning of year	9,497,235	2,166,626	27,472,985	16,242,692
Balance, end of year	5,114,042	1,734,724	17,217,445	9,718,340

Yuma’s revisions in 2015 to previously estimated reserves for crude oil, natural gas liquids and natural gas were primarily caused by (i) commodity price reductions of 6,771,739 Mcf of natural gas, 753,922 Bbl of natural gas liquids, and 2,673,927 Bbl of oil causing wells to reach their economic limits sooner and causing some proved undeveloped locations to become uneconomic; (ii) upward revisions of 2,337,685 Mcf of natural gas, 877,061 Bbl of natural gas liquids, and 250,071 Bbl of oil primarily associated with increased performance of Bayou Hebert (La Posada) field; and (iii) reclassifying PUD reserves of 7,002,271 Mcf, 624,582 Bbl of natural gas liquids, and 2,671,079 Bbl of oil to probable reserves primarily in Yuma’s Greater Masters Creek Area due to the current economic conditions and uncertainty in future development plans.

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	Davis Historical December 31, 2015
	Crude oil (Bbls)	Natural Gas Liquids (Bbls)	Natural Gas (Mcf)	Total (Boe)
Proved reserves:
Balance, beginning of year	1,995,900	717,400	12,650,500	4,821,700
Revisions of previous estimates	(871,200)	14,100	3,711,100	(238,600)
Purchases of oil and gas properties and minerals in place	12,800	25,100	516,600	124,000
Extensions and discoveries	261,200	403,600	2,132,100	1,020,200
Sale of oil and gas properties and minerals in place	(21,300)	(2,300)	(945,100)	(181,100)
Production	(209,500)	(129,700)	(2,547,300)	(763,800)
Balance, end of year	1,167,900	1,028,200	15,517,900	4,782,400
Proved developed reserves:
Balance, beginning of year	1,084,900	579,400	11,901,600	3,647,900
Balance, end of year	703,400	604,300	10,464,300	3,051,700
Proved undeveloped reserves:
Balance, beginning of year	911,000	138,000	748,900	1,173,800
Balance, end of year	464,500	423,900	5,053,600	1,730,700

From January 1, 2015 to December 31, 2015 Davis proved reserves decreased by 39,300 Boe, a change of less than 1%. Davis had 763,800 Boe of production during the year. Extensions of discoveries resulting from successful drilling in the Chalktown field added 1,020,200 Boe of PUD reserves. Partially offsetting the Chalktown extensions were downward revisions of 464,306 Boe in proved reserves from a pilot downspaced drilling program that did not perform as well as expected. In the second half of 2015, Davis’ technical work focused on the high-valued Lac Blanc and high-potential Cameron Canal fields. Davis’ geological, geophysical and reservoir engineering reinterpretations resulted in upward revisions of 555,761 Boe of proved developed reserves at the Lac Blanc field and 538,521 Boe of proved undeveloped reserves at the Cameron Canal field. Commodity price reductions resulted in a downward revision to PUD reserves of 827,107 Boe as uneconomic undeveloped locations in the El Halcón field were dropped from PUD reserves. Low prices also resulted in a downward revision of 170,179 Boe of proved developed reserves due to wells in the Vinceburg field in Galveston Bay reaching their economic limit. These revisions, together with other insignificant revisions adding approximately 128,600 Boe of proved reserves, resulted in a total net reduction in proved reserves of 238,600 Boe. The purchase of a partner’s interests in the Lac Blanc field added 124,000 Boe of proved developed reserves, and sales of minor assets at Kings Bayou, Cat Spring and Eagle Bay reduced proved developed reserves by 181,117 Boe.

	Pro Forma Adjusted December 31, 2015
	Crude oil (Bbls)	Natural Gas Liquids (Bbls)	Natural Gas (Mcf)	Total (Boe)
Proved reserves:
Balance, beginning of year	13,528,085	3,196,558	47,910,022	24,709,630
Revisions of previous estimates	(5,966,477)	(487,001)	(7,725,225)	(7,741,032)
Purchases of oil and gas properties and minerals in place	108,162	33,125	781,581	271,551
Extensions and discoveries	891,773	542,688	5,807,458	2,402,421
Sale of oil and gas properties and minerals in place	(21,300)	(2,300)	(945,100)	(181,100)
Production	(456,677)	(204,211)	(4,541,142)	(1,417,795)
Balance, end of year	8,083,566	3,078,859	41,287,594	18,043,674
Proved developed reserves:
Balance, beginning of year	3,119,850	891,932	19,688,137	7,293,138
Balance, end of year	2,505,024	920,235	19,016,549	6,594,634
Proved undeveloped reserves:
Balance, beginning of year	10,408,235	2,304,626	28,221,885	17,416,492
Balance, end of year	5,578,542	2,158,624	22,271,045	11,449,040

10

The pro forma standardized measure of discounted estimated future net cash flows was as follows as of December 31, 2015:

	Yuma Historical	Davis Historical	Pro Forma Adjusted
Future cash inflows	$438,816,500	$112,449,000	$551,265,500
Future cash outflows:			-
Production cost	(129,636,500)	(38,404,000)	(168,040,500)
Development cost	(126,463,700)	(21,947,000)	(148,410,700)
Future income taxes	(22,664,783)	-	(22,664,783)
Future net cash flows	$160,051,517	$52,098,000	$212,149,517
Adjustment to discount future annual net cash flows at 10%	(53,506,567)	(11,118,000)	(64,624,567)
Standardized measure of discounted future net cash flows	$106,544,950	$40,980,000	$147,524,950

The changes in the pro forma standardized measure of discounted estimated future net cash flows were as follows for the twelve months ended December 31, 2015:

	Yuma Historical	Davis Historical	Pro Forma Adjusted
Standardized measure, beginning of period	$295,478,496	$101,671,000	$397,149,496
Sales of oil and gas, net of production cost	(7,069,544)	(10,769,000)	(17,838,544)
Extensions and discoveries	16,659,700	3,534,000	20,193,700
Purchases of oil and gas properties and reserves in place	2,268,907	1,062,000	3,330,907
Development costs incurred during the period that reduced future development costs	4,052,919	-	4,052,919
Prices and operating expenses	(373,314,797)	(66,321,000)	(439,635,797)
Income taxes	64,883,059	-	64,883,059
Estimated future development costs	245,056,050	15,322,000	260,378,050
Quantity estimates	(98,817,149)	(12,951,000)	(111,768,149)
Sale of reserves in place	-	(2,784,000)	(2,784,000)
Accretion of discount	37,672,481	10,167,000	47,839,481
Production rates, timing and other	(80,325,172)	2,049,000	(78,276,172)
Standardized measure, end of period	$106,544,950	$40,980,000	$147,524,950

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