Exhibit 99.1

 

BRUSHY RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED FINANCIAL STATEMENTS AND REPORTS OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRMS

FOR THE YEARS ENDED DECEMBER 31, 2015 AND 2014

 

  

BRUSHY RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED FINANCIAL STATEMENTS

FOR THE YEARS ENDED DECEMBER 31, 2015 AND 2014 

 

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM (MARCUM LLP)	F-1
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM (KPMG LLP)	F-2
CONSOLIDATED BALANCE SHEETS AS OF DECEMBER 31, 2015 AND 2014	F-3
CONSOLIDATED STATEMENTS OF OPERATIONS FOR THE YEARS ENDED DECEMBER 31, 2015 AND 2014	F-4
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY (DEFICIT) FOR THE YEARS ENDED DECEMBER 31, 2015 AND 2014	F-5
CONSOLIDATED STATEMENTS OF CASH FLOWS FOR THE YEARS ENDED DECEMBER 31, 2015 AND 2014	F-6
NOTES TO FINANCIAL STATEMENTS	F-8
SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES	F-27

 

 

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

 

To the Audit Committee of the

Board of Directors and Shareholders

of Brushy Resources, Inc.

 

We have audited the accompanying consolidated balance sheet of Brushy Resources, Inc. and Subsidiaries (the “Company”) as of December 31, 2015, and the related consolidated statements of operations, changes in stockholders’ (deficit)/equity and cash flows for the year then ended.  These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audit.

 

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States).  Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.  The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing 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 over financial reporting. Accordingly, we express no such opinion.  An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.  We believe that our audit provides a reasonable basis for our opinion.

 

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of Brushy Resources, Inc. and Subsidiaries, as of December 31, 2015, and the consolidated results of its operations and its cash flows for the year then ended in conformity with accounting principles generally accepted in the United States of America.

 

The accompanying consolidated financial statements have been prepared assuming that the Company will continue as a going concern. A more fully described in Note 2, the Company has a significant accumulated and working capital deficit, incurred significant net losses, in default of its loan agreements and needs to raise additional funds to meet its obligations and sustain its operations. These conditions raise substantial doubt about the Company’s ability to continue as a going concern. Management’s plans in regard to these matters are described in Note 2. The consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty.

 

/s/ Marcum LLP

 

Marcum llp

New York, NY

April 20, 2016

 

 

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

 

The Board of Directors and Stockholders

Starboard Resources, Inc.:

 

We have audited the accompanying consolidated balance sheet of Starboard Resources, Inc. and subsidiaries as of December 31, 2014, and the related consolidated statement of operations, changes in stockholders’ equity, and cash flows for the year then ended. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

 

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

 

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Starboard Resources, Inc. and subsidiaries as of December 31, 2014, and the results of their operations and their cash flows for the year then ended, in conformity with U.S. generally accepted accounting principles.

 

/s/ KPMG LLP 

 

KPMG LLP

Dallas, Texas 

April 15, 2015

 

 

BRUSHY RESOURCES, INC. AND SUBSIDIARIES

 

CONSOLIDATED BALANCE SHEETS

 

December 31,		2015				2014
ASSETS
Current assets
Cash		$	2,839,266			$	3,574,427
Trade receivable			1,101,161				1,860,293
Joint interest receivable			171,501				508,001
Current derivative asset			733,131				1,699,156
Prepaid expenses			66,120				283,580
Total current assets			4,911,179				7,925,457
Oil and natural gas properties and other equipment
Oil and natural gas properties, successful efforts method, net of accumulated depletion and impairment			16,883,758				91,766,118
Other property and equipment, net of depreciation			67,321				103,757
Total oil and natural gas properties and other equipment, net			16,951,079				91,869,875
Other assets
Derivative asset			-				66,930
Goodwill			959,681				959,681
Other			358,752				981,283
Total other assets			1,318,433				2,007,894
Total assets		$	23,180,691			$	101,803,226
LIABILITIES AND STOCKHOLDERS' (DEFICIT) EQUITY
Current liabilities
Accounts payable and accrued liabilities		$	5,563,473			$	5,096,825
Going public delay fee			738,320				738,320
Joint interest revenues payable			1,017,823				828,924
Current maturities of related party notes payable			20,898,750				-
Current maturities of notes payable			14,171,713				2,353,322
Current asset retirement obligations			392,398				428,258
Total current liabilities			42,782,477				9,445,649
Long-term liabilities
Notes payable			-				23,104,333
Related party note payable			-				10,180,000
Deferred tax liabilities			-				14,039,742
Asset retirement obligations			3,204,160				3,177,295
Other long-term liabilities			35,147				57,234
Total long-term liabilities			3,239,307				50,558,604
Commitments and contingencies
Stockholders' (deficit) equity
Preferred stock, $.001 par value, authorized 10,000,000 shares; none issued and outstanding
Common stock, $.001 par value, authorized 150,000,000 shares; 12,711,986 and 12,362,336 shares issued at December 31, 2015, and 2014, respectively			12,712				12,362
Additional Paid-in capital			57,044,255				55,919,905
Accumulated deficit			(79,898,060	)			(14,133,294	)
Total stockholders' (deficit) equity			(22,841,093	)			41,798,973
Total liabilities and stockholders' (deficit) / equity		$	23,180,691			$	101,803,226

 

 

BRUSHY RESOURCES, INC. AND SUBSIDIARIES

 

CONSOLIDATED STATEMENTS OF OPERATIONS

 

Years Ended December 31,		2015				2014
Oil, natural gas, and related product sales		$	8,606,606			$	20,172,792
Expenses
Depreciation and depletion			22,510,290				10,140,152
Lease operating			3,677,845				5,457,471
General and administrative			3,938,291				3,876,698
Professional fees			1,041,527				986,774
Production taxes			369,317				695,693
Accretion of discount on asset retirement obligation			187,183				319,703
Exploration			49,531				80,853
Impairment of oil and gas properties			55,753,481				4,428,378
Gain on sale of assets			(2,375,333	)			(2,115,967	)
Total expenses			85,152,132				23,869,435
Operating loss			(76,545,526	)			(3,696,643	)
Other expenses
Interest			(4,149,251	)			(2,617,481	)
Realized gain from derivative contracts			2,302,860				185,891
Change in fair value of derivative contracts			(1,032,955	)			1,880,107
Other expenses			(396,793	)			-
Total other expenses			(3,276,139	)			(551,483	)
Loss before income taxes			(79,821,665	)			(4,248,126	)
Income tax (expense) benefit:
Current income taxes (expense) benefit			17,157				(15,465	)
Deferred income taxes			14,039,742				1,502,671
Total income tax expenses			14,056,899				1,487,206
Net loss		$	(65,764,766	)		$	(2,760,920	)
Net loss per basic and diluted common shares		$	(5.20	)		$	(0.22	)
Weighted average basic and diluted common share outstanding			12,655,467				12,362,336

 

 

BRUSHY RESOURCES, INC. AND SUBSIDIARIES

 

CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' (DEFICIT) / EQUITY

 

Years Ended December 31, 2015 and 2014

 

		Common Stock ($.001 Par Value)								Paid-In Capital in				Retained Earnings
		Shares				Amount				Excess of Par				(Deficit)				Total
Balances, January 1, 2014			12,362,336			$	12,362			$	54,446,105			$	(11,372,374	)		$	43,086,093
Stock-based compensation										$	1,473,800								1,473,800
Net loss															(2,760,920	)			(2,760,920	)
Balances, December 31, 2014			12,362,336				12,362				55,919,905				(14,133,294	)			41,798,973
Stock-based compensation			349,650				350				1,124,350								1,124,700
Net loss															(65,764,766	)			(65,764,766	)
Balances, December 31, 2015			12,711,986			$	12,712			$	57,044,255			$	(79,898,060	)		$	(22,841,093	)

 

 

BRUSHY RESOURCES, INC. AND SUBSIDIARIES

 

CONSOLIDATED STATEMENTS OF CASH FLOWS

 

Years Ended December 31,		2015				2014
Cash flows from operating activities
Net loss		$	(65,764,766	)		$	(2,760,920	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation and depletion			22,510,290				10,140,152
Impairment of oil and gas properties			55,753,481				4,428,378
Deferred income taxes			(14,039,742	)			(1,506,168	)
Stock-based compensation			1,124,700				1,473,800
Accretion of asset retirement obligation			187,183				319,703
Change in fair value of derivative contracts			1,032,955				(1,880,107	)
Accretion of debt issuance costs			438,535				192,739
Write off deferred offering costs			537,927				-
Gain on asset sale			(2,375,333	)			(2,115,916	)
Increase (decrease) in cash attributable to changes in operating assets and liabilities:
Trade receivable			759,132				(82,079	)
Joint interest receivable			336,500				(447,627	)
Prepaid expenses and other assets			100,776				71,808
Accounts payable and accrued liabilities			37,345				(1,134,686	)
Joint interest revenues payable			188,899				(138,856	)
Net cash provided by operating activities			827,882				6,560,221
Cash flows from investing activities
Development of oil and natural gas properties			(5,101,544	)			(16,492,626	)
Acquisition of oil and natural gas properties			-				(16,803,448	)
Proceeds from sale of oil and natural gas properties			7,083,778				1,891,743
Acquisition of other property and equipment			-				(9,495	)
Oil and natural gas abandonment costs			-				(27,345	)
Net cash provided by / (used in) investing activities			1,982,234				(31,441,171	)
Cash flows from financing activities
Proceeds from notes payable			9,750,000				24,060,170
Debt issuance costs			(229,937	)			(210,612	)
Deferred offering costs			(7,310	)			(86,231	)
Repayments of notes payable			(13,058,030	)			(1,102,367	)
Net cash (used in) / provided by financing activities			(3,545,277	)			22,660,960
Net (decrease) in cash			(735,161	)			(2,219,990	)
Cash, beginning of year			3,574,427				5,794,417
Cash, end of year		$	2,839,266			$	3,574,427

 

 

BRUSHY RESOURCES, INC. AND SUBSIDIARIES

 

CONSOLIDATED STATEMENTS OF CASH FLOWS (CONTINUED)

 

Years Ended December 31,		2015				2014
Supplemental disclosure of cash flow information
Cash paid during the period for taxes		$	12,766			$	3,835
Cash paid during the period for interest		$	829,153			$	2,231,137
Supplemental disclosure of non-cash investing transactions
Payables related to oil and natural gas capitalized expenditures		$	3,131,917			$	1,537,638
Capitalized asset retirement cost		$	(41,574	)		$	849,181
Payable settled through asset sales		$	-			$	3,872,674

 

 

BRUSHY RESOURCES, INC. AND SUBSIDIARIES

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

NOTE 1 - NATURE OF OPERATIONS

 

Brushy was originally formed as Starboard Resources LLC in Delaware on June 2, 2011 as a limited liability company to acquire, own, operate, produce, and develop oil and natural gas properties primarily in Texas and Oklahoma. On June 28, 2012, Starboard converted from a Delaware limited liability company to a Delaware C-Corporation and was named Starboard Resources, Inc. The membership units of Starboard Resources LLC were exchanged on a 1:1 basis for common shares of the Company. On July 31, 2015 Brushy sold substantially all of its Oklahoma producing properties and is primarily now focused on its Texas and New Mexico properties. On August 25, 2015 Starboard changed its name to Brushy Resources, Inc. (the “Company”).

 

NOTE 2 - GOING CONCERN

 

Our independent registered public accounting firm for the year ended December 31, 2015 issued their report dated April 20, 2016, that included an explanatory paragraph describing the existence of conditions that raise substantial doubt about our ability to continue as a going concern due to our significant accumulated deficit, working capital deficit, significant net losses and need to raise additional funds to meet our obligations and sustain our operations.

 

Given the precipitous decline in oil and natural gas prices during 2015 and into 2016, we expect to continue to face liquidity constraints. Our cash flows are negatively impacted by lower realized oil and natural gas sales prices and the significant decline in oil and natural gas prices also increases the uncertainty as to the impact of commodity prices on our estimated proved reserves. As a result, we have been in default under the 2013 Credit Agreement between us and Independent Bank, acting for itself and as administrative agent for the other lenders (as amended, the “IB Credit Agreement”) since November 2015. As a result of these defaults, we are no longer permitted to make further draws on the IB Credit Agreement and have been subject to a forbearance agreement with the lenders (the “IB Forbearance Agreement”) pursuant to which the lenders agreed to forbear exercising any of its remedies for the existing covenant defaults for a period of time (the “Forbearance Period”) to permit us to seek refinancing of the indebtedness owed under the IB Credit Agreement in the approximate amount of $11,000,000, which is referred to as the IB Indebtedness or a sale of sufficient assets to repay the IB Indebtedness. During the Forbearance Period we are not permitted to drill new oil or gas wells or make distributions to equity holders. Furthermore, this also cross defaulted the SOSventures Credit Agreement, however, the Forbearance Period began with the execution of the IB Forbearance Agreement on November 24, 2015 and ended on January 31, 2016, but was subsequently extended to March 31, 2016. We are currently in discussions with the lender under the IB Credit Agreement regarding a further extension of the Forbearance Period. If we do not obtain a further extension of the Forbearance Period, the lenders under the IB Credit Agreement will be able to accelerate the repayment of debt under the IB Credit Agreement. For more information see Note 9 - Notes Payable.

 

Proposed Merger with Lilis

 

On December 29, 2015, we agreed to combine our business with Lilis pursuant to the Agreement and Plan of Merger (the “merger agreement”). Pursuant to the merger agreement, Lilis Merger Sub, Inc. (“Merger Sub”) will merge with and into Brushy, with Brushy surviving the merger as a wholly-owned subsidiary of Lilis (the “merger”). Upon completion of the merger, each share of our common stock issued and outstanding immediately prior to the effective time will be converted into the right to receive an amount of shares of Lilis’s common stock such that our former shareholders will represent approximately 50% of the then-outstanding shares of Lilis’s common stock after the closing of the merger (without taking into account outstanding restricted stock units or options or warrants to purchase shares of Lilis’s common stock). In connection with the merger, we are obligated to convey Giddings Field and the Bigfoot Area, to SOSventures, LLC ("SOSventures"), in exchange for a release of our obligations under its subordinated credit agreement with SOSventures, dated March 29, 2013, as amended. We expect the closing of the merger to occur in the first half of 2016. However, the merger is subject to the satisfaction or waiver of other conditions, and it is possible that factors outside our control could result in the merger being completed at an earlier time, a later time or not at all. If the merger has not been completed on or before May 31, 2016, either Lilis or Brushy may terminate the merger agreement unless the failure to complete the merger by that date is due to the failure of the party seeking to terminate the merger agreement to fulfill any material obligations under the merger agreement or a material breach of the merger agreement by such party.

 

  

Collectively, these matters raise substantial doubt about the Company’s ability to continue as a going concern. The Company’s Board of Directors and management team continue to take steps to try to strengthen the Company’s balance sheet. We intend to execute the merger (which is subject to usual and customary closing conditions beyond our control) and, in the event the merger is not consummated, we intend to refinance our existing debt, sell non-core properties and seek private financings to fund our cash needs. Any decision regarding the merger or financing transaction, and our ability to complete such a transaction, will depend on prevailing market conditions and other factors. No assurances can be given that such transactions can be consummated on terms that are acceptable to the Company, or at all. If we are unable to restructure our current obligations under our existing outstanding debt and preferred stock instruments, and address near-term liquidity needs, we may need to seek relief under the U.S. Bankruptcy Code. This relief may include: (i) seeking bankruptcy court approval for the sale or sales of some, most or substantially all of the Company’s assets pursuant to section 363(b) of the U.S. Bankruptcy Code and a subsequent liquidation of the remaining assets in the bankruptcy case; (ii) pursuing a plan of reorganization (where votes for the plan may be solicited from certain classes of creditors prior to a bankruptcy filing) that the Company would seek to confirm (or “cram down”) despite any classes of creditors who reject or are deemed to have rejected such plan; or (iii) seeking another form of bankruptcy relief, all of which involve uncertainties, potential delays and litigation risks.

 

NOTE 3 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

 

Basis of Presentation

 

The consolidated financial statements have been prepared in conformity with accounting principles generally accepted in the United States of America (“GAAP”).

 

Principles of Consolidation

 

The accompanying consolidated financial statements include the accounts of Brushy and its wholly owned subsidiaries, ImPetro Resources, LLC (“ImPetro”) and ImPetro Operating (“Operating”) (Collectively the “Company”). All intercompany transactions and balances have been eliminated in consolidation.

 

Oil and Gas Natural Gas Properties

 

The Company uses the successful efforts method of accounting for oil and natural gas producing activities, as further defined under ASC 932, Extractive Activities - Oil and Natural Gas. Under these provisions, costs to acquire mineral interests in oil and natural gas properties, to drill exploratory wells that find proved reserves, and to drill and equip development wells are capitalized.

 

Exploratory drilling costs are capitalized when incurred pending the determination of whether a well has found proved reserves. A determination of whether a well has found proved reserves is made shortly after drilling is completed. The determination is based on a process that relies on interpretations of available geologic, geophysics and engineering data. If a well is determined to be successful, the capitalized drilling costs will be reclassified as part of the cost of the well. Capitalized costs of producing oil and natural gas interests are depleted on a unit-of-production basis at the field level.

 

If an exploratory well is determined to be unsuccessful, the capitalized drilling costs will be charged to expense in the period the determination is made. If a determination cannot be made as to whether the reserves that have been found can be classified as proved, the cost of drilling the exploratory well is not carried as an asset for more than one year following completion of drilling. If, after that year has passed, a determination that proved reserves exist cannot be made, the well is assumed to be impaired and its costs are charged to expense. Its cost can, however, continue to be capitalized if a sufficient quantity of reserves is discovered in the well to justify its completion as a producing well and the entity is making sufficient progress assessing the reserves and the economic and operating viability of the project.

 

 

The carrying value of oil and gas properties is assessed for possible impairment on a field by field basis and on at least an annual basis, or as circumstances warrant, based on geological analysis or changes in proved reserve estimates. When impairment occurs, an adjustment is recorded as a reduction of the asset carrying value. For the years ended December 31, 2015 and 2014, the Company's impairment charge was approximately $55,753,481 and $4,428,378, respectively.

 

Other Property and Equipment

 

Other property and equipment, which includes field equipment, vehicles, and office equipment, is stated at cost less accumulated depreciation and amortization. Depreciation and amortization is computed using the straight-line method over the estimated useful lives of the assets. Vehicles and office equipment are generally depreciated over a useful life of five years and field equipment is generally depreciated over a useful life of twenty years.

 

Goodwill

 

Goodwill represents the excess of the purchase price over the estimated fair value of the net assets acquired in the acquisition of a business. Goodwill is not amortized; rather, it is tested for impairment annually and when events or changes in circumstances indicate that fair value of a reporting unit with goodwill has been reduced below carrying value. The impairment test requires allocating goodwill and other assets and liabilities to reporting units. However, the Company only has one reporting unit. To assess impairment, the Company has the option to qualitatively assess if it is more likely than not that the fair value of the reporting unit is less than the book value. Absent a qualitative assessment, or, through the qualitative assessment, if the Company determines it is more likely than not that the fair value of the reporting unit is less than the book value, a quantitative assessment is prepared to calculate the fair market value of the reporting unit. If it is determined that the fair value of the reporting unit is less than the book value, the recorded goodwill is impaired to its implied fair value with a charge to operating expenses. As of December 31, 2015 and 2014 and the years then ended there was no impairment of goodwill. Goodwill of $959,681 was from the acquisition of ImPetro Resources LLC on June 13, 2011.

 

Deferred Offering Costs

 

The Company complies with the requirements of the Securities and Exchange Commission (“SEC”) Staff Accounting Bulletin (SAB) Topic 5A “Expenses of Offering”. Deferred offering costs consist principally of accounting, legal and other fees incurred through the consolidated balance sheet dates that are related to a proposed initial public offering and that will be charged to stockholders’ equity upon the receipt of the offering proceeds or charged to expense if the offering is not completed. For the years ended December 31, 2015 and 2014, the Company incurred deferred offering costs of approximately $7,310 and $86,231, respectively, relating to expenses connected with the proposed offering. The deferred offering costs are included in other assets in the consolidated balance sheets. For the years ended December 31, 2015 and 2014, the Company had a write off of approximately $537,927 and $0, respectively.

 

Asset Retirement Obligations

 

The Company follows the provisions of ASC 410-20, Asset Retirement Obligations. ASC 410-20 requires entities to record the fair value of obligations associated with the retirement of tangible long-lived assets in the period in which it is incurred. When the liability is initially recorded, the entity capitalizes a cost by increasing the carrying amount of the related long-lived asset. Over time, the liability is accreted to its present value each period, and the capitalized cost is depleted as part of the oil and natural gas property. Upon settlement of the liability, an entity either settles the obligation for its recorded amount or incurs a gain or loss upon settlement. The Company’s asset retirement obligations relate to the plugging, dismantlement, removal, site reclamation and similar activities of its oil and natural gas properties.

 

Asset retirement obligations are estimated at the present value of expected future net cash flows and are discounted using the Company’s credit adjusted risk free rate. The Company uses unobservable inputs in the estimation of asset retirement obligations that include, but are not limited to, costs of labor, costs of materials, profits on costs of labor and materials, the effect of inflation on estimated costs, and the discount rate. Accordingly, asset retirement obligations are considered a Level 3 measurement under ASC 820. Additionally, because of the subjectivity of assumptions and the relatively long lives of the Company’s wells, the costs to ultimately retire the Company’s wells may vary significantly from prior estimates.

 

 

Revenue Recognition and Natural Gas Imbalances

 

The Company utilizes the accrual method of accounting for natural gas and crude oil revenues, whereby revenues are recognized based on the Company’s net revenue interest in the wells upon delivery to third parties. The Company will also enter into physical contract sale agreements through its normal operations.

 

Gas imbalances are accounted for using the sales method. Under this method, revenues are recognized based on actual volumes of oil and gas sold to purchasers. However, the Company has no history of significant gas imbalances.

 

Cash

 

The Company considers all highly-liquid debt instruments with original maturities of three months or less when purchased to be cash equivalents. As of December 31, 2015 and 2014, the Company did not hold any cash equivalents.

 

The Company maintains its cash balances in financial institutions which are insured by the Federal Deposit Insurance Corporation (“FDIC”). From time to time, the Company will maintain cash balances in a financial institution that may exceed the FDIC coverage of $250,000. The Company has not experienced any losses in such accounts and believes it is not subject to any significant credit risk on cash.

 

Trade Receivable and Joint Interest Receivable

 

Trade receivable is comprised of accrued natural gas and crude oil sales and joint interest receivable is comprised of amounts owed to the Company from joint interest owners for their proportionate share of expenses. Generally, operators of natural gas and crude oil properties have the right to offset joint interest receivables with revenue payables. Accordingly, any joint interest owner that has a joint interest receivable and joint interest revenue payable as of December 31, 2015 and 2014 are shown at net in the accompanying consolidated balance sheets.

 

The Company performs ongoing credit evaluations of its customers’ and extends credit to virtually all of its customers. Credit losses to date have not been significant and have been within management’s expectations. In the event of complete non-performance by the Company’s customers and joint interest owners, the maximum exposure to the Company is the outstanding trade and joint interest receivable balance at the date of nonperformance. For the years ended December 31, 2015 and 2014, the Company had minimal bad debt expense.

 

Derivative Activities

 

The Company utilized oil and natural gas derivative contracts to mitigate its exposure to commodity price risk associated with its future oil and natural gas production. These derivative contracts have historically consisted of options, in the form of price floors or collars. The Company’s derivative financial instruments are recorded on the consolidated balance sheets as either an asset or a liability measured at fair value. The Company does not apply hedge accounting to its oil and natural gas derivative contracts and accordingly the changes in the fair value of these instruments are recognized in the statement of operations in the period of change.

 

The Company’s derivative instruments are issued to manage the price risk attributable to our expected natural gas and oil production. While there is risk that the financial benefit of rising natural gas and oil prices may not be captured, Company management believes the benefits of stable and predictable cash flow are more important. Every unsettled derivative instrument is recorded on the accompanying consolidated balance sheets as either an asset or a liability measured at its fair value. Changes in a derivative’s fair value are recognized in earnings unless specific hedge accounting criteria are met. Cash flows from natural gas and oil derivative contract settlements are reflected in operating activities in the accompanying consolidated statements of cash flows.

 

 

Realized and unrealized gains and losses on derivatives are accounted for using the mark-to-market accounting method. The Company recognizes all unrealized and realized gains and losses related to these contracts in each period in gain (loss) from derivative contracts in the accompanying consolidated statements of operations.

 

Lease Operating Expenses

 

Lease operating expenses represent, pumpers’ salaries, saltwater disposal, ad valorem taxes, repairs and maintenance, expensed workovers and other operating expenses. Lease operating expenses are expensed as incurred.

 

Sales-Based Taxes

 

The Company incurs severance tax on the sale of its production which is generated in Texas, New Mexico and Oklahoma. These taxes are reported on a gross basis and are included in production taxes within the accompanying consolidated statements of operations.

 

Stock-Based Compensation and Equity Incentive Plans

 

The Company accounts for stock-based compensation in accordance with ASC 718, Compensation - Stock Compensation. The standard requires the measurement and recognition of compensation expense in the Company’s consolidated statements of operations for all share-based payment awards made to the Company’s employees, directors and consultants including employee stock options, non-vested equity stock and equity stock units, and employee stock purchase grants. Stock-based compensation expense is measured at the grant date, based on the estimated fair value of the award, reduced by an estimate of the annualized rate of expected forfeitures, and is recognized as an expense over the employees’ expected requisite service period, generally using the straight-line method. In addition, ASC 718 requires the benefits of tax deductions in excess of recognized compensation expense to be reported as a financing cash flow, rather than as an operating cash flow as prescribed under previous accounting rules.

 

The Company’s forfeiture rate represents the historical rate at which the Company’s stock-based awards were surrendered prior to vesting. ASC 718 requires forfeitures to be estimated at the time of grant and revised on a cumulative basis, if necessary, in subsequent periods if actual forfeitures differ from those estimates.

 

During the years ended December 31, 2015 and 2014, the Company incurred a stock based compensation expense of approximately $1,125,000 and $1,474,000, respectively, and is included in the accompanying consolidated statements of operations in general and administrative expenses.

 

Income Taxes

 

Deferred income tax assets and liabilities are computed for differences between the financial statement and tax basis of assets and liabilities that will result in future taxable or deductible amounts, based on enacted tax laws and rates applicable to the periods in which the differences are expected to affect taxable income. Valuation allowances are established, when necessary, to reduce deferred income tax assets to the amount expected to be realized.

 

The Company is required to determine whether its tax positions are more likely than not to be sustained upon examination by the applicable taxing authority, including resolution of any related appeals or litigation processes, based on the technical merits of the position. The tax benefit recognized is measured as the largest amount of benefit that has a greater than fifty percent likelihood of being realized upon ultimate settlement with the relevant taxing authority. De-recognition of a tax benefit previously recognized results in the Company recording a tax liability that increases expense in that period. Based on its analysis, the Company has determined that it has not incurred any liability for unrecognized tax benefits as of December 31, 2015. The Company’s conclusions may be subject to review and adjustment at a later date based on factors including, but not limited to, on-going analyses of and changes to tax laws, regulations and interpretations thereof.

 

The Company recognizes interest and penalties related to unrecognized tax benefits in interest expense and other expenses, respectively. No interest expense or penalties have been recognized as of December 31, 2015.

 

 

Long-Lived Assets

 

The Company accounts for long-lived assets (other than oil and gas properties) at cost. Other long-lived assets consist principally of property and equipment and identifiable intangible assets with finite useful lives (subject to amortization, depletion, and depreciation). The Company may impair these assets whenever events or changes in circumstances indicate that the carrying amount of such assets may not be fully recoverable. Recoverability is measured by comparing the carrying amount of an asset to the expected undiscounted future net cash flows generated by the asset. If it is determined that the asset may not be recoverable, and if the carrying amount of an asset exceeds its estimated fair value, an impairment charge is recognized to the extent of the difference.

 

Net Loss Per Common Share

 

Basic net income (loss) per common share is computed by dividing the net income (loss) attributable to stockholders by the weighted average number of common shares outstanding during the period. Diluted net income (loss) per common share is calculated in the same manner, but also considers the impact to common shares for the potential dilution from stock options, non-vested share appreciation rights and non-vested restricted shares. For the year ended December 31, 2015, there were 900,000 potentially dilutive non-vested and vested stock options and 2,542,397 stock warrants. For the year ended December 31, 2014, there were 1,249,650 potentially dilutive non-vested restricted shares and stock options. The potentially dilutive shares, for the December 31, 2015 and 2014, are considered antidilutive since the Company is in a net loss position and thus result in the basic net loss per common share equaling the diluted net loss per common share.

 

Use of Estimates

 

The preparation of consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the condensed consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

 

The Company’s estimates of oil and natural gas reserves are, by necessity, projections based on geologic and engineering data, and there are uncertainties inherent in the interpretation of such data as well as the projection of future rates of production and the timing of development expenditures. Reserve engineering is a subjective process of estimating underground accumulations of natural gas and oil that are difficult to measure. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation and judgment. Estimates of economically recoverable natural gas and oil 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 natural gas and oil prices, future operating costs, severance taxes, development costs and workover costs, all of which may in fact vary considerably from actual results. The future drilling costs associated with reserves assigned to proved undeveloped locations may ultimately increase to the extent that these reserves are later determined to be uneconomic. For these reasons, estimates of the economically recoverable quantities of expected natural gas and oil attributable to any particular group of properties, classifications of such reserves based on risk of recovery, and estimates of the future net cash flows may vary substantially. Any significant variance in the assumptions could materially affect the estimated quantity of the reserves, which could affect the carrying value of the Company’s oil and natural gas properties and/or the rate of depletion related to the oil and natural gas properties.

 

The most significant financial estimates are associated with the Company’s estimated volumes of proved oil and natural gas reserves, asset retirement obligations, assessments of impairment imbedded in the carrying value of undeveloped acreages undeveloped properties and developed properties, fair value of financial instruments, including derivative liabilities, depreciation and accretion, income taxes and contingencies.

 

  

New Accounting Pronouncement

 

In May 2014, the FASB issued ASU No. 2014-09 (“ASU 2014-09”), “Revenue from Contracts with Customers,” which requires an entity to recognize revenue representing the transfer of promised goods or services to customers in an amount that reflects the consideration which the company expects to receive in exchange for those goods or services. ASU 2014-09 is intended to establish principles for reporting useful information to users of financial statements about the nature, amount, timing and uncertainty of revenues and cash flows arising from the entity’s contracts with customers. ASU 2014-09 will replace most existing revenue recognition guidance in GAAP when it becomes effective. The new standard is effective for us on January 1, 2018. Early application is only permitted as of January 1, 2017. The Company is currently evaluating the effect that ASU 2014-09 will have on its financial statements and related disclosures.

 

In June 2014, the FASB issued ASU No. 2014-12 (“ASU 2014-12”), “Accounting for Share-Based Payments When the Terms of an Award Provide That a Performance Target Could Be Achieved after the Requisite Service Period,” which requires a performance target that affects vesting, and that could be achieved after the requisite service period, be treated as a performance condition. ASU 2014-12 states that the performance target should not be reflected in estimating the grant date fair value of the award. ASU 2014-12 clarifies that compensation cost should be recognized in the period in which it becomes probable that the performance target will be achieved and should represent the periods for which the requisite service has already been rendered. The new standard is effective for us on January 1, 2016. The Company does not expect adoption of ASU 2014-12 to have a significant impact on its financial statements.

 

In August 2014, the FASB issued ASU No. 2014–15 (“ASU 2014-15”), “Presentation of Financial Statements – Going Concern.” ASU 2014-15 provides GAAP guidance on management’s responsibility in evaluating whether there is substantial doubt about a company’s ability to continue as a going concern and about related footnote disclosures. For each reporting period, management will be required to evaluate whether there are conditions or events that raise substantial doubt about a company’s ability to continue as a going concern within one year from the date the financial statements are issued. The new standard is effective for us on January 1, 2017. The Company does not expect the adoption of ASU 2014–15 to have a significant impact on its financial statements.

 

In November 2014, the FASB issued ASU No. 2014-16 (“ASU 2014-16”), “Derivative and Hedging (Topic 815).” ASU 2014-16 addresses whether the host contract in a hybrid financial instrument issued in the form of share should be accounted for as debt or equity. ASU 2014-16 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015. The Company does not expect the adoption of ASU 2014–16 to have a significant impact on its financial statements.

 

In April 2015, the FASB issued ASU No. 2015-03 (“ASU 2015-03”), “Interest - Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs.” ASU 2015-03 requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of the related debt liability, consistent with debt discounts, instead of being presented as an asset. ASU 2015-03 is effective for us on January 1, 2016. Once adopted, entities are required to apply the new guidance retrospectively to all prior periods presented. The retrospective application represents a change in accounting principle. Early adoption is permitted for financial statements that have not been previously issued. The Company is currently evaluating the effect that ASU 2015-03 will have on its financial statements and related disclosures.

 

In May 2015, the FASB issued ASU No. 2015-07 (“2015-07”), “Fair Value Measurement.” ASU 2015-07 removes the requirement to categorize within the fair value hierarchy all investments for which fair value is measured using the net asset value per share practical expedient. The amendments also remove the requirement to make certain disclosures for all investments that are eligible to be measured at fair value using the net asset value per share practical expedient. ASU 2015-07 is effective for us on January 1, 2016. Early adoption is permitted. The Company does not expect the adoption of ASU 2015–07 to have a significant impact on its financial statements.

 

 

In September 2015, the FASB issued ASU No. 2015-16 (“ASU 2015-16”), “Business Combinations (Topic 805), Simplifying the Accounting for Measurement-Period Adjustments”. The update requires that the acquirer in a business combination recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined (not retrospectively as with prior guidance). Additionally, the acquirer must record in the same period’s financial statements the effect on earnings of changes in depreciation, amortization or other income effects as a result of the change to the provisional amounts, calculated as if the accounting had been completed at the time of acquisition. The acquiring entity is required to disclose, on the face of the financial statements or in the footnotes to the financial statements, the portion of the amount recorded in current period earnings, by financial statement line item, that would have been recorded in previous reporting periods if the adjustment to the provisional amounts had been recognized as of the acquisition date. ASU 2015-16 is effective for us on January 1, 2016. The adoption of this standard is not expected to have a material impact on the Company’s financial statements.

 

In November 2015, the FASB has issued an update to ASU No. 2015-17 (“ASU 2015-17”) “Income Taxes (Topic 740): Balance Sheet Classification of Deferred Taxes.” The update requires a company to classify all deferred tax assets and liabilities as noncurrent. The update of ASU 2015-17 is effective for us on January 1, 2018. The Company does not expect the adoption of the update of ASU 2015–17 to have a significant impact on its financial statements.

 

In January 2016, the FASB issued ASU No. 2016-01 (“ASU 2016-01”), “Financial Instruments – Overall (Subtopic 825-10)”. ASU 2016-01 updates certain aspects of recognition, measurement, presentation and disclosure of financial instruments. The new guidance is effective for us on January 1, 2018. The Company does not expect the adoption of ASU 2016–01 to have a significant impact on its financial statements.

 

In February 2016, the FASB issued ASU No. 2016-02 (“ASU 2016-02), “Leases (Topic 842).” ASU 2016-02 requires a lessee to recognize a lease liability for the obligation to make lease payments and a right-to-use asset for the right to use the underlying asset for the lease term. ASU 2016-02 is effective for us on January 1, 2019. Early adoption is permitted. The Company is currently evaluating the effect that ASU 2016-02 will have on its financial statements and related disclosures.

 

In March 2016, the FASB issued ASU No. 2016-06 (“ASU 2016-06”), “Contingent Put and Call Option in Debt Instruments”. ASU 2016-06 is intended to simplify the analysis of embedded derivatives for debt instruments that contain contingent put or call options. The amendments in ASU 2016-06 clarify that an entity is required to assess the embedded call or put options solely in accordance with the four-step decision sequence. Consequently, when a call (put) option is contingently exercisable, an entity does not have to initially assess whether the event that triggers the ability to exercise a call (put) option is related to interest rates or credit risks. The amendments in ASU 2016-06 take effect for public business entities for financial statements issued for fiscal years beginning after December 15, 2016, and interim periods within those fiscal years. Early adoption is permitted, including adoption in an interim period. The Company does not expect the adoption of ASU 2016–01 to have a significant impact on its financial statements.

 

NOTE 4 - FAIR VALUE MEASUREMENTS

 

As defined by ASC 820, the fair value of a financial instrument is the amount at which the instrument could be exchanged in a current transaction between willing parties, other than in a forced or liquidation sale, which was further clarified as the price that would be received to sell an asset or paid to transfer a liability (“an exit price”) in an orderly transaction between market participants at the measurement date. The carrying amounts of the Company’s financial assets and liabilities, such as cash, trade receivable, joint interest receivable, joint interest revenues payable, accounts payable and accrued liabilities and related party payable, approximate their fair values because of the short maturity of these instruments. The carrying amount of the notes payable in long-term debt also approximates fair value due to its variable-rate characteristics.

 

The following tables present information about the Company’s financial assets and liabilities measured at fair value as of December 31, 2015 and December 31, 2014:

 

($ in thousands)		Level 1				Level 2				Level 3				Balance as of December 31, 2015
Assets (at fair value):
Derivative assets (oil collar and put options)		$	-			$	733			$	-			$	733
Liabilities (at fair value):
Asset Retirement Obligations		$	-			$	-			$	3,597			$	3,597

 

 

($ in thousands)		Level 1				Level 2				Level 3				Balance as of December 31, 2014
Assets (at fair value):
Derivative assets (oil collar and put options)		$	-			$	1,766			$	-			$	1,766
Liabilities (at fair value):
Asset Retirement Obligations		$	-			$	-			$	3,606			$	3,606

 

The Company's derivative contracts consist of NYMEX-based fixed price commodity swaps and NYMEX collars. The NYMEX-based fixed price derivative contracts are indexed to NYMEX futures contracts, which are actively traded, for the underlying commodity and are commonly used in the energy industry. A number of financial institutions and large energy companies act as counter-parties to these type of derivative contracts. As the fair value of these derivative contracts is based on a number of inputs, including contractual volumes and prices stated in each derivative contract, current and future NYMEX commodity prices, and quantitative models that are based upon readily observable market parameters that are actively quoted and can be validated through external sources, we have characterized these derivative contracts as Level 2.

 

The asset retirement liability is measured using primarily Level 3 inputs. The significant unobservable inputs to this fair value measurement include estimates of plugging costs, remediation costs, inflation rate and well life. The inputs are calculated based on historical data as well as current estimated costs. See Note 7 - Asset Retirement Obligations.

 

The Company estimates the expected undiscounted future cash flows of its oil and natural gas properties and compares such amounts to the carrying amount of the oil and natural gas properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, the Company will adjust the carrying amount of the oil and natural gas properties to fair value. The factors used to determine fair value are subject to management’s judgment and expertise and include, but are not limited to, recent sales prices of comparable properties, the present value of future cash flows, net of estimated operating and development costs using estimates or proved reserves, future commodity pricing, future production estimates, anticipated capital expenditures and various discount rates commensurate with the risk and current market conditions associated with realizing the expected cash flows projected. These assumptions represent Level 3 inputs. Impairment of oil and gas assets for the year ended December 31, 2015 and 2014 was $55,753 thousand and $4,428 thousand, respectively.

 

NOTE 5 - PROPERTY ACQUISITION AND DIVESTITURE

 

On March 26, 2014 (the “Acquisition Date”), the Company completed the purchase of oil and natural gas leases and leasehold interests (the “Oil and Natural Gas Properties”) from White Oak Resources VI, LLC and Permian Atlantis LLC (collectively the “Seller”) for the purpose of increasing the Company’s oil and natural gas operations in the Permian Basin. The assets acquired are: (a) oil and natural gas leases and leasehold interests in Winkler and Loving Counties in Texas and Lea County, New Mexico; (b) twenty-nine wellbores; and (c) any contracts or agreements related to the foregoing lands, leases and wells. The Oil and Natural Gas Properties include total acreage held by production of 5,160 gross developed acres (1,983.61 net developed acres). Additionally, producing wells and surrounding acreage have been unitized under Texas Railroad Commission regulations. Under the terms of the agreement, the Company purchased the Oil and Natural Gas Properties for $16,803,000 in cash, including before purchase price adjustments. For the year ended December 31, 2014, the Company recognized $1,932 thousand of oil, natural gas and products sales and $725 thousand of net operating income related to properties acquired from White Oak Resources VI, LLC and Permian Atlantis LLC and transaction cost of $45 thousand in profession fees.

 

Unaudited Pro Forma Condensed Combined Financial Statements

 

The following unaudited pro forma financial statements give effect to the acquisition of the Oil and Natural Gas Properties. The unaudited pro forma statement of operations for the year ended December 31, 2014, reflects the acquisition of the Oil and Natural Gas Properties as if it had occurred on January 1, 2014.

 

 

It is not intended to be indicative of the Company's results of operations or financial position that might have been achieved had the acquisition been completed as of the dates presented, or the Company's future results of operations or financial position.

 

in thousands, except share data		Year Ended December 31, 2014
Oil, natural gas, and related product sales		$	20,855
Net loss		$	2,442
Net loss per basic and diluted common share		$	0.20
Weighted average basic and diluted common shares outstanding			12,362,336

 

Financial Statement Presentation and Purchase Price Allocation

 

The following table summarizes the purchase price and values of assets acquired and liabilities assumed:

 

Fair value of assets acquired and liabilities assumed (in thousands)
Proved oil and natural gas properties (1)		$	17,662
Revenue payable			(27	)
Asset retirement obligations			(832	)
Total fair value of assets acquired and liabilities assumed, net		$	16,803
Cash consideration transferred		$	16,803

 

(1) Amount includes asset retirement costs of approximately $832.

 

On July 31, 2015, the Company sold all of its Oklahoma properties, which were located in Logan and Kingfisher Counties, Oklahoma, to Remora Petroleum, LP (Austin, TX) for $7,249,390. The purchaser is not affiliated with any Company officers, directors or material stockholders.

 

The following table summarized the results of operation from the properties sold:

 

($ in thousands)		Year Ended December 31, 2015				Year Ended December 31, 2014
Oil, natural gas, and related product sales		$	1,368			$	6,720
Expenses			269				782
Operating income		$	1,099			$	5,938

 

As part of this transaction, the Company entered into the Fifth Amendment to its Credit Agreement with Independent Bank (“Amendment”). The Amendment provides that $4,000,000 of the purchase price was paid to Independent Bank to pay down its credit facility with Independent Bank.

 

 

NOTE 6 - OIL AND NATURAL GAS PROPERTIES

 

The following table presents a summary of the Company’s oil and natural gas properties at December 31, 2015 and December 31, 2014:

 

($ in thousands)		December 31, 2015				December 31, 2014
Oil and natural gas properties
Proved-developed producing properties		$	43,912			$	96,691
Proved-developed non-producing properties			5,865				2,880
Proved-undeveloped properties			-				13,330
Unproved properties			2,389				1,996
Less: Accumulated depletion			(35,282	)			(23,131	)
Total oil and natural gas properties, net of accumulated depletion and impairment		$	16,884			$	91,766

 

As of December 31, 2015 and December 31, 2014, the accumulated impairment was $55,985 thousand and $3,955 thousand, respectively.

 

NOTE 7 - ASSET RETIREMENT OBLIGATIONS

 

The Company has recognized the fair value of its asset retirement obligations related to the future costs of plugging, abandonment, and remediation of oil and natural gas producing properties. The present value of the estimated asset retirement obligations has been capitalized as part of the carrying amount of the related oil and natural gas properties. The liability has been accreted to its present value as of the end of each period. At December 31, 2015 and December 31, 2014, the Company evaluated 147 and 169 wells, respectively, and has determined a range of abandonment dates between January 2016 and October 2044. The following table represents a reconciliation of the asset retirement obligations for the year ended December 31, 2015 and December 31, 2014:

 

		Year Ended December 31, 2015				Year Ended December 31, 2014
($ in thousands)
Asset retirement obligations, beginning of period		$	3,606			$	2,437
Additions to asset retirement obligation			0				859
Liabilities settled during the period			(155	)			0
Accretion of discount			187				320
Revision of estimate			(41	)			(10	)
Asset retirement obligations, end of period		$	3,597			$	3,606

 

As of December 31, 2015 and 2014, the current asset retirement obligation was approximately $392 thousand and $428 thousand respectively, and the long term asset retirement obligation was approximately $3,204 thousand and $3,177 thousand respectively.

 

See Note 4 - Fair Value Measurements.

 

NOTE 8 – DERIVATIVES

 

We use derivatives to hedge our oil production. Our current hedge position consists put options, of some which have deferred premiums paid at settlement. These contracts and any future hedging arrangements may expose us to risk of financial loss in certain circumstances, including instances where production is less than expected or oil prices increase. In addition, these arrangements may limit the benefit to us of increases in the price of oil. Accordingly, our earnings may fluctuate significantly as a result of changes in the fair value of our derivative instrument, which we utilize entirely to hedge our production and do not enter into for speculative purposes. We have not designated the derivative contracts as hedges for accounting purposes, and accordingly, we record the derivative contracts at fair value and recognize changes in fair value in earnings as they occur.

 

 

At January 1, 2016, we had the following open crude oil derivative contracts:

 

January 1, 2016

Instrument

Commodity

Volume (bbl / month)

Floor Price

Ceilings Price

Purchased Put Option Price

January 2016 – March 2016

Put

Crude Oil

1,500

75.00

January 2016 – December 2016

Put

Crude Oil

3,000

50.00

January 2016 – December 2016

Collar

Crude Oil

3,000

54.00

79.30

 

The following tables identify the fair value amounts of derivative instruments included in the accompanying consolidated balance sheets as derivative contracts, categorized by primary underlying risk. Balances are presented on a gross basis, prior to the application of the impact of counterparty and collateral netting. The following tables also identify the net gain (loss) amounts included in the accompanying consolidated statements of operations as gain (loss) from derivative contracts.

 

Fair Value of Derivative Financial Instruments

 

($ in thousands)		December 31, 2015				December 31, 2014
Derivative financial instruments - Current asset		$	733			$	1,699
Derivative financial instruments - Long-term assets			-				67
Net derivative financial instruments		$	733			$	1,766

 

Effect of Derivative Financial Instruments

 

($ in thousands)		December 31, 2015				December 31, 2014
Realized gain/(loss) on settlement of derivative contracts		$	2,303			$	186
Change in fair value of derivative contracts			(1,033	)			1,880
Realized/Unrealized gain/(loss) from derivative contracts		$	1,270				2,066

 

NOTE 9 - NOTES PAYABLE

 

On June 27, 2013, the Company entered into a credit agreement (“Credit Agreement”) with Independent Bank to borrow up to $100,000,000 at a current rate of 4.00% annum. The Credit Agreement was obtained to fund the development of the Company’s oil and natural gas properties and refinance the prior bank facility. At December 31, 2015 and December 31, 2014, the Company had approximately $12,600,000 and $22,500,000 in borrowings outstanding under the Credit Agreement, respectively.

 

Loans under the Credit Agreement bear interest at the greater of: (1) the prime rate, the annual rate of interest announced by the Wall Street Journal as its “prime rate”, or (2) the floor rate of 4.00%.

 

In November 2015 counsel for Independent Bank had notified us of the following defaults under IB Credit Agreement: i) the interest coverage ratio covenant set forth in Section 7.15.1 of the IB Credit Agreement for the fiscal quarter ended June 30, 2015, (ii) the current ratio covenant set forth in Section 7.15.2 of the IB Credit Agreement for the fiscal quarter ended June 30, 2015, (iii) the leverage ratio covenant set forth in Section 7.15.3 of the IB Credit Agreement for the fiscal quarter ended June 30, 2015, and (iv) the Company is not currently maintaining the minimum Commodity Hedging Transactions (as defined in the IB Credit Agreement) required by Section 7.21 of the IB Credit Agreement. The letter further stated that the bank was contemplating its course of action.

 

On November 24, 2015, we entered into the Forbearance Agreement and the Third Amendment to the Amended and Restated Credit Agreement with Independent Bank under which Independent Bank, acting for itself and as administrative agent for other lenders, agreed to forbear exercising any of its remedies for the existing covenant defaults for period of time to permit us to seek refinancing of the indebtedness owed to Independent Bank in the approximate amount of $11,000,000, which is referred to as the IB Indebtedness or a sale of sufficient assets to repay the IB Indebtedness. The Forbearance Period began with the execution of the IB Forbearance Agreement on November 24, 2015 and ended on January 31, 2016. The Forbearance Period was subsequently extended to March 31, 2016.

 

 

In connection with IB Forbearance Agreement, we provided certain additional collateral protections to Independent Bank. The Company granted a first lien mortgage on a newly completed well in New Mexico. We also delivered certain written directives to Independent Bank. In the event of default on the IB Forbearance Agreement or any IB Non-Forbearance Default, Independent Bank is authorized to send the written directives to Cargill, the counterparty to certain hedging contracts with the Company. These written directives instruct Cargill to pay over to Independent Bank “all hedge settlement proceeds, all hedge liquidation proceeds, and all amount otherwise payable by such hedge providers to Brushy.” We also executed and delivered to Independent Bank certain letters in lieu of transfer orders, whereby we instructed first purchasers of oil and gas production to pay directly to Independent Bank all production revenues attributable to our interest in such oil and gas assets. Independent Bank agrees not to send such letters provided that the IB Indebtedness is paid in full on or before the end of the Forbearance Period. At the time of the extension of the Forbearance Period to March 31, 2016, we agreed to unwind the remaining existing hedge contract with Cargill and permit Cargill to pay to Independent Bank all hedge settlement proceeds, all hedge liquidation proceeds, and all amounts otherwise payable by Cargill to us. Such payments satisfied outstanding interest and default interest owing to Independent Bank as well as certain other expenses. In addition, such payments reduced the principal due Independent Bank by $406,720.

 

During the Forbearance Period, we are not permitted to drill new oil or gas wells or to make any distributions to equity holders. Furthermore, this also cross defaulted the SOSVentures Credit Agreement, however the maturity of the second lien note to SOSventures was extended to August 1, 2016.

 

We are currently in discussions with the lenders under the IB Credit Agreement regarding a further extension of the Forbearance Period. We are also in discussions with Lilis and other financings parties regarding possible refinance options for the amount outstanding under the IB Credit Agreement

 

NOTE 10 - STOCK BASED COMPENSATION AND CONDITIONAL PERFORMANCE AWARDS

 

On April 1, 2012, the Company entered into employment agreements (the “Employment Agreement”) which provided a restricted stock grant and a conditional performance award to key members of management.

 

The restricted stock grant of 349,650 shares had a grant date fair value of $10.00 per share as approved by the Company's compensation committee and vests in full upon the earlier of an initial public offering (“IPO”) which includes the sale of shares to the public, a business combination whereas 50% or more of the voting power is transferred to the new owners, or March 1, 2015. Those 349,650 shares were earned by the employee recipients and issued to them during the three month period ending March 31, 2015.

 

During the twelve months ended December 31, 2015 and 2014, the Company incurred a stock-based compensation expense of approximately $300,000 and $1,199,000, respectively, related to the restricted stock grant, which is included in the accompanying consolidated statements of operations in general and administrative expenses.

 

Additionally, the Employment Agreement provides for a conditional performance award where if an IPO occurs, the employee will receive: (1) a cash payment of 1% of the difference between the Company market capital and the book value at the time of the IPO, (2) common stock options to purchase 1.0% of the fully-diluted capital stock as of the IPO date and IPO price which will vest over a four year period and contain a cashless exercise, (3) common stock options to purchase 1.0% of the fully-diluted capital stock as of the 2nd anniversary of the IPO date at the closing price of the common stock on the 2nd anniversary date of the IPO and will vest six years after the grant and contain a cashless exercise. As of the twelve months ended December 31, 2015 and 2014, the conditional performance feature is not probable and as such, no compensation expense related to the conditional performance feature has been recognized.

 

 

On August 30, 2014, the Company amended and restated the Employment Agreement which provided for additional stock options.

 

The equity award of options to purchase 900,000 shares at the exercise price of $4.75 per share and vesting over three years from September 4, 2014 with a one-year cliff (in respect of 300,000 shares) and monthly vesting thereafter of 25,000 shares over the remaining two years. During the twelve months ended December 31, 2015 and 2014, the Company incurred a stock-based compensation expense of approximately $825,000 and $275,000, respectively, related to stock option, which is included in the accompanying consolidated statements of operations in general and administrative expenses. As of December 31 2015, there was approximately $1,375,000 of unrecognized stock-based compensation related to the non-vested stock options to be recognized over 1.67 years.

 

The assumptions used in the Black-Scholes Option Pricing Model for the stock options granted were as follows:

 

		2014
Risk-free interest rate			1.87	%
Expected volatility of common stock			92	%
Dividend yield		$	0.00
Expected life of options			5.72 years

 

There was no new option granted in 2015. On December 31, 2015, there were 900,000 stock options outstanding and the intrinsic value of the associated options was zero. The weighted average exercise of $4.75/share, weighted average grant date fair value of $2.75/share and the weighted average remaining contractual life of 8.55 years. On December 31, 2015, 425,000 stock options were exercisable.

 

NOTE 11 - RELATED PARTY TRANSACTIONS

 

Subordinated Credit Facility with SOSVentures

 

The Chairman of the Company’s Board of Directors, Bill Liao, works for SOSventures. Further, a group composed of SOSventures, Sean O’Sullivan Revocable Living Trust and Bradford R. Higgins constitute a group owning 4,863,720 or 39.34% of the Company’s common stock shares.

 

On June 3, 2014 the Company agreed to amend its credit agreement with SOSventures, originally entered into on July 25, 2013, providing for a term loan through February 16, 2016 in an amount up to $20,000,000 at an 18.00% interest rate. The loan under this agreement is secured by a second lien on the Company’s assets.

 

The SOSventures credit agreement requires the Company to maintain certain financial ratios. First, the Company must maintain an interest coverage ratio of 3:1 at the end of each quarter so that its consolidated net income less the Company’s fees under the credit facility, lender expenses, non-cash charges relating to the hedge agreements, interest, income taxes, depreciation, depletion, amortization, exploration expenditures and costs and other non-cash charges (netted for noncash income) (“EBITDAX”) is greater than 3 times the Company’s interest expense under the credit facility. Second, the Company must maintain a debt to EBITDAX ratio of less than 3.5:1 at the end of each quarter. Third, the Company must maintain a current ratio of at greater than 1:1 at the end of each quarter, meaning that the Company’s consolidated current assets (including the unused amount of the credit facility by excluding non-cash assets under ASC 410 and 815) must be greater than the Company’s consolidated current liabilities (excluding non-cash obligations under ASC 410 and 815 and current maturities under the credit facility.)

 

The credit agreement prevents the Company from incurring indebtedness to banks or lenders, other than Independent Bank, without the consent of SOSventures. It also prevents the Company from incurring most contingent obligations or liens (other than to Independent Bank). It also restricts the Company’s ability to pay dividends, issue options and warrants and repurchase the Company’s common stock shares. The limitation on options and warrants does not apply to equity compensation plans.

 

This credit facility is currently in default due to the default under the IB Credit Agreement.

 

 

As of March 16, 2016, with accrued and unpaid interest the Company has $21.6 million drawn against the SOSventures credit facility. In light of the December 19, 2014 notice from Independent Bank relating to the payment of interest to SOSventures, pursuant to the Intercreditors Agreement, the Company is are accruing interest payments to SOSventures since the date of that notice.

 

NOTE 12 - LEGAL PROCEEDINGS

 

From time-to-time, the Company may become subject to proceedings, lawsuits and other claims in the ordinary course of business including proceedings related to environmental and other matters. Such matters are subject to many uncertainties, and outcomes are not predictable with assurance.

 

The Company is subject to various possible contingencies that arise primarily from interpretation of federal and state laws and regulations affecting the oil and natural gas industry. Such contingencies include differing interpretations as to the prices at which oil and natural gas sales may be made, the prices at which royalty owners may be paid for production from their leases, environmental issues and other matters. Although management believes that it has complied with the various laws and regulations, administrative rulings and interpretations thereof, adjustments could be required as new interpretations and regulations are issued. In addition, environmental matters are subject to regulation by various federal and state agencies.

 

Lawsuit Relating to 17.23% of our Common Stock Shares

 

Approximately 17.23% of the Company common stock was interpleaded into Connecticut Superior Court for the Judicial District of Stamford/Norwalk at Stamford, Cause No. FST-CV12-6015112-S (“Interpleader Action”). These are the residual shares of common stock that belonged to the Partnerships after the distribution of the partnerships shares. Claims related to the Interpleader Action were heard in an American Arbitration Association arbitration in 2015. The claimants were Gregory Imbruce; Giddings Investments LLC; Giddings Genpar LLC, Hunton Oil Genpar LLC, ASYM Capital Ill LLC, Glenrose Holdings LLC; ASYM Energy Investments LLC. “Certain” respondents and counterclaimants were Charles Henry, Ahmed Ammar; John P. Vaile, as Trustee of John P. Vaile Living Trust, John Paul Otieno, SOSventures, Bradford Higgins, William Mahoney, Edward M. Conrads, Robert J. Conrads, and the Partnerships. “PKG Respondents” and cross claimants were William F. Pettinati, Jr., Sigma Gas Barbastella Fund, Sigma Gas Antrozous Fund, Nicholas P. Garofolo (the plaintiffs in the above-referenced stockholder litigation) who made claims against Charles S. Henry, III, Bradford Higgins and SOSventures. The relief respondents were Rubicon Resources LLC, Sean O’Sullivan, King Lee, Michael Rihner, Scott Decker, Andrew Gillick, Briana Gillick, Steve Heinemann, Stanley Goldstein, Sidney Orbach, James P. Ashman, and Patricia R. Ashman. The claims, counterclaims and cross claims relate to the governance, control and termination of the Partnerships, including the distribution by the Partnerships of our shares of common stock to the limited partners in the Partnerships in a liquidating distribution in February 2014 as part of a “monetization” event, and other matters.

 

On September 10, 2015, the American Arbitration Association issued an arbitration award in the Interpleader Action, which is referred to as the Award. The Award states as follows:

 

1)

All claims asserted by Claimants, including Gregory Imbruce and various business entities controlled by Mr. Imbruce against all Respondents were denied and award was made in favor of the “Certain” respondents, including the Company director, Charles S. Henry, III, as well as SOSventures, Bradford Higgins, John Paul Otieno, Estate of William Mahoney, Ahmed Ammar, John P. Vaile, as Trustee of John P. Vaile Living Trust, Edward M. Conrads, Robert J. Conrads, Giddings Oil & Gas LP, Asym Energy Fund III LP and Hunton Oil Partners LP.

 

2)

All claims asserted by Claimants, Gregory Imbruce and various business entities controlled by Mr. Imbruce against Relief Respondents, including Rubicon Resources LLC, Sean O’Sullivan Revocable Living Trust, King Lee, Michael Rihner, Scott Decker, Andrew Gillick, Briana Gillick, Steve Heinemann, Stanly Goldstein, Sidney Orbach, James P. Ashman and Patricia R. Ashman, were denied.

 

3)

An award was made in favor of the “Certain” respondents, including the Company director, Charles S. Henry, III, as well as SOSventures, Bradford Higgins, John Paul Otieno, Estate of William Mahoney, Ahmad Ammar, John P. Vaile, as Trustee of John P. Vaile Living Trust, Edward M. Conrads, Robert J. Conrads, Giddings Oil & Gas LP, Asym Energy Fund III LP and Hunton Oil Partners LP against Mr. Imbruce and his entities on the following claims:

 

 

a)	breach of fiduciary duty;

 

b)	breach of implied covenant of good faith and fair dealing;

 

c)	partnership dissolution;

 

d)	unjust enrichment;

 

e)	breach of contract;

 

f)	accounting;

 

g)	violation of Connecticut Unfair Trade Practices Act;

 

h)	civil theft; and

 

i)	piercing the corporate veil.

 

4)

All claims asserted by William F. Pettinati, Jr. Sigma Gas Barbastella Fund, Sigma Gas Antrozous Fund and Nicholas P. Garofolo against the Company's director, Charles S. Henry III, as well as SOSventures and Bradford Higgins were denied.

 

5)

A declaratory award was entered declaring that the removal of Hunton Oil Genpar LLC, Giddings Genpar LLC and Asym Capital III LLC and/or Gregory Imbruce as the General Partner(s) of the Partnerships was lawful and in compliance with all legal and contractual requirements, and thus was effective;

 

6)

A declaratory award that the distribution of our -issued common stock made in February 2014 to limited partners in the Partnerships with remaining shares of common stock ultimately being interpleaded into Court in Connecticut was lawful, met all legal requirements and is effective in that the distribution was the result of a “monetization” event under the Partnership agreements;

 

7)

A declaratory award that the Partnerships were effectively dissolved at the time of the distribution of the above-referenced shares of common stock issued by the Company from the Partnerships to the limited partners in the Partnerships;

 

8)

A denial of any and all fees and expenses claimed by Mr. Imbruce and his entities due to “multiple and repeated violations of the Connecticut Uniform Securities Act;”

 

9)

A denial of fees and expenses claimed by Mr. Imbruce and his entities for the time periods subsequent to the 2011 rollup that formed us;

 

10)

An award of damages in favor of the “Certain” respondents, in the amount of $1,602,235, subject to trebling under a Civil Theft finding to $4,806,705, plus attorney and expert fees of $2,998,839 for a total award of $7,805,544, payable by Claimants, including Mr. Imbruce and his business entities;

 

11)

Injunctive relief ordering an accounting of the sources and uses of all funds and other assets of the Partnerships during the time that Mr. Imbruce and his entities served as general partners of the Partnerships;

 

12)

Post-judgment interest at 10 percent per year payable by Mr. Imbruce and his business entities; and

 

13)

Arbitration administrative fees, expenses and compensation of the Arbitrator totaling $122,200 to be paid by Gregory Imbruce et al, and William F. Pettinati, Jr., Sigma Gas Barbastella Fund, Sigma Gas Antrozous Fund and Nicholas P. Garofolo.

 

 

The “Certain” respondents filed in Connecticut Superior Court seeking to confirm the Award. Likewise, Claimants have filed in Connecticut Superior Court to vacate the Award. If the Connecticut Superior Court confirms the Award, we anticipate that the Court will subsequently issue a related order as to ownership of the 2,190,891 common stock of the Company, which may result in modifying the Company ownership structure.

 

Bexar County Proceedings

 

On April 17, 2015, the Company was served with a lawsuit filed in Bexar County, Texas by William F. Pettinati, Jr., Nicholas Garofolo, Sigma Gas Barbastella Fund and Sigma Gas Antrozous Fund against Starboard (now Brushy), its directors, its Chief Operating Officer, Edward Shaw, its former Chief Financial Officer, Eric Alfuth, our stockholder, Bradford Higgins, and Sean O’Sullivan, the managing director of our stockholder, SOSventures (the “Bexar County Proceedings”). Mr. Pettinati, Mr. Garofolo and the Sigma Gas Antrozous Fund are stockholders. Mr. Pettinati owns 145,112 shares, Mr. Garofolo owns 226,680 shares of common stock and Sigma Gas Antrozous Fund owns 44,610 shares of common stock. Combined these stockholders account for approximately 3.3% of the Company's outstanding common stock. These parties became stockholders in February 2014.

 

The Plaintiffs allege several derivative and direct causes of action. These derivative claims include, breach of fiduciary duty, waste of corporate assets, concerted action and conspiracy, joint enterprise, agency, alter ego, exemplary damages, and unjust enrichment. The direct claims include, breach of fiduciary duty, conversion, shareholder oppression, concerted action and conspiracy, declaratory judgment that the distribution of stock to the plaintiffs was invalid, joint enterprise, agency, alter ego, exemplary damages, concerted action and conspiracy and failure to allow for inspection of books and records. Many of the allegations relate to events that allegedly happened before the Plaintiffs became stockholders, including the distributions from the Partnerships that led to the Plaintiffs becoming stockholders in February 2014. Some similar claims involving these Plaintiffs (including the legality of the Partnerships’ liquidating distribution) were previously heard in the arbitration relating to the Partnerships referenced above. Plaintiffs were parties to that arbitration. For actions after February 2014, Plaintiffs complain that the Company's common stock still lacks a trading venue, that a books and records request was not honored, that we “delayed” a public offering, that SOSventures had allegedly taken steps to “foreclose” on the Company's assets under the SOSventures Credit Agreement and that we filed for an extension to the filing date for the Company's annual report on Form 10-K for the year ending December 31, 2014. On October 6, 2015 Plaintiffs withdrew the claim about not honoring a books and records request.

 

The matter is styled Sigma Barbastella Fund et al v. Charles S. Henry, III et al. and it is Cause No. 20105-CI-05672 in the 224th District Court in Bexar County, Texas.

 

The Company's directors and officers are subject to indemnification under the Company's bylaws.

 

Settlement of Interpleader Action and Bexar County Proceedings

 

On February 17, 2016, the various parties to the Interpleader Action and the Bexar County Proceedings entered into a global settlement agreement (the “Settlement Agreement”) under which the parties to the proceedings issued mutual releases and the plaintiffs in all proceedings agreed to withdraw their claims. In return, the plaintiffs received a cash settlement, the majority of which was covered by the Company's insurance.

 

NOTE 13 - STOCKHOLDER’S EQUITY

 

Preferred Shares

 

The Company is authorized to issue up to 10,000,000 preferred shares, par value $0.001 per share, with such designations, voting and other rights and preferences as may be determined from time to time by the Company’s board of directors. No preferred shares were issued and outstanding as of December 31, 2015 and 2014.

 

  

Common Shares

 

The Company has a single class of common shares that have the same rights, preferences, limitations, and qualifications. The Company is authorized to issue up to 150,000,000 shares, par value $0.001 per share, in the aggregate and from time to time may increase the number of shares authorized.

 

Warrants

 

Upon entering into the Second Amendment to the First Amended and Restated Credit Agreement with SOSVentures, SOSVentures received warrants to purchase 2,542,397 of the Company’s common shares for $1.00 per share with a two-year term. The intrinsic value associated with the outstanding warrants was zero at December 31, 2015, as the strike price of all warrants exceeded the implied market price for Common Stock. The remaining contract life was 1.29 years. The implied value of the warrants was based on our peer group, which included Company’s owning assets in the same areas and of similar size. This valuation determined that the value of the warrants was zero. As such, the Company has placed no value on the warrants issued.

 

NOTE 14 - INCOME TAXES

 

For the years ended December 31, 2015 and 2014, the Company estimated that its current and deferred tax provision was as follows:

 

		2015				2014
Current taxes:
Federal		$	-			$	-
State			17,157				(15,465	)
Total current tax benefit / (expense)			17,157				(15,465	)
Deferred taxes:
Federal			27,984,379				1,449,296
State			133,932				53,375
Total deferred tax benefit			28,118,311				1,502,671
Change in valuation allowance			(14,078,569	)			-
Total deferred income tax expense			14,039,742				1,502,671
Total current and deferred tax expenses		$	14,056,899			$	1,487,206

 

A reconciliation of income tax expense (benefit) computed by applying the U.S. federal statutory income tax rate and the reported effective tax rate on income for the years ended December 31, 2015 and 2014 are as follows:

 

		2015				2014
Income tax provision calculated using the federal statutory income tax rate		$	(27,139,366	)		$	1,444,432
State income taxes, net of federal income taxes			(25,205	)			37,910
Permanent differences, rate changes and other			3,932				4,864
Adjustment of previous deferred tax amounts			(974,829	)			-
Change in valuation allowance			14,078,569				-
Total income tax expense		$	(14,056,899	)		$	(1,487,206	)

  

Deferred income taxes arise from temporary differences in the recognition of certain items for income tax and financial reporting purposes. The approximate tax effects of significant temporary differences which comprise the deferred tax assets and liabilities at December 31, 2015 and 2014 are as follows:

 

 

		December 31,
		2015				2014
Deferred tax assets
Federal and state net operating loss carryforwards		$	9,380,168			$	6,864,241
Oil and natural gas properties and other equipment			2,122,275				-
Stock-based compensation			1,596,776				1,214,378
Asset retirement obligations			1,222,830				1,225,887
Other			5,784				5,784
Total deferred tax assets			14,327,833				9,310,290
Deferred tax liabilities:
Oil and natural gas properties and other equipment			-				(22,749,563	)
Derivatives			(249,264	)			(600,469	)
Total deferred tax liabilities			(249,264	)			(23,350,032	)
Total net deferred tax (liability)			14,078,569				(14,039,742	)
Valuation allowance			(14,078,569	)			-
Deferred tax asset (liability), net of valuation allowance		$	-			$	(14,039,742	)

 

At December 31, 2015, the Company has net operating losses as follows:

 

		Amount				Expiration
Net operating losses:
Federal		$	26,846,276				Dec. 2032 to 2035
State			6,562,922				Dec. 2032 to 2035

 

In assessing the need for a valuation allowance on our deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will be realized. The ultimate realization of deferred tax assets is dependent upon whether future book income is sufficient to reverse existing temporary differences that give rise to deferred tax assets, as well as whether future taxable income is sufficient to utilize net operating loss and credit carryforwards. Assessing the need for, or the sufficiency of, a valuation allowance requires the evaluation of all available evidence, both positive and negative. Management had no positive evidence to consider. Negative evidence considered by management includes cumulative book and tax losses in recent years, forecasted book and tax losses, no taxable income in available carryback years, and no tax planning strategies contemplated to realize the valued deferred tax assets.

 

As of December 31, 2015 and 2014, management assessed the available positive and negative evidence to estimate if sufficient future taxable income would be generated to use the Company’s deferred tax assets and determined that it is not more-likely-than-not that the deferred tax assets would be realized in the near future. Therefore, the Company recorded a full valuation allowance of approximately $14,078,569 and $0 on its deferred tax assets as of December 31, 2015 and 2014, respectively.

 

NOTE 15 - SUBSEQUENT EVENTS

 

Credit Facilities and Forbearance Agreement.

 

The maturity of our second lien note to SOSventures was extended to August 1, 2016. The Forbearance Period began with the execution of the IB Forbearance Agreement on November 24, 2015 and ended on January 31, 2016, but was subsequently extended to March 31, 2016. We are currently in discussions with the lender under the IB Credit Agreement regarding a further extension of the Forbearance Period.

 

On January 20, 2016, the Company, Lilis and Merger Sub entered into an amendment to the merger agreement (the “Amendment”). Pursuant to the Amendment: (i) the amount of the refundable deposit was increased by $1 million to a total of $2 million and (ii) the scope of the refundable deposit was broadened such that it now covers the amount paid by Lilis to Independent Bank on December 29, 2015 in addition to certain other matters, such as payments towards accounts payable, transactions costs and other operating costs of the Company.

 

On March 24, 2016, the Company, Lilis and Merger Sub entered into a second amendment to the Merger Agreement (the “Second Amendment”). Pursuant to the Second Amendment: (i) the definition of refundable deposit was modified to include such further increases as may be mutually agreed upon between the parties, (ii) the amount and treatment of restricted stock units of the Company with respect to the Merger Agreement was clarified, the definition of “Stock Exchange Ratio” was fixed at 4.550916 to account for certain grants of restricted stock to members of the Board of Directors of the Company pursuant to existing service agreements and (iv) the definition of “Termination Date” was changed from April 30, 2016 to May 31, 2016.

 

 

BRUSHY RESOURCES, INC. AND SUBSIDIARIES

 

SUPPLEMENTAL INFORMATION

 

Presented in accordance with

FASB ASC Topic 932, Extractive Activities - Oil and Gas

 

 

BRUSHY RESOURCES, INC. AND SUBSIDIARIES

 

SUPPLEMENTAL INFORMATION

 

Supplemental Oil and Natural Gas Disclosures (Unaudited)

 

The following tables set forth supplementary disclosures for oil and gas producing activities in accordance with FASB ASC Topic 932, Extractive Activities - Oil and Gas.

 

Capitalized Costs

 

The following table presents a summary of the Company’s oil and natural gas properties at December 31, 2015 and 2014:

 

		2015				2014
Oil and natural gas properties
Proved-developed producing properties		$	43,912			$	96,691
Proved-developed non-producing properties			5,865				2,880
Proved-undeveloped properties			-				13,330
Unproved properties			2,389				1,996
Less: Accumulated depletion			(35,282	)			(23,131	)
Total oil and natural gas properties, net of accumulated depletion		$	16,884			$	91,766

 

The following table summarizes costs incurred in oil and natural gas property acquisition, exploration, and development activities. Property acquisition costs as those incurred to purchase lease or otherwise acquire property, including both undeveloped leasehold and the purchase of reserves in place. Exploration costs include costs of identifying areas that may warrant examination and examining specific areas that are considered to have prospects containing oil and natural gas reserves, including costs of drilling exploratory wells, geological and geophysical costs, and carrying costs on undeveloped properties. Development costs are incurred to obtain access to proved reserves, including the cost of drilling development wells, and to provide facilities for extracting, treating, gathering and storing oil and natural gas. Additionally, costs incurred also include new asset retirement obligations established. Asset retirement obligations included in the tables below in the as reported columns for the years ended December 31, 2015 and 2014 were approximately $(42,000) and $849,000, respectively

 

Costs incurred (capitalized and charged to expense) in oil and natural gas activities for the years ended December 31, 2015 and 2014 were as follows:

 

		2015				2014
Acquisitions of proved properties		$	-			$	16,803,448
Exploration			73,496				785,314
Development			8,118,390				17,244,950
Total costs incurred		$	8,191,886			$	34,749,337

  

Results of operations from oil and natural gas producing activities for the years ended December 31, 2015 and 2014, excluding Company overhead and interest costs, were as follows:

 

		2015				2014
Oil, natural gas and related product sales		$	8,606,606			$	20,172,792
Lease operating costs			(3,677,845	)			(5,457,471	)
Production taxes			(369,317	)			(695,693	)
Exploration costs			(49,531	)			(80,533	)
Depletion			(22,510,290	)			(10,140,152	)
Impairment			(55,753,481	)			(4,428,378	)
Results of operations from oil and natural gas producing activities		$	(73,753,858	)		$	(629,435	)

 

 

BRUSHY RESOURCES, INC. AND SUBSIDIARIES

 

SUPPLEMENTAL INFORMATION

 

Supplemental Oil and Natural Gas Disclosures (Unaudited) (continued)

 

Proved Reserves Methodology

 

The Company’s estimated proved reserves, as of December 31, 2014 and 2013, are made in accordance with the SEC’s final rule, Modernization of Oil and Gas Reporting, which amended Rule 4-10 of Regulation S-X (the “Final Rule”). As defined by the Final Rule, proved reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible in future years from known reservoirs under existing economic conditions, operating methods, and government regulations. Projects to extract the hydrocarbons must have commenced or an operator must be reasonably certain that it will commence the projects within a reasonable time. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the projects. Further requirements for assignment of estimated proved reserves include the following:

 

The area of a reservoir considered proved includes (A) that portion delineated by drilling and defined by natural gas, oil, and/or water contacts, if any; and (B) adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data. In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons and highest known oil seen in well penetrations unless geoscience, engineering, or performance data and reliable technology establishes a lower or higher contact with reasonable certainty. Reliable technologies are any grouping of one or more technologies (including computational methods) that have been field-tested and have been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

 

Reserves which can be produced economically through applications of improved recovery techniques (including, but not limited to fluid injections) are included in the proved classification when successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, and other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based.

 

Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The prices used are the average crude oil and natural gas prices during the twelve month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

 

Reserves engineering is a subjective process of estimating underground accumulations of crude oil, condensate, natural gas, and natural gas liquids that cannot be measured in an exact manner. The accuracy of any reserves estimate is a function of the quality of available date and of engineering and geological interpretation and judgment. The reserves actually recovered, the timing of production of those reserves, as well as operating costs and the amount and timing of development expenditures may be substantially different from original estimates. Revisions result primarily from new information obtained from development drilling, production history, field tests, and data analysis and from changes in economic factors including expectation and assumptions as to availability of financing for development projects.

 

Reserve Quantity Information

 

The following table presents the Company’s estimate of its proved oil and gas reserves all of which are located in the United States. The estimates have been prepared with the assistance of Forrest A. Garb & Associates, Inc., an independent petroleum reservoir engineering firm. Oil reserves, which include condensate and natural gas liquids, are stated in barrels and gas reserves are stated in thousands of cubic feet.

 

 

BRUSHY RESOURCES, INC. AND SUBSIDIARIES

 

SUPPLEMENTAL INFORMATION

 

Supplemental Oil and Natural Gas Disclosures (Unaudited) (continued)

 

PROVED-DEVELOPED AND UNDEVELOPED RESERVES		Crude Oil (Bbl)				Natural Gas (Mcf)
December 31, 2013			3,650,910				8,639,620
Revisions of previous estimates			(772,982	)			(758,638	)
Extensions and discoveries			558,000				333,230
Acquisitions of reserves			797,360				3,811,000
Sales of reserves			(59,370	)			(474,930	)
Production			(180,898	)			(779,012	)
December 31, 2014			3,993,020				10,771,270
Revisions of previous estimates			(3,334,352	)			(7,207,552	)
Extensions and discoveries			327,865				1,313,149
Acquisitions of reserves			-				-
Sales of reserves			(165,430	)			(1,430,690	)
Production			(152,273	)			(676,847	)
December 31, 2015			668,830				2,769,330
PROVED DEVELOPED RESERVES
December 31, 2015			668,830				2,769,330
December 31, 2014			853,560				4,324,760

 

The following table presents the Company’s changes in proved undeveloped reserves.

 

PROVED UNDEVELOPED RESERVES

 

		Crude Oil (Bbl)				Natural Gas (Mcf)
December 31, 2013			3,166,300				6,539,420
Revisions of previous estimates			(704,790	)			(921,280	)
Extensions and discoveries			540,150				237,800
Acquisitions of reserves			531,350				1,887,730
Sales of reserves			(59,370	)			(474,930	)
Transfer to developed			(334,170	)			(822,240	)
December 31, 2014			3,139,470				6,446,500
Revisions of previous estimates			(3,099,750	)			(6,128,780	)
Extensions and discoveries			0				0
Acquisitions of reserves			0				0
Sales of reserves			(39,720	)			(317,720	)
Transfer to developed			0				0
December 31, 2015			0				0

 

Due to the lack of available capital required to drill the proved undeveloped locations, all proven undeveloped reserves were removed during 2015.

 

Future cash flows are computed by applying a first-day-of-the-month 12-month average price of natural gas (Henry Hub) and oil (West Texas Intermediate) to year end quantities of proved natural gas and oil reserves. Future operating expenses and development costs are computed primarily by the Company's petroleum engineers by estimating the expenditures to be incurred in developing and producing the Company’s proved natural gas and oil reserves at the end of the year, based on year end costs and assuming continuation of existing economic conditions. For the year ended December 31, 2015, the oil and natural gas prices were applied at $47.03/Bbl and $2.23/Mcf, respectively, in the standardized measure. For the year ended December 31, 2014, the oil and natural gas prices were applied at $91.42/Bbl and $6.53Mcf, respectively, in the standardized measure.

 

 

BRUSHY RESOURCES, INC. AND SUBSIDIARIES

 

SUPPLEMENTAL INFORMATION

 

Supplemental Oil and Natural Gas Disclosures (Unaudited) (continued)

 

Standardized Measure of Discounted Future Net Cash Flow and Changes Therein Relating to Proved Oil and Gas Reserves

 

The following tables, which presents a standardized measure of discounted future cash flows and changes therein relating to proved oil and gas reserves as of December 31, 2015 and 2014, for the years ended December 31, 2015 and 2014, is presented pursuant to ASC 932. In computing this data, assumptions other than those required by the Financial Accounting Standards Board could produce different results. Accordingly, the data should not be construed as being representative of the fair market value of the Company’s proved oil and gas reserves.

 

A discount factor of 10 percent was used to reflect the timing of future net cash flows. The standardized measure of discounted future net cash flows is not intended to represent the replacement costs or fair value of the Company's natural gas and oil properties. An estimate of fair value would take into account, among other things, the recovery of reserves not presently classified as proved, anticipated future changes in prices and costs, and a discount factor more representative of time value of money and the risks inherent in reserve estimates of natural gas and oil producing operations. There have been no estimates for future plugging and abandonment costs

 

Standardized Measure of Discounted Future Net Cash Flows as of December 31, 2015

 

Future cash inflows			37,611,800
Less: Future production costs			(16,468,590	)
Future development costs			-
Future income tax expense			-
Future net cash flows			21,143,210
10% discount factor			(6,300,765	)
Strandardized measure of discounted future net cash inflows			14,842,445

 

Changes in Standardized Measure of Discounted Future Net Cash Flows for the Year Ended December 31, 2015

 

Standardized measure - beginning of year			90,116,131
Sales of oil and natural gas, net of production costs			(4,559,444	)
Net changes in prices and production costs			(134,395,658	)
Development costs incurred during the year			457,344
Changes in future development costs			71,777,018
Extensions, discoveries, and improved recoveries			9,321,938
Revisions/timing of previous quantity estimates			(69,250,616	)
Accretion of discount			13,199,248
Net change in income taxes			39,332,749
Purchases and sale of mineral interests			(1,156,265	)
End of year			14,842,445

 

 

BRUSHY RESOURCES, INC. AND SUBSIDIARIES

 

SUPPLEMENTAL INFORMATION

 

Supplemental Oil and Natural Gas Disclosures (Unaudited) (continued)

 

Standardized Measure of Discounted Future Net Cash Flows as of December 31, 2014

 

Future cash inflows			435,341,260
Less: Future production costs			(104,680,910	)
Future development costs			(92,010,030	)
Future income tax expense			(72,379,134	)
Future net cash flows			166,271,186
10% discount factor			(76,155,055	)
Standardized measure of discounted future net cash inflows			90,116,131

 

Changes in Standardized Measure of Discounted Future Net Cash Flows for the Year Ended December 31, 2015

 

Net Changes in Prices and Production Costs: For the year ended December 31, 2015, the oil and natural gas prices were applied at $47.03/Bbl and $2.23/Mcf, respectively, in the standardized measure. At December 31, 2014, the oil and natural gas prices were applied at $91.42/Bbl and $6.53/Mcf, respectively, in the standardized measure. The decrease in oil and natural gas prices resulted in a significant decrease in future expected cash flows and reserves.

 

Extensions, Discoveries, and Improved Recoveries: During the year ended December 31, 2015, the Company had extensions and discoveries of 327,870 Bbl of crude oil and 1,313,150 Mcf of natural gas from primarily newly identified horizontal drilling opportunities in the Delaware Basin, located in the Crittendon field.

 

Revisions of Previous Quantity Estimates: During the year ended December 31, 2015, the Company adjusted its previous estimates by (3,460,067) Bbl of crude oil and (8,320,523) Mcf of natural gas from primarily removal of proven undeveloped reserves that the Company currently has interests in due to lack of available capital.

 

Purchases and sales of mineral interests: During the year ended December 31, 2015, the Company sold its Oklahoma properties in Logan and Kingfisher counties.

 

Accretion of Discount: Accretion during the year ended December 31, 2014 was the result of accretion of the future net revenues at a standard rate of 10% due to the passage of time.

 

 

BRUSHY RESOURCES, INC. AND SUBSIDIARIES

 

SUPPLEMENTAL INFORMATION

 

Supplemental Oil and Natural Gas Disclosures (Unaudited) (continued)

 

Significant Changes in Reserves for the Year Ended December 31, 2013

 

Net Changes in Prices and Production Costs: For the year ended December 31, 2014, the oil and natural gas prices were applied at $95.28/Bbl and $4.36/MMBtu, respectively, in the standardized measure. At December 31, 2013, the oil and natural gas prices were applied at $96.90/Bbl and $3.67/MMBtu, respectively, in the standardized measure. The increase in oil and natural gas prices resulted in a significant increase in future expected cash flows and reserves. Each of the reference prices for oil and natural gas were adjusted for quality factors and regional differences.

 

Extensions, Discoveries, and Improved Recoveries: During the year ended December 31, 2014, the Company had extensions and discoveries of 558,000 Bbl of crude oil and 333,230 Mcf of natural gas from primarily newly identified drilling opportunities in the Eaglebine oil and natural gas reservoirs as well as new drills in Oklahoma.

 

Revisions of Previous Quantity Estimates: During the year ended December 31, 2014, the Company adjusted its previous estimates by (772,982) Bbl of crude oil and (758,638) Mcf of natural gas from primarily revisions of proved undeveloped reserves that the Company currently has interests in due to increases in estimated production costs and the requirement that a development plan for the undeveloped oil and gas reserves must be adopted indicating that such reserves are scheduled to be drilled within five years under SEC Regulation S-X Rule 4-10(a)(31)(ii).

 

Purchases and sales of mineral interests: During the year ended December 31, 2014, the Company purchased the Crittendon Field.

 

Accretion of Discount: Accretion during the year ended December 31, 2014 was the result of accretion of the future net revenues at a standard rate of 10% due to the passage of time.