Exhibit 99.4

DAVIS PETROLEUM ACQUISITION CORP.

CONSOLIDATED FINANCIAL STATEMENTS

DECEMBER 31, 2015 AND 2014

(With Independent Auditor’s Report Thereon)

Table of Contents

Independent Auditor’s Report	1
Consolidated Balance Sheets	2
Consolidated Income Statements	3
Consolidated Statements of Cash Flows	4
Consolidated Statements of Changes in Stockholders’ Equity	5
Notes to the Consolidated Financial Statements	6
Supplemental Oil and Gas Disclosures (unaudited)	25

Independent Auditor's Report

Tothe Board of Directors of

Davis Petroleum Acquisition Corp.:

We have audited the accompanying consolidated financial statements of Davis Petroleum Acquisition Corp. and its subsidiaries, which comprise the consolidated balance sheets as of December 31, 2015 and 2014, and the related consolidated statements of income, stockholders’ equity and cash flows for the years then ended.

Management's Responsibility for the Consolidated Financial Statements

Management is responsible for the preparation and fair presentation of the consolidated financial statements in accordance with accounting principles generally accepted in the United States of America; this includes the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of consolidatedfinancial statements that are free from material misstatement, whether due to fraud or error.

Auditor's Responsibility

Our responsibility is to express an opinion on the consolidated financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free from material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the consolidated financial statements. The procedures selected depend on our judgment, including the assessment of the risks of material misstatement of the consolidated financial statements, whether due to fraud or error. In making those risk assessments, we consider internal control relevant to the Company's preparation and fair presentation of the consolidated financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control. Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.

Opinion

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Davis Petroleum Acquisition Corp. and its subsidiaries at December 31, 2015 and 2014, and the results of their operations and their cash flows for the years then ended in accordance with accounting principles generally accepted in the United States of America.

Houston, Texas

April 5, 2016, except for the revision described in Note 20 and the effects thereof, as to which the date is January 17, 2017.

1

DAVIS PETROLEUM ACQUISITION CORP.

CONSOLIDATED BALANCE SHEETS

AS OF DECEMBER 31

	2015	2014
($ in thousands)
ASSETS
Current:
Cash	$4,064	$10,477
Accounts receivable	5,112	7,363
Joint interest advances paid	175	937
Derivative asset	1,711	8,098
Other current assets	877	7,457
Total current assets	11,939	34,332
Property, plant, and equipment:
Oil and gas properties - full cost method
Proved properties	425,767	408,799
Unevaluated properties	179	10,877
Other	9,034	9,034
Less: Accumulated depreciation, depletion, amortization and impairment	(389,345)	(331,727)
Total property, plant and equipment, net	45,635	96,983
Other assets	405	616
Long-term derivative asset	-	639
Deferred income taxes	1,426	11,881
TOTAL ASSETS	$59,405	$144,451
LIABILITIES
Current:
Accounts payable and accrued expenses	$3,936	$19,991
Oil and gas revenues and royalties payable	439	821
Joint interest advances received	475	598
Current portion of asset retirement obligations	185	1,822
Total current liabilities	5,035	23,232
Long-term debt	-	5,000
Asset retirement obligations	5,147	5,404
Other long-term liabilities	95	95
TOTAL LIABILITIES	10,277	33,731
Commitments and contingencies (Note 16)
STOCKHOLDERS' EQUITY
Common stock, par value $0.01 per share (authorized 400,100,000 shares; issued 223,584,069 and 223,523,434 as of December 31, 2015 and 2014, respectively)	2,236	2,235
Preferred stock, par value $0.01 per share (authorized 50,000,000 shares; issued 33,367,187 and 31,130,201 as of December 31, 2015 and 2014,	334	311
Treasury Stock, at cost; 72,111,216 and 71,622,528 shares at December 31, 2015 and 2014, respectively	(41,350)	(41,140)
Paid-in capital	207,284	205,144
Accumulated deficit	(119,376)	(55,830)
Total Stockholders' Equity	49,128	110,720
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY	$59,405	$144,451

See accompanying Notes to the Consolidated Financial Statements

2

DAVIS PETROLEUM ACQUISITION CORP.

CONSOLIDATED INCOME STATEMENTS

FOR THE YEARS ENDED DECEMBER 31

	2015	2014
($ in thousands)
REVENUES	$18,774	$58,694
EXPENSES
Lease operating and production costs	6,510	12,611
Production taxes	1,106	2,468
Depreciation, depletion and amortization	17,139	32,880
Impairment of oil and gas properties	40,480	-
General and administrative	7,807	9,938
Accretion expense	176	852
Other operating expenses	174	1,006
(Gain) on derivative instruments	(3,319)	(9,290)
Total expenses	70,073	50,465
INCOME (LOSS) FROM OPERATIONS	(51,299)	8,229
Other (income) and expense:
Interest and other income	(21)	(159)
Interest expense	578	1,226
Income (loss) before income taxes	(51,856)	7,162
Income tax expense (benefit) - current	6	(192)
Income tax expense - deferred	10,455	2,676
NET INCOME (LOSS)	$(62,317)	$4,678
Earnings Per Share
Basic	$(0.42)	$0.03
Diluted	$(0.42)	$0.03
Weighted Average Shares Outstanding (in thousands)
Basic	149,182	147,350
Diluted	149,182	177,178

See accompanying Notes to the Consolidated Financial Statements

3

DAVIS PETROLEUM ACQUISITION CORP.

CONSOLIDATED STATEMENTS OF CASH FLOWS

FOR THE YEARS ENDED DECEMBER 31

	2015	2014
($ in thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$(62,317)	$4,678
Adjustments to reconcile net income to net cash provided
operating activities:
Depreciation, depletion and amortization	17,139	32,880
Amortization of debt issuance costs	210	122
Impairment of oil and gas properties	40,480	-
Net deferred income tax expense	10,455	2,676
Stock-based compensation expense	933	1,712
Accretion expense	176	852
Derivative instruments	(3,318)	(9,290)
Working capital changes:
Decrease in accounts receivable	2,804	1,808
Decrease in other current and long-term assets	6,583	951
(Decrease) increase in accounts payable and other current and
non-current liabilities	(5,307)	2,740
Increase (decrease) in oil and gas revenues payable	(382)	(3,280)
Increase (decrease) in joint interest advances	3,620	(3,203)
Net cash provided by operating activities	11,076	32,646
CASH FLOWS FROM INVESTING ACTIVITIES:
Acquisitions	(1,401)	(1,541)
Capital expenditures	(22,932)	(27,420)
Proceeds from the sale of properties	1,710	33,484
Divestments	-	3,721
Derivative settlements	10,344	(1,264)
Net cash provided by (used in) investing activities	(12,279)	6,980
CASH FLOWS FROM FINANCING ACTIVITIES:
Repayments on Senior Credit Facility	(15,000)	(40,000)
Borrowings on Senior Credit Facility	10,000	5,000
Treasury stock repurchases	(210)	(699)
Net cash used in financing activities	(5,210)	(35,699)
Net (decrease) increase in cash	(6,413)	3,927
Cash - beginning of the period	10,477	6,550
Cash - end of the period	$4,064	$10,477

See accompanying Notes to the Consolidated Financial Statements

4

DAVIS PETROLEUM ACQUISITION CORP.

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

	Common Stock		Preferred Stock	Treasury Stock	Paid-in Capital	Accumulated Deficit	Stockholders' Equity
($ in thousands)	Shares	Value
December 31, 2013	222,976	$2,237	$290	$(40,441)	$201,636	$(59,356)	$104,366
Net income	-	-	-	-	-	4,678	4,678
Payment of dividends in kind	-	-	21	-	1,131	(1,152)	-
Restricted stock grants, net of cancelations	547	(2)	-	-	2	-	-
Treasury stock - employee tax payment	-	-	-	(699)	-	-	(699)
Amortization of stock-based compensation	-	-	-	-	2,375	-	2,375
December 31, 2014	223,523	$2,235	$311	$(41,140)	$205,144	$(55,830)	$110,720
Net income	-	-	-	-	-	(62,317)	(62,317)
Payment of dividends in kind	-	-	23	-	1,206	(1,229)	-
Restricted stock grants, net of cancelations	61	1	-	-	-	-	1
Treasury stock - employee tax payment	-	-	-	(210)	-	-	(210)
Amortization of stock-based compensation	-	-	-	-	934	-	934
December 31, 2015	223,584	$2,236	$334	$(41,350)	$207,284	$(119,376)	$49,128

See accompanying Notes to the Consolidated Financial Statements

5

DAVIS PETROLEUM ACQUISITION CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Organization and Nature of Business

Organization

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, Davis Petroleum Acquisition Corp. and its wholly-owned subsidiaries are collectively referred to as “Davis” or the “Company”.

Nature of Business

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.

2. Summary of Significant Accounting Policies

Principles of Consolidation and Reporting

The consolidated financial statements of the Company include the accounts of DPAC and its wholly-owned subsidiaries. The Company proportionately consolidates its interests in oil and gas joint ventures. All significant intercompany transactions have been eliminated in consolidation.

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.

Cash

Cash includes cash on hand and on deposit and the carrying value approximates market value.

Trade Accounts Receivable

Trade accounts receivable are recorded at the invoiced amount and do not bear interest. The Company uses the specific identification method of providing allowances for doubtful accounts. The Company does not have any off-balance-sheet credit exposure related to its customers. In the normal course of business, collateral is not required for financial instruments with credit risk.

6

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

Oil and Gas Properties

The Company accounts for its oil and gas producing activities using the full cost method of accounting as prescribed by the Securities and Exchange Commission (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. The Company capitalized $1.5 million and $2.1 million of internal costs in 2015 and 2014, respectively. 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 Interest

The Company capitalizes interest on capital invested in long-term projects that are under development. Upon commencement of production, capitalized interest, as a component of the total cost of the full cost pool, is depleted. Capitalized interest is calculated by multiplying the weighted-average interest rate on debt by the amount of costs excluded. There was no interest capitalized during the years ended December 31, 2015 and 2014.

Other Property, Plant, and Equipment

Other property, plant, and equipment is stated at the lower of cost or fair market value. Depreciation and amortization is calculated using the straight-line method over the estimated useful lives of the respective assets. The cost of normal maintenance and repairs is charged to operating expense as incurred. Material expenditures which extend the life of an asset are capitalized and depreciated over the estimated remaining useful life of the asset. The cost of other property, plant and equipment sold, or otherwise disposed of, and the related accumulated depreciation or amortization is removed from the accounts and any gains or losses are reflected in current operations.

In the event that facts and circumstances indicate that the carrying value of other plant, property and equipment may be impaired, an evaluation of recoverability is performed. If an evaluation is required, the estimated future undiscounted cash flows associated with the asset are compared to the asset’s carrying amount to determine if a write-down to market value (measured using discounted cash flows) is required.

Asset Retirement Obligations

The Company 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, the Company 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 the Company recognizes gains and losses on divested oil and gas properties. The ARO is based on a number of assumptions requiring judgment. The Company 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.

7

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

Debt Issuance Costs

Debt issuance costs reflect the expenditures incurred in connection with obtaining and renewing the Company’s senior credit facility. Such debt issuance costs are being amortized over the term of the credit facility to interest expense and had a carrying amount of $0 and $210.0 thousand at December 31, 2015 and 2014, respectively. Amortization expense during the year ended December 31, 2015 and 2014 was $210.0 and $122.1 thousand, respectively.

Revenue Recognition

The Company recognizes oil and gas sales upon delivery to the purchaser (“sales method”). Under the sales method, the Company and other joint owners may sell more or less than their entitled share of the natural gas volume produced. Should the Company’s sales of natural gas exceed its share of estimated remaining recoverable reserves, a liability is recorded by the Company and revenue is deferred. At December 31, 2015 and 2014, there were no material imbalance positions.

The Company records its share of revenues when collection is reasonably assured based on the volumes sold using contracted sales prices. Sales prices for natural gas and crude oil are adjusted for transportation costs and other related deductions. The transportation costs and other deductions are based on contractual or historical data and do not require significant judgment. Subsequently, these deductions and transportation costs are adjusted to reflect actual charges based on third party documents. Historically, these adjustments have been insignificant. Since there is a ready market for natural gas and crude oil, the Company sells the majority of its products soon after production at various locations where title and risk of loss pass to the buyer.

Joint Interest Advances

The Company periodically requires other joint interest owners and is sometimes required by other joint interest owners to prepay expected future expenditures generally related to drilling and completion activities (joint interest advances). When cash is received from other joint interest owners prior to costs being incurred, the Company records a liability. When cash is paid to other joint interest owners prior to costs being incurred, the Company records an asset.

Royalty Payable

Royalty liabilities are recorded in the period in which the natural gas and crude oil are produced and such amounts are included in Oil and Gas Revenues and Royalties Payable on the Company’s Consolidated Balance Sheet.

Commodity Hedging Contracts and Other Derivatives

The Company 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. The Company does not designate its derivative contracts as hedges, as defined in ASC 815, Derivatives and Hedging, and accordingly recognizes changes in the fair value of the derivatives currently in earnings (see Note 7 – Commodity Hedging Contracts and Other Derivatives).

8

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

Income Taxes

Income taxes are provided based on earnings reported for tax return purposes in addition to a provision for deferred income 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.

Stock-Based Compensation

The Company has a stock-based employee compensation plan which is described more fully in Note 14 – Stockholders’ Equity. The Company uses the grant date fair value based method of accounting for stock-based compensation. The Company recognizes compensation cost using the straight line method over the requisite service period for the entire award for its stock options and over the requisite service period for each separately vesting portion of restricted stock awards, as appropriate.

Treasury Stock

The Company records treasury stock purchases at cost. Amounts are recorded as reductions to stockholders’ equity. Shares of common stock are repurchased by the Company as they are surrendered by employees to pay withholding tax upon the vesting of restricted stock awards.

Environmental Costs

Environmental expenditures are expensed or capitalized, as appropriate, depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations and that do not have future economic benefit are expensed. Liabilities related to future costs are recorded on an undiscounted basis when environmental assessments and/or remediation activities are probable and the costs can be reasonably estimated.

New Accounting Requirements

In November 2015, the Financial Accounting Standards Board (FASB) issued guidance regarding the presentation of deferred income taxes in the balance sheet which requires that within a particular jurisdiction, deferred tax liabilities and assets, as well as any related valuation allowance, be offset and classified as a single noncurrent amount. The guidance is required for interim and annual periods beginning after December 15, 2016. However, early adoption is available and we have implemented this guidance at December 31, 2015.

In April 2015, the FASB issued guidance regarding the presentation of debt issuance costs in the financial statements which requires that debt issuance costs be presented as a reduction of the carrying value of the financial liability and not as a separate asset. The guidance requires retrospective adjustment to the balance sheet presentation and disclosures applicable for a change in an accounting principle. The guidance is effective for interim and annual periods beginning after December 15, 2015. We will adopt this guidance in the first quarter of 2016.

9

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

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 beginning on or after December 15, 2016. We will adopt this guidance in the first quarter of 2017.

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 interim and annual periods beginning on or after December 15, 2017. We are currently evaluating the impact of this guidance on our financial statements.

3. Accounts Receivable

At December 31, accounts receivable consisted of the following:

	2015	2014
($ in thousands)
Natural gas and crude oil sales	$4,286	$6,527
Joint interest billings	826	836
Accounts receivable	$5,112	$7,363

4. Other Current Assets

At December 31, other current assets consisted of the following:

	2015	2014
($ in thousands)
Prepaid insurance	$153	$261
ARO receivable	-	7,196
Other	724	-
Total other current assets	$877	$7,457

In February 2015, the Company and one of its former partners completed the arbitration proceeding for a breach of contract claim under the Clipper Operating Agreement (‘Clipper’) against another former partner who withdrew from Clipper but was contractually obligated to fund a portion of the estimated future ARO expenditures relative to Clipper.

Davis claimed an award in the amount of $9,868 thousand. The Arbitrator’s decision (the ‘Award’) was received on April 1, 2015 and awarded Davis $7,196 thousand. The final ruling was received on July 28, 2015 and the settlement of $7,196 thousand plus interest of $112 thousand was received in August 2015.

The ARO receivable was reduced as a result of the Award, with the corresponding increase to the Company’s full cost pool.

10

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

5. Acquisitions and Divestments

Acquisitions

Effective August 1, 2015, the Company purchased an additional working interest in their Lac Blanc field for $1,401 thousand.

Divestments

During 2015, the Company sold its interests in the following fields:

●

Cat Spring - net proceeds of $74,640

●

Carter Estate #1 – net proceeds of $867,500

●

Overriding Royalty Interests (various) – net proceeds of $768,000

Pursuant to full cost accounting rules, no gain or loss was recognized on these sales.

During 2014, the Company sold its interest in Davis Offshore for $33,484 thousand. No gain or loss was recognized on this sale.

6. 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 December 31:

	2015	2014
($ in thousands)
Proved properties	$425,767	$408,799
Less: accumulated depreciation, depletion, amortization and impairment	(381,988)	(324,960)
Proved properties, net	43,779	83,839
Unproved properties
Leasehold acquisition costs	-	4,596
Exploration and development	-	116
Unevaluated properties	179	6,165
Total unproved properties	179	10,877
Oil and gas properties, net	$43,958	$94,716

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. In 2015 the Company recorded a $40.5 million ceiling test write-down. There were no ceiling test limit write-downs required during 2014.

11

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

Costs Not Being Amortized

Costs not being amortized are transferred to the Company’s full cost pool as its drilling program is executed or costs are evaluated and deemed impaired. The Company anticipates that these unevaluated costs will be included in the depletion computation over the next two years. The Company is unable to predict the future impact on depletion rates. A summary of the Company’s unevaluated properties by year incurred follows:

December 31, 2015	Year Incurred
($ in thousands)	2015	2014	2013 & Prior	Total
Unevaluated reserves	$179	$-	$-	$179
Total unevaluated properties, at December 31, 2015	$179	$-	$-	$179

Other

Other property and equipment consists of the following:

	Useful	December 31,
	life (years)	2015	2014
($ 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		(7,357)	(6,767)
Other property and equipment, net		$1,677	$2,267

7. Commodity Hedging Contracts and Other Derivatives

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.

12

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

As of December 31, 2015, the Company had the following outstanding commodity derivative contracts, all of which settle monthly:

Period	Instrument Type	Average Daily Volumes	Average Fixed Price
2016	Natural Gas Swap	3,000 MMBtu	$4.05

Balance Sheet

At December 31, 2015 and 2014, the Company had the following outstanding commodity derivative contracts recorded in its consolidated balance sheets ($ in thousands):

		Estimated Fair Value
		Year Ended December 31,
Instrument Type	Balance Sheet Classification	2015	2014
Natural Gas/Crude Oil Swaps/Collars	Derivative asset - short-term	$1,711	$8,098
Natural Gas/Crude Oil Swaps/Collars	Derivative asset - long-term	-	639
Total derivative instruments		$1,711	$8,737

8. 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.

13

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

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 December 31, 2015:

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

	Recurring Fair Value Measures
	As of December 31, 2014
($ in thousands)	Level 1	Level 2	Level 3
Natural Gas Swaps	$-	$3,195	$-
Crude Oil Swaps	-	5,542	-
Total	$-	$8,737	$-

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.

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. There were no borrowings as of December 31, 2015.

14

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

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.

9. Accounts Payable and Accrued Expenses

Accounts payable and accrued expenses consisted of the following at December 31:

	2015	2014
($ in thousands)
Trade payables	$669	$3,639
Accrued expenses	3,267	16,352
Total accounts payable	$3,936	$19,991

10. Income Taxes

The provision for income taxes for the years ending December 31 follows:

	2015	2014
($ in thousands)
Current Expense (Benefit)
Federal	$-	$4
State	6	(196)
Deferred Expense (Benefit)
Federal	11,060	2,585
State	(605)	91
Total provision	$10,461	$2,484

15

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

A reconciliation of the federal statutory income tax rate to the effective income tax rate for the years ended December 31 follows:

	2015	2014
U.S. statutory rate	35.00%	35.00%
Valuation allowance	-56.32%	0.00%
State return to provision (net of federal benefit)	0.00%	-2.97%
State income taxes (net of federal benefit)	1.16%	2.48%
Other	-0.01%	0.19%
Effective rate	-20.17%	34.70%

Deferred income tax (liabilities) assets at December 31 follows:

($ in thousands)	2015	2014
Deferred income tax liabilities
Property, plant and equipment	$-	$7,014
Financial accruals and other	566	3,020
	566	10,034
Deferred income tax assets
Net operating loss carryforward	(21,523)	(20,237)
Property, plant and equipment	(9,006)	-
Stock based compensation	(1,802)	(1,678)
Valuation allowance	30,339	-
Deferred income taxes, net	$(1,426)	$(11,881)

At December 31, 2015, the Company had a deferred tax asset related to federal and state net operating loss carryforwards of approximately $54.0 million which expire between 2027 and 2035. There are no limitations on their annual usage. Realization of the deferred tax asset is dependent, in part, on generating sufficient taxable income prior to expiration of the loss carryforwards. At December 31, 2015, the Company has recorded a full valuation allowance against its Federal and Louisiana net deferred tax asset of $30.3 million because the Company believes it is more likely than not that the asset will not be utilized based on losses over the most recent three-year period. At December 31, 2015 the Company has not recorded a valuation allowance against its Texas net deferred tax asset of $1.4 million based on its assessment of several factors, including a history of paying Texas Margins tax and projected future Texas Margins tax expense. At December 31, 2015, the Company does not have any unrecognized tax benefits and does not anticipate any unrecognized tax benefits during the next twelve months. The Company did not incur any income tax deficiencies during fiscal year 2014 or 2015, and therefore has not had any interest or penalties assessed during the years ended December 31, 2014 or 2015. The tax years of the Company that remain subject to examination by the Internal Revenue Service and other income tax authorities are fiscal years 2011, 2012, 2013, 2014 and 2015.

16

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued) 

11. Long-term Debt

Long-term debt at December 31 consisted of the following:

	2015	2014
($ in thousands)
Senior Credit Facility	$-	$5,000
Total debt	-	5,000
Less: current maturities	-	-
Total long-term debt	$-	$5,000

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 and in July 2015, it was extended until July 6, 2016.

The borrowing base is determined at least semiannually using the bank’s usual and customary criteria for oil and gas reserve valuation, and at December 31, 2015 and 2014 was $24 million and $35 million, respectively.

Additionally, the Senior Credit Facility permits the issuance of letters of credit up to the remaining capacity of the Senior Credit Facility. All outstanding amounts owed under the SeniorCredit Facility become due and payable no later than the final maturity date of July 6, 2016, and are subject to acceleration upon the occurrence of events of default which the Company considers usual and customary for an agreement of this type.

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 Company incurred commitment fees of $107 thousand and $165 thousand during 2015 and 2014, respectively. 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 years ended December 31, 2015 and 2014, the weighted average interest rate on the Senior Credit Facility was 3.67% and 4.12%, 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, affirmative representations regarding the absence of material adverse changes, and liens on properties. The Company was in compliance with all debt covenants at December 31, 2015 and 2014.

17

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

12. Asset Retirement Obligations

The majority of the Company’s asset retirement obligations relate to plugging and abandoning oil and gas wells and related equipment. The following table reflects the changes in the Company’s asset retirement obligations during the years ended December 31:

($ in thousands)	2015	2014
Asset retirement obligations at beginning of period	$7,226	$27,447
Liabilities incurred during the period	1,079	415
Liabilities settled during the period (1)	(2,906)	(20,957)
Current period accretion expense	176	852
Revisions in estimated cash flows	(243)	(531)
Asset retirement obligations at end of period	$5,332	$7,226
Less: current portion	(185)	(1,822)
Non-current portion	$5,147	$5,404
(1) Includes ARO's sold as part of disposition in 2014

13. Significant Concentrations

In 2015, approximately 38 percent of the Company’s natural gas, oil, and NGL production was transported and processed through pipeline and processing systems owned by CrossTex Energy Partners. The Company takes steps to mitigate these risks through identification of alternative pipeline transportation. The Company expects to continue to transport a substantial portion of its future natural gas production through these pipeline systems.

During the years ended December 31, 2015, and 2014, sales to four customers accounted to approximately 84 percent and sales to five customers accounted to approximately 85 percent, respectively, of the Company’s total revenues. Management believes that the loss of these customers would not have a material adverse effect on its results of operations or its financial position since the market for the Company’s production is highly liquid with other willing buyers.

Substantially all of the Company’s accounts receivable at December 31, 2015 and 2014 were from sales of natural gas and crude oil as well as joint interest billings to third party companies also in the oil and gas industry. At December 31, 2015, there were four customers that represented approximately 75 percent of the Company’s accounts receivable balance. At December 31, 2014, there were 10 customers that represented approximately 56% of the Company’s accounts receivable balance. This concentration of customers and joint interest owners may impact the Company’s overall credit risk, either positively or negatively, in that these entities may be similarly affected by changes in economic or other conditions.

18

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

14. Stockholders’ Equity

Stock Compensation Plans

Davis provides an incentive plan for the issuance of restricted stock and stock options (the “Plan”). The purpose of the Plan is to enable the Company to obtain and retain the services of selected persons considered essential to the long-range success of the Company by offering them an opportunity to become owners of the Common Stock of the Company through restricted stock and stock option grants. Stock options may be granted to officers, directors and key employees at or above fair market value on the date of grant, vest ratably over three to five years, and have a term of ten years. Fair market value is the simple average of the value that each of the Company’s three major investors independently calculated as being representative of the value of their Company stock at the date of grant. The total number of shares of the Company’s Common Stock for which awards under the Plan may be granted is 28,500,000. At December 31, 2015, there were 4,008,383 shares available for grant under the Plan.

Restricted Shares

The Company has issued 21,701,127 shares of restricted stock from the Plan of which 12,825,427 shares and 11,597,459 shares were vested at December 31, 2015 and 2014, respectively. Of those restricted shares vested at December 31, 2015, a total of 4,978,572 shares were returned to the Company in cashless transactions to pay taxes on vested restricted stock and are accounted for as treasury shares, and 569,600 shares were canceled upon employee resignations and terminations. The Company issued 126,635 shares of restricted stock during the year ended December 31, 2015 with a grant date fair value of $69 thousand. The restrictions on certain restricted stock generally lapse within four years from the date of grant. Related compensation expense recorded for the year ended December 31, 2015 was $553 thousand. The Company entered in a merger agreement on February 10, 2016 (See Footnote 18). The merger will result in the termination of employees over the time period from the date the merger agreement was signed through the closing of the merger and will result in the vesting of 4.7 million shares of restricted stock and the recognition of approximately $998 thousand restricted stock expenses.

Stock Options

The Company’s stock option activity follows:

	Options	Weighted average exercise price
December 31, 2013	7,893,651	$0.85
Canceled and forfeited	(257,737)	0.88
December 31, 2014	7,635,914	$0.85
Canceled and forfeited	(841,404)	1.28
December 31, 2015	6,794,510	$0.80

The following table summarizes information related to stock options outstanding and exercisable at December 31, 2015:

Options Outstanding			Options Exercisable
Number of Options	Weighted Average Exercise Price	Weighted Average Remaining Contractual Life	Number of Options	Weighted Average Exercise Price
4,000,000	$0.68	7.4	2,666,667	$0.68
1,450,000	0.73	3.7	1,450,000	0.73
200,000	0.76	4.6	200,000	0.76
200,000	0.78	4.3	200,000	0.78
200,000	0.96	6.7	150,000	0.96
496,001	1.00	0.4	496,001	1.00
248,509	2.50	0.5	248,509	2.50
6,794,510	$0.80	5.7	5,411,177	$0.82

19

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

The Company uses the Black-Scholes option pricing model to calculate the fair value of its stock options. Because the Company’s stock is not publicly traded, the expected term and volatility used to value its options are based on the expected volatilities and terms of similar companies with publicly traded stock. During the years ended December 31, 2015 and 2014, the Company recognized expense of $380 thousand and $394 thousand (net of $75 thousand capitalized), respectively, related to employee stock options.

Total share-based compensation expense recognized for the year ended December 31, 2015 and 2014 was $933 thousand and $1,712 thousand, respectively, and is reflected in general and administrative expenses in the Consolidated Income Statement. The Company expects to recognize $1,165 thousand for the year ended December 31, 2016.

Series A Convertible Preferred Stock and Common Stock Redemption

On March 8, 2013, the Company issued 27,442,727 shares of Series A Convertible Preferred Stock (“Preferred Stock”) providing for cumulative dividends of 7% per annum, payable in-kind, for $15.1 million in proceeds. Proceeds from the issuance of the Series A Convertible Preferred Stock, along with $14 million in borrowings under the Senior Credit Facility and available cash were used to purchase 65,672,512 million shares of the Company’s common stock in March 2013. During 2015 and 2014, the Company issued 2,236,986 and 2,087,014 shares of Preferred Stock, respectively, as paid in-kind dividends and as of December 31, 2015, there are 33,367,187 shares of preferred stock outstanding.

15. 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.  

	2015	2014
Net income (loss)	$(62,317)	$4,678
Weighted average common shares - Basic	149,182	147,350
Effect of exercise of stock options (1)	-	-
Effective of conversion of preferred stock	31,963	29,828
Weighted average common shares - Diluted	181,145	177,178
Earnings (loss) per common share
Basic	$(0.42)	$0.03
Diluted	$(0.42)	$0.03
There were 6,795 thousand and 7,686 thousand stock options in 2015 and 2014, respectively
that were not included in the diluted shares outstanding as they were all out-of-the money.

20

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

16. Retirement Benefits

The Company has a discretionary defined contribution savings plan (“401(k) Plan”). Under the 401(k) Plan, an employee may elect to contribute from 1 to 100 percent of eligible compensation subject to Internal Revenue Service limits. As of January 1, 2011, the employer match is calculated as 100 percent of the employee’s elective deferrals each payroll period up to 6 percent of eligible compensation each payroll period subject to Internal Revenue Service limits. The Company contributed approximately $169 thousand and $198 thousand to this plan for the years ended December 31, 2015 and 2014, respectively.

17.  Commitments and Contingent Liabilities

Lease Obligations and Other Commitments

The Company has an operating lease for office space. The Company incurred lease rental expense of $422 thousand and $431 thousand during the years ended December 31, 2015 and 2014, respectively.

Future minimum annual rental commitments under non-cancelable leases at December 31, 2015 follow:

(In thousands)
2016	194
2017	-
2018	-
2019	-
Thereafter	-
Total	$194

18. Supplemental Cash Flow Information

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

	Year ended December 31, 2015	Year ended December 31, 2014
(In thousands)
Cash paid for interest, net of amounts capitalized	$362	$1,119
Non-cash additions to asset retirement obligations	836	(116)
Change in accrued capital expenditures	13,730	11,444

19. Subsequent Events

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.

21

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

The merger resulted in the termination of employees from the date the merger agreement was signed through the closing of the merger. On April 1, 2016 the Company terminated a group of employees and $716 thousand of restricted stock expense was recognized.

20. 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, as of December 31, 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. 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.

The Company revised its previously issued consolidated balance sheet as of December 31, 2015 and consolidated statements of operations, consolidated statements of changes in equity and consolidated statements of cash flows for the year ended December 31, 2015, 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 S4 and related quarterly information previously filed with the SEC.

22

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

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 year ended December 31, 2015:

	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

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 year ended December 31, 2015:

	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)	70,073
LOSS FROM OPERATIONS	(54,040)	2,741	(51,299)
NET LOSS BEFORE INCOME TAXES	(54,597)	2,741	(51,856)
NET LOSS	(65,058)	2,741	(62,317)
NET LOSS ATTRIBUTABLE TO COMMON STOCKHOLDERS	(65,058)	2,741	(62,317)
EARNINGS (LOSS) PER COMMON SHARE:
Basic	(0.44)	0.02	(0.42)
Diluted	(0.44)	0.02	(0.42)

23

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

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

24

DAVIS PETROLEUM ACQUISITION CORP.

SUPPLEMENTAL OIL AND GAS DISCLOSURES (UNAUDITED)

Oil and Natural Gas Exploration and Production Activities

Oil and natural gas sales reflect the market prices of net production sold or transferred with appropriate adjustments for royalties, net profits interest, and other contractual provisions. Lease operating expenses include lifting costs incurred to operate and maintain productive wells and related equipment including such costs as operating labor, repairs and maintenance, materials, supplies, and fuel consumed. Production taxes include production and severance taxes. Depletion of oil and natural gas properties relates to capitalized costs incurred in acquisition, exploration, and development activities. Results of operations do not includeinterest expense and general corporate amounts.

Costs Incurred and Capitalized Costs

The costs incurred in oil and natural gas acquisition, exploration, and development activities follow:

	Year ended December 31, 2015	Year ended December 31, 2014
(In thousands)
Costs incurred for the year:
Exploration (including geological and geophysical costs)	$-	$298
Development	3,847	33,724
Acquisition of proved properties, net	1,401	3,918
Capitalized salaries	1,502	2,737
Lease acquisition costs, net of recoveries	899	951
Costs incurred before estimated asset retirement obligations	7,649	41,628
Estimated asset retirement obligations incurred, net of revisions	-	(339)
Total costs incurred	$7,649	$41,289

Results of operations for natural gas and crude oil producing activities, which exclude processing and other activities, corporate general and administrative expenses, and straight-line depreciation expense, were as follows:

	Year ended December 31, 2015	Year ended December 31, 2014
(In thousands)
Revenues	$18,774	$58,663
Operating costs:
Depreciation, depletion, amortization and impairment	57,619	28,442
Lease operating expenses	6,510	12,678
Production taxes	1,106	2,467
Accretion expense	176	852
Income tax provision	-	4,073
Results of operations	$(46,637)	$10,151
Amortization rate per mcfe	$3.66	$4.20

25

DAVIS PETROLEUM ACQUISITION CORP.

SUPPLEMENTAL OIL AND GAS DISCLOSURES (UNAUDITED)

Oil and Natural Gas Reserves and Related Financial Data

The following tables present the Company’s independent petroleum consultants’ estimates of proved oil and natural gas reserves, all of which are located in the United States of America. The Company emphasizes that reserves are estimates that are expected to change as additional information becomes available. Reservoir engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact way and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment.

Proved reserves are estimated quantities of natural gas and crude oil which geological and engineering data indicate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.

	Oil (bbls)	Gas (mcf)	Mcfe
Proved reserves at December 31, 2013	4,452,600	14,611,100	41,326,700
Revisions of previous estimates	(331,700)	344,400	(1,645,800)
Extension, discoveries and other additions	929,100	1,734,000	7,308,600
Sales of minerals in place	(1,486,800)	(864,200)	(9,785,000)
Production	(849,900)	(3,174,700)	(8,274,100)
Proved reserves at December 31, 2014	2,713,300	12,650,600	28,930,400
Revisions of previous estimates	(857,200)	3,711,100	(1,432,100)
Extension, discoveries and other additions	664,800	2,132,100	6,120,900
Purchases of minerals in place	37,900	516,600	744,000
Sales of minerals in place	(23,600)	(945,100)	(1,086,700)
Production	(339,200)	(2,547,300)	(4,582,500)
Proved reserves at December 31, 2015	2,196,000	15,518,000	28,694,000
Proved developed reserves
December 31, 2013	2,167,500	12,203,700	25,208,700
December 31, 2014	1,664,400	11,901,600	21,888,000
December 31, 2015	1,307,600	10,464,300	18,309,900
Proved undeveloped reserves
December 31, 2013	2,285,100	2,407,200	16,117,800
December 31, 2014	1,049,000	748,900	7,042,900
December 31, 2015	888,400	5,053,600	10,384,000

26

DAVIS PETROLEUM ACQUISITION CORP.

SUPPLEMENTAL OIL AND GAS DISCLOSURES (UNAUDITED)

The twelve-month unweighted arithmetic average of the first-day-of-the-month reference prices used in the Company’s reserve estimates at December 31, 2015 and 2014 were $ 2.59/Mmbtu and $50.28/Bbl (West Texas Intermediate) and $4.35/Mmbtu and $94.99/Bbl (West Texas Intermediate) respectively, for natural gas and oil, respectively.

Standardized Measure of Discounted Future Net Cash Flows

The following table presents a standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves. Future cash flows were computed by applying year-end prices of oil and natural gas, which are adjusted for applicable transportation and quality differentials, to the estimated year-end quantities of those reserves. Future production and development costs were computed by estimating those expenditures expected to occur in developing and producing the proved oil and natural gas reserves at the end of the year, based on year-end costs. Actual future cash flows may vary considerably, and the standardized measure does not necessarily represent the fair value of the Company’s oil and natural gas reserves.

Standardized Measure - Year Ended	2015	2014
($ in thousands)
Future cash inflows	$112,449	$268,960
Less related future:
Production costs	38,404	80,726
Development costs	21,947	42,727
Income taxes	-	-
Future net cash flows	52,098	145,507
10% annual discount for estimated timing of cash flows	(11,118)	(43,836)
Standardized measure of discounted future net cash flows	$40,980	$101,671

A summary of the changes in the standardized measure of discounted future net cash flows applicable to proved natural gas and crude oil reserves follows:

Summary of Changes - Year Ended	2015	2014
($ in thousands)
January 1	$101,671	$174,699
Net change in sales and transfer prices and in production (lifting)
costs related to future production	(66,321)	(25,805)
Net change due to revisions in quantity estimates	(12,951)	(13,702)
Net change due to extensions, discoveries and improved recovery	3,534	29,291
Purchases of reserves in place	1,062	-
Sales of reserves in place	(2,784)	(58,220)
Accretion of discount	10,167	18,299
Sales and transfers of oil and gas produced during the period	(10,769)	(43,567)
Net change in income taxes	-	8,289
Changes in estimated future development costs	15,322	8,669
Other	2,049	3,718
Net change	(60,691)	(73,028)
December 31	$40,980	$101,671

27