Brushy Resources, Inc. - FORM 10-K

Attached files

file	filename
EX-31.1 - EXHIBIT 31.1 - Brushy Resources, Inc.	ex31_1.htm
EX-32.1 - EXHIBIT 32.1 - Brushy Resources, Inc.	ex32_1.htm
EX-99.2 - EXHIBIT 99.2 - Brushy Resources, Inc.	ex99_2.htm
EX-31.2 - EXHIBIT 31.2 - Brushy Resources, Inc.	ex31_2.htm
EX-23.2 - EXHIBIT 23.2 - Brushy Resources, Inc.	ex23_2.htm

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington D.C. 20549

FORM 10-K

(Mark One)

T ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF1934

For the Fiscal Year Ended December 31, 2015

☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE EXCHANGE ACT OF 1934

Commission file number 333-191139

BRUSHY RESOURCES, INC.

(Exact name of registrant as specified in its charter)

Delaware	45-5634053
(State or other jurisdiction of Incorporation or organization)	(IRS Employer Identification No.)

300 E. Sonterra Blvd., Suite 1220	(210) 999-5400
San Antonio, Texas 78258	(Issuer’s telephone number)
(Address of principal executive offices)

Securities registered pursuant to Section 12(b) of the Act: None

Title of each class

Common Stock, $0.001 par value

Indicate by check mark if the Registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities

Yes ☐ No T

Indicate by checkmark if the Registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ☐ No T

Indicate by check mark whether the Registrant (1) has filed all reports required by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing to such filing requirements for the past 90 days. Yes T No ☐

Indicate by check mark whether the Registrant has submitted electronically and posted on its corporate web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the Registrant was required to submit and post such files). Yes ☐ No T

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of Registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to the Form 10-K. ☐

Indicate by check mark whether the Registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and smaller reporting company” in Rule 12-b2 of the Exchange Act.

Large accelerated filer ☐	Accelerated filer ☐
Non-accelerated filer (do not check if a smaller reporting company) ☐	Smaller reporting company T

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act.) Yes ☐ No T

The Company’s stock has not traded, consequently it has no aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which Registrant’s common stock shares was last sold as of the last business day of the Registrant’s most recently completed second fiscal quarter.

As of April 20, 2016, 12,711,986 shares of Common Stock were outstanding.

BRUSHY RESOURCES, INC. AND SUBSIDIARIES

INDEX TO FORM 10-K

		PAGE

	PART I	4
Item 1.	Description of Business.	4
Item 1A.	RISK FACTORS	14
Item 2.	Properties.	34
Item 3.	LEGAL PROCEEDINGS.	41

	PART II	43
Item 4.	Mine Safety Disclosures	43
Item 5.	Market for Common Equity and Related Stockholder Matters	43
Item 6.	Selected Financial Data	44
Item 7.	Management’s Discussion and Analysis or Plan of Operations	44
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk.	51
Item 8.	Financial Statements and Supplementary Data.	52

	PART III	52
Item 9.	Changes In and Disagreements with Accountants on Accounting and Financial Disclosure.	52
Item 9A.	Controls and Procedures	53
Item 9B.	Other Information	54
Item 10.	Directors, Executive Officers and Corporate Governance	55
Item 11.	Executive Compensation	57
Item 13.	Certain Relationships and Related Transactions, and Director Independence.	61
Item 14.	Principal Accountant Fees and Services	62

	PART IV	63
Item 15.	Exhibits, Financial Statement Schedules	63

	SIGNATURES	67
	Financial Statements	F-1
	Consent of Petroleum Engineer	Exhibit 23.2
	Certifications	Exhibits 31.1, 31.2, 32.1
	Reserve Report Summary as of December 31, 2015	Exhibit 99.2

Table of Contents

CAUTIONARY NOTE REGARDING FORWARD LOOKING STATEMENTS

This Annual Report on Form 10-K (this “Form 10-K”) contains “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995, Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). All statements other than statements of historical fact included or incorporated by reference in this Form 10-K are forward-looking statements, including, without limitation, but are not limited to, any statements regarding business strategy, estimated current and future net reserves and present values of such reserves, drilling and completion of wells including our identified locations, financial strategy, budget projections, operating results, marketing and realized prices for oil, natural gas and natural gas liquids, timing and amount of future production of oil and natural gas, availability and cost of drilling and production equipment, availability and cost of oilfield labor, the amount, nature and timing of capital expenditures, including future development costs, our ability to fund our 2015 capital expenditure budget, availability and terms of capital, development results from our identified drilling locations, property acquisitions, property development and operating costs, general economic conditions, the commodity price environment, the effectiveness and extent of our risk management activities, our insurance coverage, estimates of future potential impairments, environmental liabilities, technology, counterparty credit risk, government regulation of and tax treatment for the oil and gas industry, non-historical plans, objectives, expectations and intentions contained in this report, future revenues, future costs and expenses, earnings, earnings per share, margins, cash flows, liquidity and dividends. Important factors which may affect the actual results include, but are not limited to, the resolution of the litigation involving Giddings Oil & Gas LP, Hunton Oil Partners LP and Asym Energy Fund III LP, the proposed merger with Lilis Energy, Inc. (“Lilis”), political developments, market and economic conditions, changes in raw material, transportation and energy costs, inflation, industry competition, lack of availability of drilling and production equipment and services, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating oil and natural gas reserves and in projecting future rates of production, cash flow and access to capital, the timing of development expenditures, cost of services, service and equipment providers and the ability to execute and realize the expected benefits from strategic initiatives, including revenue and reserve growth plans, mergers and acquisitions and their integration, changes in financial markets and changing legislation and regulations, including changes in tax law or tax regulations and other risks described in our “Risk Factors” section commencing on page 14 of this Report. In some cases, you can identify a forward-looking statement by terminology such as “may,” “will,” “could,” “should,” “expect,” “plan,” “project,” “intend,” “anticipate,” “believe,” “estimate,” “predict,” “potential,” “pursue,” “target” or “continue,” the negative of such terms or variations thereon, or other comparable terminology.

These forward-looking statements involve certain risks and uncertainties. Actual results may differ materially from those contemplated in the forward-looking statements due to, among others, the factors discussed under “Risk Factors” beginning on page 14 of this Form 10-K, as well as the following factors:

●

the possibility that we or Lilis may be unable to obtain stockholder approvals required for the merger;

●

the possibility that problems may arise in successfully integrating the businesses of the two companies;

●

the possibility that the merger may involve unexpected costs; and

●

the possibility that the businesses may suffer as a result of uncertainty surrounding the merger.

Should one or more of the risks or uncertainties described in this report occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements. All forward-looking statements, expressed or implied, included in this report are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue. All forward-looking statements in this report are expressly qualified by the statements in this section to reflect events or circumstances after the date of this report. Forward-looking statements are not guarantees of future performance and actual results may differ significantly from the results discussed in the forward-looking statements. We assume no obligation to revise or update any forward-looking statements for any reason, except as required by law.

In this Annual Report on Form 10-K, references to "we", "our", "us" or the "Company" refer to Brushy Resources, Inc, and its subsidiaries.

NON-GAAP FINANCIAL MEASURES

We refer to the term PV-10 in this annual report on Form 10-K. This is a supplemental financial measure that is not prepared in accordance with U.S. generally accepted accounting principles, or GAAP. Any analysis of non-GAAP financial measures should be used only in conjunction with results presented in accordance with GAAP. PV-10 is the present value of the estimated future cash flows from estimated total proved reserves after deducting estimated production and ad valorem taxes, future capital costs, abandonment costs, net of salvage value, and operating expenses, but before deducting any estimates of future income taxes. The estimated future cash flows are discounted at an annual rate of 10% to determine their “present value.” We believe PV-10 to be an important measure for evaluating the relative significance of our oil and gas properties and that the presentation of the non-GAAP financial measure of PV-10 provides useful information to investors because it is widely used by professional analysts and investors in evaluating oil and gas companies. Because there are many unique factors that can impact an individual company when estimating the amount of future income taxes to be paid, we believe the use of a pre-tax measure is valuable for evaluating our Company. We believe that PV-10 is a financial measure routinely used and calculated similarly by other companies in the oil and gas industry. However, PV-10 is considered a non-GAAP financial measure under SEC regulations because it does not include the effects of future income taxes, as is required in computing the standardized measure of discounted future net cash flows.

Table of Contents

The Securities and Exchange Commission (“SEC”) has adopted rules to regulate the use in filings with the SEC and in public disclosures of “non-GAAP financial measures,” such as PV-10. These measures are derived on the basis of methodologies other than in accordance with GAAP. These rules govern the manner in which non-GAAP financial measures are publicly presented and require, among other things:

a presentation with equal or greater prominence of the most comparable financial measure or measures calculated and presented in accordance with GAAP; and

a statement disclosing the purposes for which the company’s management uses the non-GAAP financial measure.

For a reconciliation of PV-10 to the standardized measure of our proved oil and gas reserves at December 31, 2015, see page 35 of this annual report.

Emerging Growth Company

We are an “Emerging Growth Company” under the Jumpstart our Business Startups Act (JOBS Act) which was signed into law by President Obama in April 2012. This means that we have lesser SEC-reporting company requirements than we would otherwise have. Specifically, Emerging Growth Companies are subject to the following lower reporting requirements:

No requirement for an independent auditor attestation as to the effectiveness of our internal controls;

No requirement to discuss our financial performance or to present supplemental financial information for periods more than two years previous;

Any future possible periodic auditor rotation requirements will not apply to us;

Our executive compensation disclosure will comply with the provisions applicable to smaller reporting companies, that is companies with less than $75 million in market capital, rather than other companies of comparable size to us;

No requirement that we seek an advisory vote from shareholders as to the approval of our executive compensation (say-on-pay);

No requirement that we seek a shareholder vote determining the frequency of shareholder advisory votes on executive compensation (say-on-pay vote frequency);

No requirement for shareholder approval of golden parachutes for our officers and directors in mergers or change-of-control transactions;

Research reports about us by a broker or dealer will not be part of our registration statement, even if the broker or dealer is participating in underwriting or selling our securities;

Our management or agents may communicate orally and in writing with qualified institutional buyers or institutional accredited investors who are prospective investors in our initial public offering (IPO) before or after our registration statement becomes effective (provided such communications are supplemented with the delivery of our annual report); and

Brokers and dealers involved with offering and selling our securities may publish research reports relating to our company at any time after our IPO and within any restrictive period on the sale of securities by our holders after the IPO.

We will lose the above-described exemptions from our reporting and shareholder approval obligations when we cease to be an Emerging Growth Company. We will cease to be an Emerging Growth Company on the last day of the fiscal year following the date of the fifth anniversary of our first sale of common equity securities under an effective registration statement or a fiscal year in which we have $1 billion in gross revenues. We will also immediately cease to be an Emerging Growth Company if the market value of our common stock held by non-affiliates exceeds $700 million or upon our issuing $1 billion or more in non-convertible debt in a three year period. Finally, we may choose to opt-out of the emerging growth company status at any time. If we opt out of emerging growth company status we may not opt back in.

No Delayed Adoption of New or Revised Accounting Standards under the Jumpstart our Business Startups Act (JOBS ACT)

The JOBS Act provides that we have the option of deferring compliance with new or revised accounting standard until such date as companies that do not file periodic reports with the SEC are required to comply with the new or revised accounting standard. We have elected not to use this provision and intend to implement new or revised accounting standards applicable to reporting issuers when such implementation is required of other reporting issuers. This election is irrevocable.

PART I

Item 1.

Description of Business.

Our Company

Starboard Resources LLC was formed 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 under the name Starboard Resources, Inc. (“Starboard”). On August 25, 2015, Starboard changed its name to Brushy Resources, Inc.

We are an independent exploration and production company focused on the operation, acquisition, development and production of both conventional and unconventional onshore oil and natural gas resources. We operate and target oil production and reserves that offer low-risk development opportunities within multiple formations utilizing horizontal drilling and multi-fracture completion technology.

Table of Contents

Our core operations are primarily focused on the oil and natural gas wells in the Permian Basin, with operations in the Delaware Basin where we control approximately 3,460 net acres (approximately 7,220 gross acres) and in the liquids rich, oil bearing window of the Eagle Ford trend of South Texas and the nearby oil-prone Giddings field where in combination we control approximately 15,260 net acres (approximately 13,970 gross acres). We also acquired the Crittendon Field and control 5,160 gross acres (2,759 net acres). We sold our non-operated properties in Logan and Kingfisher Counties, Oklahoma in July 2015, which consisted of 1,229 net acres (5,055 gross acres). The combined estimated reserve base and net production are each approximately 60% oil-weighted.

As part of this strategy, we focused on the following areas:

Giddings – Bastrop and Bigfoot – Texas

Delaware Basin – Winkler Counties – Texas and Lea County, New Mexico

In Winkler and Loving Counties, Texas we control about 6,700 gross acres (2,953 net acres). In Lea County, New Mexico we started producing the Mexico P #1 Federal well on September 12, 2015 and now hold 520 gross acres (504.7 net acres) by production.

At January 1, 2016, based on the reserves estimate by our independent reservoir engineers, we had 1,130 MBOE of estimated proved reserves with a PV-10 of $14.7 million. At January 1, 2016, 100% of our estimated proved reserves were proved developed reserves and 59% of our estimated proved reserves were oil and condensate. Our average daily production was 543 BOE per day at year-end 2015.

As of March 9, 2016, the Company has 114 (102.9 net) company operated wells and participates in 4 (1.4 net) non-operated wells, of which 111 of these wells are oil wells and 7 are gas wells.

Proposed 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, (collectively, the “Giddings Field Assets”), 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 (the “SOSventures Credit Agreement”).

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.

Our board of directors has determined that the merger is fair to, and in the best interests of, our stockholders. In deciding to approve the merger agreement and to recommend that our stockholders vote to approve the issuance of shares of common stock in connection with the merger, our board of directors consulted with our management and legal and financial advisors and considered a variety of factors, including the following material factors:

● We are in default of several covenants of our credit facilities with Independent Bank and SOSventures and under strict deadlines imposed by the Forbearance Agreement executed November 24, 2015 (the “IB Forbearance Agreement”), which, if not met, leave little or no options for us to avoid foreclosure other than bankruptcy;

● the pre-closing terms of the merger agreement would result in the Independent Bank credit facility being paid off before the expiration of the Forbearance Agreement.

● Lilis’s strategy to focus its efforts on oil and gas properties are consistent with the location and predominant nature of our oil and gas properties are consistent with in similar areas;

Table of Contents

● all of our prospects are located in the west Texas region, specifically in the Permian Basin, which is desirable to Lilis;

● the combined company would have an important presence in two attractive areas: the Permian Basin in southwest New Mexico and west Texas, where we currently own properties, and the Denver Julesburg Basin in Wattenberg Field, Colorado, where Lilis currently owns properties and;

● the combination will increase estimated proved reserves and production;

● the complementary nature of the two companies’ respective asset bases, which is expected to permit the combined company to compete more effectively with other exploration and production companies;

● the merger would benefit us since Lilis’s estimated prospects would significantly increase by gaining access to mature geological concepts in the Permian Basin developed by our management;

● the combined company would continue to have a significant presence in the Permian Basin, which Lilis does not currently have, including in the Crittendon Field, as well as the ability to participate and jointly operate, along with a related party of Brushy, in the Giddings Field Assets;

● the combined company should have greater oil and gas exploitation and production strengths, greater liquidity in the market for its securities and should be able to pursue future strategic opportunities that might not otherwise be possible for us on our own;

● the pro forma financial condition, prospects, and opportunities of the combined company;

● the terms of the merger agreement and the structure of the merger, including the conditions to each party’s obligation to close;

● the combined entity’s market capitalization and its expected enhanced access to debt and equity capital markets, which our board of directors believes will enhance the ability to finance development and production of the combined entity’s increased scale of operations;

● sale of the Giddings Field Assets, which is required by the merger agreement, will relieve $21,100,000 in liability owed to SOSventures pursuant to the SOSventures Credit Agreement;

● the merger will create a larger company that is expected to have more liquidity in its common stock and better access to capital markets, which should provide greater financial flexibility; and

● the structure of the merger is expected to constitute a reorganization under section 368(a) of the Internal Revenue Code.

Our board of directors considered a number of additional factors concerning the merger agreement and the transactions contemplated by the merger agreement, including the merger. These factors included:

● information concerning the financial condition, results of operations, prospects, and businesses of Brushy and Lilis, including the respective companies’ reserves, production volumes, cash flows from operations, recent performance of common stock, and the ratio of our common stock price to the fair value of Lilis’s common stock over various periods, as well as current industry, economic, and market conditions;

● the Fairness Opinions produced by ROTH Capital Partners (“ROTH”);

● the net asset value per share of the common stock of both Brushy and Lilis;

● that the percentage ownership of our current stockholders will be reduced to approximately 50% of the then-outstanding shares of our capital stock as a result of the merger;

● that there are significant risks inherent in combining and integrating two companies, including that the companies may not be successfully integrated and that successful integration of the companies will require the dedication of significant management resources, which will temporarily detract attention from the day-to-day businesses of the combined company;

● the effects on net asset value, cash flows from operations, and other financial measures under various modeling assumptions and the uncertainties in timing with respect to some anticipated benefits of the merger;

● that the merger agreement imposes limitations on our ability to solicit offers for the acquisition of Brushy, as well as the possibility that we could be required to pay to Lilis a termination fee of $1,200,000 in certain circumstances;

● that the capital requirements necessary to achieve the expected growth of the combined company’s business will be significant, and there can be no assurance that the combined company will be able to fund all of its capital requirements from operating cash flows;

● that the merger might not be closed as a result of a failure to satisfy the conditions contained in the merger agreement;

● if oil or gas prices decrease, the combined assets will be less desirable from a financial point of view; and

● that the merger required Lilis to pay $2,000,000 upfront in the form of a refundable deposit and that such refundable deposit may not actually be refundable if certain unfavorable events were to occur, such as the bankruptcy, liquidation or dissolution of Brushy; and

In view of the wide variety of factors considered by our board of directors in evaluating the merger agreement and the transactions contemplated by it, including the merger, and the complexity of these matters, our board of directors did not find it practicable to, and did not attempt to, quantify, rank, or otherwise assign relative weight to those factors.

It should be noted that this explanation of the reasoning of our board of directors and all other information presented in this section is forward-looking in nature and, therefore, should be read in light of the factors discussed under the heading “Cautionary Statement Concerning Forward-Looking Statements.”

Table of Contents

General Corporate Information

Our principal executive offices are located at 300 E. Sonterra Blvd, Suite 1220, San Antonio, TX 78258, and our telephone number at that address is (210) 999-5400. Additional information can be found on our website: www.starboardresources.com. Information on our website or any other website is not incorporated by reference herein and does not constitute a part of this annual report.

Employees

As of December 31, 2015, we had 13 full time employees. We are not a party to any collective bargaining agreements and have not experienced any strikes or work stoppages. We believe our relationships with our employees are good. From time to time, we utilize the services of independent contractors to perform various field and other services.

Our Business Strategy

Our goal is to increase stockholder value by building reserves, production and cash flows at an attractive return on invested capital, while continuing to drill out our existing reserve base. We seek to achieve our goals through the following strategies:

Develop non-producing properties (“PDNPs”) and proven undeveloped reserves (“PUDs”) in core areas located in Texas, New Mexico and Oklahoma. We have established core acreage positions in Texas where we have built up a drilling inventory throughout oil-rich plays. Since the majority of our acreage is held by production, we have the flexibility to develop our acreage in a disciplined manner in order to maximize economics, as well as resource recovery from the assets. Our development and production projects are economic at current commodity prices. However, we currently do not have sufficient capital to develop our reserves. If we can obtain new financing and our projects remain economic, we will continue to exploit these opportunities.

Optimize our vertical drilling program and capture potential horizontal development opportunities. We believe opportunities for increased well density exist across our acreage base for both our horizontal and vertical drilling programs and that horizontal drilling may be economical in areas where vertical drilling is currently not economical or logistically viable. We intend to target multiple benches within the Delaware Basin with horizontal wells and believe our horizontal drilling program may significantly increase our recoveries per section as compared to drilling vertical wells alone.

Maintain our financial discipline and flexibility. As an operator, we leverage advanced technologies and integrate the experience of our management and technical teams. We believe our team demonstrates financial discipline that is achieved by our approach to evaluating and analyzing prospects, along with prior drilling and completion results, before allocating capital. This discipline is reflected in the improvements our team has attained on reducing overall unit costs. When we are not the operator, we proactively engage with the operators in an effort to ensure similar financial discipline. Additionally, we conduct our own internal geological and engineering studies on these prospects and provide input on the drilling, completion and operation of many of these non-operated wells pursuant to our agreements and relationships with the operators. Our management focuses on maintaining a conservative balance sheet while trying to best optimize the overall capital structure to provide the best balance of risk and return potential. We also have a hedge program in place to mitigate risks.

Pursue additional leasing and strategic acquisitions. Our management team’s familiarity with our key operating areas, experience with unique and distressed transactions, and a broad contact base across both operators and financial sponsors enable us to identify high-return acquisition opportunities at attractive prices.

Hedging Activities

Our current hedge position consists of put options and collars. 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 use entirely to hedge our production and do not enter into for speculative purposes.

At December 31, 2015, 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

Recent Activities

At the time of the extension of the forbearance period to March 31, 2016 under the 2013 Credit Agreement between us and Independent Bank, 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. For more information see “Item 7—Management Discussion & Analysis—Credit Facilities and Forbearance Agreement on page 47.

Table of Contents

Recent Developments

Liquidity and Ability to Continue as a Going Concern

As discussed under “Item 7 - Management’s Discussion and Analysis of Financial Condition and Results of Operations-Liquidity and Capital Resources,” continued low oil and natural gas prices during 2015 and into 2016 have had a significant adverse impact on our business, and, as a result of our financial condition, substantial doubt exists that we will be able to continue as a going concern.

The precipitous decline in oil and natural gas prices during 2015 and into 2016 has had a significant adverse impact on our business, and as a result of our financial condition, our registered independent public accountants have issued an opinion with an explanatory paragraph expressing substantial doubt as to our ability to continue as a “going concern.” 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. In November 2015, counsel for the lenders notified us of the following defaults under the 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 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. 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. This also cross defaulted the SOSventures Credit Agreement. During the Forbearance Period, we are not permitted to drill new oil or gas wells or to make any distributions to equity holders. Furthermore, 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 lenders 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. Furthermore, if we are unable to restructure or refinance our current obligations under our existing debt, 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 our 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 we 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.

Under certain circumstances, it is also possible that our creditors may file an involuntary petition for bankruptcy against us. Please read “Item 7-Management’s Discussion and Analysis of Financial Condition and Results of Operations-Liquidity and Capital Resources” for further discussion. Also, for additional discussion of factors that may affect our ability to continue as a going concern and the potential consequences of our failure to do so, please see “Item 1A-Risk Factors.”

Proposed Merger with Lilis Energy

On December 29, 2015, we agreed to combine our business with Lilis pursuant to the merger agreement. 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). 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. For more information on the merger please see “Description of our Business—Proposed Merger on page 5.”

Exploration and Development Activities

We have been committed to drilling both developmental and exploratory oil wells throughout our acreage. We spent $8.2 million on exploration and development activities during 2015 after spending $34.8 million in 2014. Currently, we do not expect to spend any capital on exploration and development activities in 2016, unless we are able to obtain new financing.

Table of Contents

Management’s Experience with Horizontal Drilling

The Company intends to engage in directional drilling, which includes horizontal drilling, to develop our proven undeveloped reserves, particularly in our Eagle Ford Shale play acreage. Both our CEO, Michael Pawelek, and our Chief Operating Officer, Edward Shaw, have been engaged in in directional drilling and operating wells in our target areas since 1999.

Present Activities

We recently drilled or re-entered and completed our first three wells in the Delaware Basin properties in Winkler County, Texas and Lea County, New Mexico.

We vertically re-entered and horizontally drilled, frac’ed and completed the Kudu #1H well in the Wolfcamp formation in Winkler County, Texas and started producing the well on August 12, 2015 with a peak 24-hour production rate 653 barrels of oil equivalent per day, comprised of 392 barrels of oil and 1.6 million cubic feet of natural gas flowing on a “18/64 choke at 2,500 psi up 4.5” casing.

We performed a behind-pipe completion of the vertical wellbore and completed the well with a frac in the Wolfcamp Formation for the Mexico P #1 Federal well in Lea County, New Mexico and started producing the well on September 12, 2015 with a peak 24-hour production rate of 244 barrels of oil equivalent per day, comprised of 219 barrels of oil and 0.2 million cubic feet of natural gas flowing on a “10/64 choke at 500 psi up 10.75” casing. Further the economic production of the Mexico P #1 Federal well increases our held-by-production acreage by 520 gross acres (504.7 net acres) in the Delaware Basin. We now own approximately 3,264 net acres in Winkler and Loving Counties, Texas and Lea County, New Mexico.

We vertically re-entered and horizontally drilled, frac’ed and completed the Wolfe #3H well in the Brushy Canyon formation in Winkler County Texas and installed an artificial lift on the Wolfe #3H and initial fluid production was 1,000 barrels per day. During the fourth quarter of 2015, the response has been in line with expectations with total fluid extraction increasing to 1,500 barrels per day and oil production increasing from 10 to 190 barrels of oil per day. Our management believes that this trend should continue with production increasing until it reaches the production levels typical of other Horizontal Brushy Canyon wells drilled in the area.

Any reference to “peak production” or “initial production” should not be viewed as an indication of what any of the wells are expected to produce in the long run. These production numbers stem from production under test conditions and investors should expect the peak production or initial production to decline over the long-term.

Delivery Commitments

The Company is not currently committed to providing a fixed and determinable quantity of oil or gas under any existing contract.

Major Customers

The Company sold oil and natural gas production representing more than 10% of its oil and natural gas revenues as follows:

2015:
Oil:	Texican	35	%
	First River Midstream	18	%
	Sunoco	28	%

Gas:	ETC	32	%
	DCP	38	%
	Superior	30	%

2014:
Oil:	Sunoco	72	%
	BP Products North America	12	%

Gas:	Regency	21	%
	DCP	15	%
	Superior	53	%

Table of Contents

Because alternate purchasers of oil are readily available, we believe that the loss of any of our purchasers would not have a material adverse effect on our financial results. Our agreement with Texican Crude & Hydrocarbon LLC provides that our oil will be sold at the posted prices for Sunoco West Texas intermediate crude oil for the calendar month, deemed 40.0 API gravity, plus/minus the average of Argus’s P-Plus and plus/minus ArugsLLS/WTI differential less marketing adjustment of $4.85 for the trading month.

The DCP Midstream, LP gas purchase contract for our Texas properties states that the residue gas value will be weighted average of the the price per MMBtu received by the Buyer f.o.b. Buyer’s Facilities for Residue Gas sold during the month. NGL net value will be the monthly average of the daily average prices per gallons for (i)the average of ethane in E-P mix and purity ethane, (ii) non-TET propane, (iii) non-TET isobutene, (iv) non-TET normal butane, and (v) non-TET natural gasoline (pentanes and heaver) during the month as reported for Mont Belvieu, Texas by the Oil Price Information Service less a transportation, fractionation and storage fee of $0.12 per gallon, escalated as of each January 1 beginning with 2016 by the higher of (i) 3% or (ii) the annual percentage change in in Consumer Price Index for all Urban Consumers, all items, without seasonal adjustment, as published by the Bureau of Labar Statistics of the United States Department of Labor. Further, the contract provides for the payment of (i) 85% of the net value for Reidue Gas and (ii) 85% of the net value for any NGL less (iii) $0.20 per MMBtu and less any applicable fess. The deduction will increase by 3% as of each January 1 commencing as of January 1, 2016. Further, if the Company delivers less than 25 Mcf per day at any delivery point, it will be charged a low volume fee of $350.00 per month.

First River Midstream, LLC is the oil purchaser from our Crittendon properties excluding the Kudu #1H. The contract provides that our oil will be sold at the average posting price of Phillips 66 West Texas Intermediate crude oil, at a deemed gravity of 40.0 degrees API, plus the arithmetic average of the mid-points of Argus reported prices for WTI P-Plus crude oil, plus the Argus LLS differential to WTI weighted average per barrel, less a downward adjustment of $3.00 per barrel.

ETC is the purchaser of the natural gas from our Crittendon properties, which the gas purchase contract states a price per MMBTU equal to 100% of the average of the daily midpoint for Waha and El Paso Permian (Index), less a downward adjustment of $0.49 per MMBTU.

Competition

We encounter competition from other oil and natural gas companies in all areas of our operations, including the acquisition of exploratory prospects and proven properties. Many of our competitors are large, well-established companies that have been engaged in the oil and natural gas business for much longer than we have and possess substantially larger operating staffs and greater capital resources than we do. Our ability to explore for oil and natural gas reserves and to acquire additional properties in the future will be dependent upon our ability to conduct our operations, to evaluate and select suitable properties and to consummate transactions in this highly competitive environment. We believe that our technological expertise, our exploration, land, drilling and production capabilities and the experience of our management generally enable us to compete effectively.

Marketing

Our production is marketed to third parties consistent with industry practices. Typically, oil is sold at the wellhead at field-posted prices plus a bonus and natural gas is sold under contract at a negotiated price based upon factors normally considered in the industry, such as distance from the well to the pipeline, well pressure, estimated reserves, quality of natural gas and prevailing supply and demand conditions.

Our marketing objective is to receive the highest possible wellhead price for our product. We are aided by the presence of multiple outlets near our production in Texas, New Mexico and Oklahoma. We take an active role in determining the available pipeline alternatives for each property based on historical pricing, capacity, pressure, market relationships, seasonal variances and long-term viability.

Regulation of the Oil and Natural Gas Industry

Regulation of Transportation and Sale of Oil

Sales of crude oil, condensate and natural gas liquids are not currently regulated and are made at negotiated prices. Nevertheless, Congress could reenact price controls in the future.

Our sales of crude oil are affected by the availability, terms and cost of transportation. The transportation of oil in common carrier pipelines is also subject to rate regulation. The Federal Energy Regulatory Commission (“FERC”) regulates interstate oil pipeline transportation rates under the Interstate Commerce Act. Interstate oil pipeline rates are typically set based on a cost of service methodology (“Cost-Based Rates”); however, they may also be set based on the competitive market (“Market-Based Rates”) or by agreement between the pipeline and its shippers (“Settlement Rates”). Some oil pipeline rates may be increased pursuant to an index methodology, whereby the pipeline may increase its rates up to a ceiling set by reference to the Producer Price Index for Finished Goods (unless the rate increase is shown to be substantially in excess of the actual cost increases incurred by the pipeline). Intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state. Insofar as effective interstate and intrastate rates are equally applicable to all comparable shippers, we believe that the regulation of oil transportation rates will not affect our operations in any way that is of material difference from those of our competitors.

Table of Contents

Further, interstate and intrastate common carrier oil pipelines must provide service on a non-discriminatory basis. Under this open access standard, common carriers must offer service to all similarly situated shippers requesting service on the same terms and under the same rates. When oil pipelines operate at full capacity, access is governed by prorationing provisions set forth in the pipelines’ published tariffs. Accordingly, we believe that access to oil pipeline transportation services generally will be available to us to the same extent as to our competitors.

Regulation of Transportation and Sale of Natural Gas

Historically, the transportation and sale for resale of natural gas in interstate commerce have been regulated pursuant to the Natural Gas Act of 1938, the Natural Gas Policy Act of 1978 and regulations issued under those Acts by the FERC. In the past, the federal government has regulated the prices at which natural gas could be sold. While sales by producers of natural gas can currently be made at uncontrolled market prices, Congress could reenact price controls in the future.

FERC regulates interstate natural gas transportation rates and service conditions, which affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas. Since 1985, the FERC has endeavored to make natural gas transportation more accessible to natural gas buyers and sellers. The interstate pipelines’ traditional role as wholesalers of natural gas has been eliminated and replaced by a structure under which pipelines provide transportation and storage service on an open access basis to others who buy and sell natural gas. Although the FERC’s orders do not directly regulate natural gas producers, they are intended to foster increased competition within all phases of the natural gas industry.

We cannot accurately predict whether the FERC’s actions will achieve the goal of increasing competition in markets in which our natural gas is sold. Additional proposals and proceedings that might affect the natural gas industry are pending before the FERC and the courts. The natural gas industry historically has been very heavily regulated. Therefore, we cannot provide any assurance that the less stringent regulatory approach recently established by the FERC will continue. However, we do not believe that any action taken will affect us in a way that materially differs from the way it affects other natural gas producers.

Gathering service, which occurs upstream of jurisdictional transmission services, is regulated by the states on shore and in state waters. Although its policy is still in flux, FERC has reclassified certain jurisdictional transmission facilities as non-jurisdictional gathering facilities, which has the tendency to increase our costs of getting natural gas to point of sale locations.

Intrastate natural gas transportation is also subject to regulation by state regulatory agencies. The basis for intrastate regulation of natural gas transportation and the degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline rates and services varies from state to state. Insofar as such regulation within a particular state will generally affect all intrastate natural gas shippers within the state on a comparable basis, we believe that the regulation of similarly situated intrastate natural gas transportation in any states in which we operate and ship natural gas on an intrastate basis will not affect our operations in any way that is of material difference from those of our competitors. Like the regulation of interstate transportation rates, the regulation of intrastate transportation rates affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas.

Regulation of Production

The production of oil and natural gas is subject to regulation under a wide range of local, state and federal statutes, rules, orders and regulations. Federal, state and local statutes and regulations require permits for drilling operations, drilling bonds and reports concerning operations. All of the states in which we own and operate properties have regulations governing conservation matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum allowable rates of production from oil and natural gas wells, the regulation of well spacing, and plugging and abandonment of wells. The effect of these regulations is to limit the amount of oil and natural gas that we can produce from our wells and to limit the number of wells or the locations at which we can drill, although we can apply for exceptions to such regulations or to have reductions in well spacing. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and natural gas liquids within its jurisdiction. The failure to comply with these rules and regulations can result in substantial penalties. Our competitors in the oil and natural gas industry are subject to the same regulatory requirements and restrictions that affect our operations.

Table of Contents

Environmental Matters and Other Regulation

General

Our operations are subject to stringent and complex federal, state and local laws and regulations governing environmental protection as well as the discharge of materials into the environment. These laws and regulations may, among other things:

require the acquisition of various permits before drilling commences;

restrict the types, quantities and concentration of various substances that can be released into the environment in connection with oil and natural gas drilling and production activities;

limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas; and

require remedial measures to mitigate pollution from former and ongoing operations, such as requirements to close pits and plug abandoned wells.

These laws and regulations may also restrict the rate of oil and natural gas production below the rate that would otherwise be possible. The regulatory burden on the oil and gas industry increases the cost of doing business in the industry and consequently affects profitability. Additionally, Congress and federal and state agencies frequently revise environmental laws and regulations, and any changes that result in more stringent and costly waste handling, disposal and cleanup requirements for the oil and gas industry could have a significant impact on our operating costs. The following is a summary of some of the existing laws, rules and regulations to which our business operations are subject.

Waste Handling

The Resource Conservation and Recovery Act, or RCRA, and comparable state statutes, regulate the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. Under the auspices of the federal Environmental Protection Agency, or EPA, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Drilling fluids, produced waters and most of the other wastes associated with the exploration, development and production of crude oil or natural gas are not currently regulated under RCRA or state hazardous waste provisions though our operations may produce waste that do not fall within this exemption. However, these oil and gas production wastes may be regulated as solid waste under state law or RCRA. It is possible that certain oil and natural gas exploration and production wastes now classified as non-hazardous could be classified as hazardous wastes in the future. Any such change could result in an increase in our costs to manage and dispose of wastes, which could have a material adverse effect on our results of operations and financial position.

Comprehensive Environmental Response, Compensation, and Liability Act

The Comprehensive Environmental Response, Compensation, and Liability Act, or CERCLA, also known as the Superfund Law, imposes joint and several liability, without regard to fault or legality of conduct, on classes of persons who are considered to be responsible for the release of a hazardous substance into the environment. These persons include the current or former owner or operator of the site where the release occurred and anyone who disposed or arranged for the disposal of a hazardous substance released at the site. Under CERCLA, such persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment.

In the course of our operations, we generate wastes that may fall within CERCLA’s definition of hazardous substances. Further, we currently own, lease or operate properties that have been used for oil and natural gas exploration and production for many years. Hazardous substances or petroleum may have been released on, at or under the properties owned, leased or operated by us, or on, at or under other locations, including off-site locations, where such hazardous substances or other wastes have been taken for disposal. In addition, some of our properties have been operated by third parties or by previous owners or operators whose handling, treatment and disposal of hazardous substances, petroleum, or other materials or wastes were not under our control. These properties and the substances or materials disposed or released on, at or under them may be subject to CERCLA, RCRA or analogous or other state laws. Under such laws, we could be required to remove previously disposed substances and wastes or released petroleum, remediate contaminated property or perform remedial plugging or pit closure operations to prevent future contamination.

Water Discharges

The Federal Water Pollution Control Act, or the Clean Water Act, and analogous state laws, impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of oil and other substances into waters of the United States or state waters. Under these laws, the discharge of pollutants into regulated waters is prohibited except in accordance with the terms of a permit issued by EPA or an analogous state agency. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations.

The Oil Pollution Act of 1990, or OPA, which amends and augments the Clean Water Act, establishes strict liability for owners and operators of facilities that are the site of a release of oil into waters of the United States. In addition, OPA and regulations promulgated pursuant thereto impose a variety of regulations on responsible parties related to the prevention of oil spills and liability for damages resulting from such spills. OPA also requires certain oil and natural gas operators to develop, implement and maintain facility response plans, conduct annual spill training for certain employees and provide varying degrees of financial assurance.

Table of Contents

Air Emissions

The Federal Clean Air Act and comparable state laws regulate emissions of various air pollutants through air emissions permitting programs and the imposition of other requirements. In addition, EPA has developed and continues to develop stringent regulations governing emissions of toxic air pollutants at specified sources. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the Federal Clean Air Act and associated state laws and regulations. Oil and gas operations may in certain circumstances and locations be subject to permits and restrictions under these statutes for emissions of air pollutants, including volatile organic compounds, nitrous oxides, and hydrogen sulfide.

Climate Change

In response to findings that emissions of carbon dioxide, methane and other greenhouse gases present an endangerment to public health and the environment because emissions of such gases are contributing to warming of the earth’s atmosphere and other climatic changes, the EPA had adopted regulations under existing provisions of the federal Clean Air Act that would require a reduction in emissions of greenhouse gases, from motor vehicles and, also, could trigger permit review for greenhouse gas emissions from certain stationary sources. The EPA has asserted that the motor vehicle greenhouse gas emission standards triggered Clean Air Act construction and operating permit requirements for stationary sources, commencing when the motor vehicle standards took effect on January 2, 2011. The EPA published its final rule to address the permitting of greenhouse gas emissions from stationary sources under the PSD and Title V permitting programs. This rule “tailors” these permitting programs to apply to certain stationary sources of GHG emissions in a multi-step process, with the largest sources first subject to permitting. It is widely expected that facilities required to obtain PSD permits for their greenhouse gas emissions also will be required to reduce those emissions according to “best available control technology” standards for greenhouse gases that have yet to be developed. With regards to the monitoring and reporting of greenhouse gases, on November 30, 2010, the EPA published a final rule expanding its existing greenhouse gas emissions reporting rule published in October 2009 to include onshore oil and natural gas production activities, which may include certain of our operations. In addition, both houses of Congress have actively considered legislation to reduce emissions of greenhouse gases, and almost one-half of the states have already taken legal measures to reduce emissions of greenhouse gases, primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. The adoption and implementation of any legislation or regulations imposing reporting obligations on, or limiting emissions of greenhouse gases from, our equipment and operations could require us to incur costs to reduce emissions of greenhouse gases associated with our operations or could adversely affect demand for the oil and natural gas we produce. Finally, it should be noted that some scientists have concluded that increasing concentrations of greenhouse gases in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic event; if any such effects were to occur, they could have an adverse effect on our exploration and production operations.

National Environmental Policy Act

Oil and natural gas exploration and production activities on federal lands are subject to the National Environmental Policy Act, or NEPA. NEPA requires federal agencies, including the Department of Interior, to evaluate major agency actions that have the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an Environmental Assessment that assesses the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed Environmental Impact Statement that may be made available for public review and comment. All of our current exploration and production activities, as well as proposed exploration and development plans, on federal lands require governmental permits that are subject to the requirements of NEPA. This process has the potential to delay the development of oil and natural gas projects.

Endangered Species, Wetlands and Damages to Natural Resources

Various state and federal statutes prohibit certain actions that adversely affect endangered or threatened species and their habitat, migratory birds, wetlands, and natural resources. These statutes include the Endangered Species Act, the Migratory Bird Treaty Act, the Clean Water Act and CERCLA. Where takings of or harm to species or damages to wetlands, habitat, or natural resources occur or may occur, government entities or at times private parties may act to prevent oil and gas exploration or production or seek damages to species, habitat, or natural resources resulting from filling or construction or releases of oil, wastes, hazardous substances or other regulated materials.

OSHA and Other Laws and Regulations

We are subject to the requirements of the federal Occupational Safety and Health Act (OSHA) and comparable state statutes. The OSHA hazard communication standard, the Emergency Planning and Community Right to Know Act and similar state statutes require that we organize and/or disclose information about hazardous materials stored, used or produced in our operations.

Table of Contents

Private Lawsuits

In addition to claims arising under state and federal statutes, where a release or spill of hazardous substances, oil and gas or oil and gas wastes have occurred, private parties or landowners may bring lawsuits against oil and gas companies under state law. The plaintiffs may seek property damages, personal injury damages, remediation costs or injunctions to require remediation or restoration of contaminated property, soil, groundwater or surface water. In some cases, oil and gas operations are located near populated areas and emissions or accidental releases could affect the surrounding properties and population.

Market Price of and Dividends on the Registrant’s Common Equity and Related Stockholder Matters

Market for Our Common Stock

Our common stock is not currently traded. We have no market price. Further, we have paid no dividends and do not anticipate paying dividends in the near future. We are not currently listed or quoted on an over-the-counter market or a national securities exchange. We provide no assurance that a listing or quotation will be obtained.

We have not paid any cash dividends to date, and have no intention of paying any cash dividends on our common stock in the foreseeable future. The declaration and payment of dividends is subject to the discretion of our Board of Directors, certain limitations imposed under Delaware corporation law and the consent of our lenders pursuant to the terms of our credit facilities. During the Forbearance Period we are not permitted to declare any dividends to equity holders. The timing, amount and form of dividends, if any, will depend on, among other things, our results of operations, financial condition, cash requirements and other factors deemed relevant by our Board of Directors.

Item 1A.

RISK FACTORS

An investment in our common stock is subject to numerous risks, including those listed below and described elsewhere in this annual report. You should carefully consider these risks, along with the information provided elsewhere and incorporated by reference in this annual report before investing in our common stock. You could lose all or part of your investment in our common stock.

Our independent registered public accounting firm expressed substantial doubt regarding our ability to continue as a going concern in their audit opinion for our December 31, 2015 financial statements.

Our audited financial statements for the year ended December 31, 2015 have been prepared under the assumption that we will continue as a going concern. Our independent registered public accounting firm has issued their report dated April 20, 2016, in connection with the audit of our financial statements for the year ended December 31, 2015 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 liquidity. The fact that we have received this going concern qualification from our independent registered public accounting firm will likely make it more difficult for us to raise capital on favorable terms and could hinder, to some extent, our operations. Additionally, if we are not able to continue as a going concern, it is possible stockholders may lose part or all of their investment. Our financial statements do not include any adjustments that might result from the outcome of this uncertainty.

We have been unable to comply with the restrictions and covenants in our credit facilities which has resulted in an event of default under the IB Credit Agreement, and has subjected us to a forbearance agreement.

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. This has also cross defaulted the SOSventures Credit Agreement. 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 pursuant to which the lenders agreed to forbear exercising any of its remedies for the existing covenant defaults for the Forbearance Period to permit us to seek refinancing of the indebtedness owed under the IB Credit Agreement. During the Forbearance Period, we are not permitted to drill new oil or gas wells or to make any distributions to equity holders.

In the event we do not refinance the debt during the Forbearance Period, the lenders could terminate their commitments to lend or accelerate the loans and declare all amounts borrowed due and payable. If any of these events occur, our assets might not be sufficient to repay in full all of our outstanding indebtedness and we may be unable to find alternative financing on favorable or acceptable terms to us.

We have an operating loss.

We have substantial capital requirements that, if not met, may hinder operations.

The exact amount of capital spending for 2016 will depend upon individual well performance results, cash flow and, where applicable, partner negotiations on the timing of drilling operations. We have and expect to continue to have substantial capital needs as a result of our active exploration, development, and acquisition programs. We expect that additional external financing will be required in the future to fund our growth. The Company’s Board of Directors and management team continue to take steps to try to strengthen our 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. Without additional capital resources, we may be forced to limit or defer our planned oil and natural gas exploration and development program and this will adversely affect the recoverability and ultimate value of our oil and natural gas properties, in turn negatively affecting our business, financial condition, and results of operations.

Due to our substantial liquidity concerns, we may be unable to continue as a going concern.

Our existing and future debt agreements could create issues as interest payments become due and the debt matures that will threaten our ability to continue as a going concern. If we fail to satisfy our obligations with respect to our indebtedness or fail to comply with the financial and other restrictive covenants contained in the debt agreements governing our indebtedness, an event of default could result, which would permit acceleration of such debt and which could result in an event of default under and an acceleration of our other debt and would permit our secured lenders to foreclose on any of our assets securing such debt. Any accelerated debt would become immediately due and payable. While we will attempt to take appropriate mitigating actions to refinance any indebtedness prior to its maturity or otherwise extend the maturity dates, and to cure any potential defaults, there is no assurance that any particular actions with respect to refinancing existing indebtedness, extending the maturity of existing indebtedness or curing potential defaults in our existing and future debt agreements will be sufficient. The uncertainty associated with our ability to repay our outstanding debt obligations as they become due raises substantial doubt about our ability to continue as a going concern.

Table of Contents

Our shareholder base is currently not stable because we have interpleaded 17.23% of our common stock into a Connecticut Court.

Approximately 17.23% of our 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:

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 our 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.

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.

An award was made in favor of the “Certain” respondents, including our 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:

breach of fiduciary duty;

breach of implied covenant of good faith and fair dealing;

partnership dissolution;

unjust enrichment;

breach of contract;

accounting;

violation of Connecticut Unfair Trade Practices Act;

civil theft; and

piercing the corporate veil.

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

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;

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;

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 us from the Partnerships to the limited partners in the Partnerships;

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;”

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;

Table of Contents

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 our common stock, which may result in modifying our ownership structure. While the parties to the Interpleader Action and certain other litigation have entered into a global settlement agreement pursuant to all parties to the proceedings issued mutual releases and the plaintiffs in all proceedings agreed to withdraw their claims in return for a cash settlement, the majority of which was covered by insurance, the effectiveness of the settlement is subject to the condition of either the passage of time or the consummation of the merger with Lilis.

Our success is dependent on the prices of oil and natural gas. Low oil or natural gas prices and the substantial volatility in these prices may adversely affect our financial condition and our ability to meet our capital expenditure requirements and financial obligations.

The prices we receive for our oil and natural gas heavily influence our revenue, profitability, cash flow available for capital expenditures, access to capital and future rate of growth. Oil and natural gas are commodities and, therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for oil and natural gas have been volatile. These markets will likely continue to be volatile in the future. The prices we receive for our production, and the levels of our production, depend on numerous factors. These factors include the following:

worldwide and regional economic conditions impacting the global supply and demand for oil and natural gas;

the prices and availability of competitors’ supplies of oil and natural gas;

the actions of the Organization of Petroleum Exporting Countries, or OPEC, and state-controlled oil companies relating to oil price and production controls;

the price and quantity of foreign imports;

the impact of U.S. dollar exchange rates on oil and natural gas prices;

domestic and foreign governmental regulations and taxes;

speculative trading of oil and natural gas futures contracts;

the availability, proximity and capacity of gathering and transportation systems for natural gas;

the availability of refining capacity;

the prices and availability of alternative fuel sources;

Table of Contents

weather conditions and natural disasters;

political conditions in or affecting oil and natural gas producing regions, including the Middle East and South America;

the continued threat of terrorism and the impact of military action and civil unrest;

public pressure on, and legislative and regulatory interest within, federal, state and local governments to stop, significantly limit or regulate hydraulic fracturing activities;

the level of global oil and natural gas inventories and exploration and production activity;

the impact of energy conservation efforts;

technological advances affecting energy consumption; and

overall worldwide economic conditions.

Lower oil and natural gas prices will reduce our cash flows, borrowing ability and the present value of our estimated reserves. Our exploration, development and exploitation projects require substantial capital expenditures. We may be unable to obtain needed capital or financing on satisfactory terms, which could lead to expiration of our leases or a decline in our oil and natural gas reserves. Lower oil and natural gas prices may also reduce the amount of oil and natural gas that we can produce economically and may affect our estimated proved reserves. The present value of future net revenues from our estimated proved reserves will not necessarily be the same as the current market value of our estimated oil and natural gas reserves.

Drilling for oil and natural gas is a speculative activity and involves numerous risks and substantial and uncertain costs that could adversely affect us.

Our success will depend on the success of our drilling program. Most of our prospects have completed evaluations. Other prospects are in various stages of evaluation, ranging from prospects that are ready to drill to prospects that will require substantial additional seismic data processing and interpretation and other types of technical geological evaluation. There is no way to predict in advance of drilling and testing whether any particular prospect will yield oil or natural gas in sufficient quantities to recover drilling or completion costs or to be economically viable. The use of seismic data and other technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling whether oil or natural gas will be present or, if present, whether oil or natural gas will be present in commercial quantities. We cannot assure you that the analogies we draw from available data from other wells, more fully explored prospects or producing fields will be applicable to our drilling prospects.

The budgeted costs of planning, drilling, completing and operating wells are often exceeded and such costs can increase significantly due to various complications that may arise during the drilling and operating processes. Before a well is spud, we may incur significant geological and geophysical (seismic) costs, which are incurred whether a well eventually produces commercial quantities of hydrocarbons, or is drilled at all. Exploration wells endure a much greater risk of loss than development wells. The analogies we draw from available data from other wells, more fully explored locations or producing fields may not be applicable to our drilling locations. If our actual drilling and development costs are significantly more than our estimated costs, we may not be able to continue our operations as proposed and could be forced to modify our drilling plans accordingly. Drilling for oil and natural gas involves numerous risks, including the risk that no commercially productive natural gas or oil reservoirs will be discovered. The cost of drilling, completing, and operating wells is substantial and uncertain, and drilling operations may be curtailed, delayed, or canceled as a result of a variety of factors beyond our control, including:

unexpected or adverse drilling conditions;

elevated pressure or irregularities in geologic formations;

equipment failures or accidents;

adverse weather conditions;

compliance with governmental requirements; and

shortages or delays in the availability of drilling rigs, crews, and equipment.

If we decide to drill a certain location, there is a risk that no commercially productive oil or natural gas reservoirs will be found or produced. We may drill or participate in new wells that are not productive. We may drill wells that are productive, but that do not produce sufficient net revenues to return a profit after drilling, operating and other costs. A productive well may become uneconomic if water or other deleterious substances are encountered which impair or prevent the production of oil and/or natural gas from the well. Our overall drilling success rate or our drilling success rate for activity within a particular project area may decline. Unsuccessful drilling activities could result in a significant decline in our production and revenues and materially harm our operations and financial condition by reducing our available cash and resources. There is no way to predict in advance of drilling and testing whether any particular location will yield oil or natural gas in sufficient quantities to recover exploration, drilling or completion costs or to be economically viable. Even if sufficient amounts of oil or natural gas exist, we may damage the potentially productive hydrocarbon-bearing formation or experience mechanical difficulties while drilling or completing the well, resulting in a reduction in production and reserves from the well or abandonment of the well.

Because of the risks and uncertainties of our business, our future performance in exploration and drilling may not be comparable to our historical performance.

Table of Contents

We are subject to contingencies arising from interpretations of federal and state laws and regulations affecting the oil and gas industry.

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.

We depend on successful exploration, development and acquisitions to maintain reserves and revenue in the future.

In general, the volume of production from oil and natural gas properties declines as reserves are depleted, with the rate of decline depending on reservoir characteristics. Except to the extent that we conduct successful exploration and development activities or acquire properties containing proved reserves, or both, our proved reserves will decline as reserves are produced. Our future oil and natural gas production is, therefore, highly dependent on our level of success in finding or acquiring additional reserves. Additionally, the business of exploring for, developing, or acquiring reserves is capital intensive. Recovery in our reserves, particularly undeveloped reserves, will require significant additional capital expenditures and successful drilling operations. To the extent cash flow from operations is reduced and external sources of capital become limited or unavailable, our ability to make the necessary capital investment to maintain or expand our asset base of oil and natural gas reserves would be impaired. In addition, we are dependent on finding partners for our exploratory activity. To the extent that others in the industry do not have the financial resources or choose not to participate in our exploration activities, we will be adversely affected.

Our development and exploration operations require substantial capital and we may be unable to obtain needed capital or financing on satisfactory terms or at all, which could lead to a loss of properties and a decline in our oil and natural gas reserves.

The oil and natural gas industry is capital intensive. We make and expect to continue to make substantial capital expenditures in our business and operations for the exploration for and development, production and acquisition of oil and natural gas reserves. To date, we have financed capital expenditures with the sale of our equity in 2011, a 2012 credit facility from Mutual of Omaha Bank (now replaced), a 2012 loan and 2013 credit agreement from SOSventures and a 2013 credit agreement from Independent Bank. Our credit facility with Independent Bank has a current borrowing base of $12.6 million. We have $12.6 million drawn on the facility at December 31, 2015. This credit facility is currently in default. As a result of such default, we also cross defaulted our SOSventures Credit Agreement and we are no longer permitted to make further draws and have been subject to a forbearance agreement with the lenders pursuant to which the lenders agreed to forbear exercising any of its remedies for the existing covenant defaults for a period of time to permit us to seek refinancing of the indebtedness owed.

In the near term, we intend to finance our capital expenditures with cash flow from operations, sales of non-core property assests and future issuance of debt and/or equity securities. Our cash flow from operations and access to capital are subject to a number of variables, including:

our estimated proved oil and natural gas reserves;

the amount of oil and natural gas we produce from existing wells;

the prices at which we sell our production;

the costs of developing and producing our oil and natural gas reserves;

our ability to acquire, locate and produce new reserves;

the ability and willingness of banks to lend to us; and

our ability to access the equity and debt capital markets.

We cannot assure you that our operations and other capital resources will provide cash in sufficient amounts to maintain planned or future levels of capital expenditures. Further, our actual capital expenditures in 2016 could exceed our capital expenditure budget. In the event our capital expenditure requirements at any time are greater than the amount of capital we have available, we could be required to seek additional sources of capital, which may include refinancing existing debt, joint venture partnerships, production payment financings, sales of non-core property assets, offerings of debt or equity securities or other means. We cannot assure you that we will be able to obtain debt or equity financing on terms favorable to us, or at all.

If we are unable to fund our capital requirements, we may be required to curtail our operations relating to the exploration and development of our prospects, which in turn could lead to a possible loss of properties and a decline in our oil and natural gas reserves, or may be otherwise unable to implement our development plan, complete acquisitions or otherwise take advantage of business opportunities or respond to competitive pressures, any of which could have a material adverse effect on our production, revenues and results of operations. In addition, a delay in or the failure to complete proposed or future infrastructure projects could delay or eliminate potential efficiencies and related cost savings.

Our level of indebtedness may increase and reduce our financial flexibility.

In the future, we may incur significant indebtedness in order to make future acquisitions or to develop our properties. Our level of indebtedness could affect our operations in several ways, including the following:

a significant portion of our cash flows could be used to service our indebtedness;

a high level of debt would increase our vulnerability to general adverse economic and industry conditions;

Table of Contents

the covenants contained in the agreements governing our outstanding indebtedness will limit our ability to borrow additional funds, dispose of assets, pay dividends and make certain investments;

a high level of debt may place us at a competitive disadvantage compared to our competitors that are less leveraged and therefore, may be able to take advantage of opportunities that our indebtedness would prevent us from pursuing;

our debt covenants may also affect our flexibility in planning for, and reacting to, changes in the economy and in our industry;

a high level of debt may make it more likely that a reduction in our borrowing base following a periodic redetermination could require us to repay a portion of our then-outstanding bank borrowings; and

a high level of debt may impair our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions, general corporate or other purposes.

A high level of indebtedness increases the risk that we may further default on our debt obligations. Our ability to meet our debt obligations and to reduce our level of indebtedness depends on our future performance. General economic conditions, oil and natural gas prices and financial, business and other factors affect our operations and our future performance. Many of these factors are beyond our control. We may not be able to generate sufficient cash flows to pay the interest on our debt, and future working capital, borrowings or equity financing may not be available to pay or refinance such debt. Factors that will affect our ability to raise cash through an offering of our capital stock or a refinancing of our debt include financial market conditions, the value of our assets and our performance at the time we need capital.

Our credit facilities contain restrictive covenants that may limit our ability to respond to changes in market conditions or pursue business opportunities.

Our credit facilities contain restrictive covenants that limit our ability to, among other things:

incur additional indebtedness;

create additional liens;

sell assets;

merge or consolidate with another entity;

pay dividends or make other distributions;

engage in transactions with affiliates; and

enter into certain swap agreements.

In addition, our credit facilities require us to maintain certain financial ratios and tests for which we are currently in default. Given such default, during the Forbearance Period we are not permitted to drill new oil or gas wells or make any distributions to equity holders. Thus, our failure to comply with these provisions may materially adversely affect our ability to react to changes in market conditions, take advantage of business opportunities we believe to be desirable, obtain future financing, fund needed capital expenditures or withstand a continuing or future downturn in our business.

Our borrowings under our Independent Bank revolving credit facility expose us to interest rate risk.

Our earnings are exposed to interest rate risk associated with borrowings under our Independent Bank revolving credit facility, which bear interest at a rate elected by us that is based on the prime rate with a minimum floor of 4.00% depending on the base rate used and the amount of the loan outstanding in relation to the borrowing base. As of March 31, 2016, the weighted average interest rate on outstanding borrowings under our revolving credit facility was 14.90%. If interest rates increase, so will our interest costs, which may have a material adverse effect on our results of operations and financial condition.

Table of Contents

Proposed tax and other legislation may materially impact our financial performance.

On February 9, 2016, the Obama Administration released its 2017 Budget Proposal. Targeted tax changes include: (i) a $10.25 per barrel tax on crude oil; (ii) increases in the oil spill liability trust fund financing; (iii) reinstatement of superfund taxes; and (iv) the elimination of certain fossil fuel tax preferences, such as the enhanced oil recovery credit, the credit for oil and gas produced from marginal wells, expensing of intangible drilling costs, the deduction for tertiary injectants, percentage depletion for oil and natural gas wells, and the domestic manufacturing deduction for oil and natural gas production; and (v) increasing the geological and geophysical amortization period for independent producers to seven years. Any of these tax changes could have a material impact on our financial performance.

We may have accidents, equipment failures or mechanical problems while drilling or completing wells or in production activities, which could adversely affect our business.

While we are drilling and completing wells or involved in production activities, we may have accidents or experience equipment failures or mechanical problems in a well that cause us to be unable to drill and complete the well or to continue to produce the well according to our plans. We may also damage a potentially hydrocarbon-bearing formation during drilling and completion operations. Such incidents may result in a reduction of our production and reserves from the well or in abandonment of the well.

Our estimated reserves are based on many assumptions that may prove inaccurate. Any significant inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.

No one can measure underground accumulations of oil and natural gas in an exact way. Oil and natural gas reserve engineering requires subjective estimates of underground accumulations of oil and natural gas and assumptions concerning future oil and natural gas prices, production levels, and operating and development costs. As a result, estimated quantities of proved reserves and projections of future production rates and the timing of development expenditures may prove to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves which could adversely affect our business, results of operations, financial condition and our ability to make cash distributions to our shareholders.

In order to prepare our estimates, we must project production rates and the timing of development expenditures. We must also analyze available geological, geophysical, production and engineering data. The extent, quality and reliability of this data can vary. The process also requires economic assumptions about matters such as oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. Although the reserve information contained herein is reviewed by independent reserve engineers, estimates of oil and natural gas reserves are inherently imprecise.

Further, the present value of future net cash flows from our proved reserves may not be the current market value of our estimated oil and natural gas reserves. In accordance with SEC requirements, we base the estimated discounted future net cash flows from our proved reserves on the 12-month average oil and gas index prices, calculated as the un-weighted arithmetic average for the first-day-of-the-month price for each month and costs in effect on the date of the estimate, holding the prices and costs constant throughout the life of the properties.

Actual future prices and costs may differ materially from those used in the net present value estimate, and future net present value estimates using then current prices and costs may be significantly less than the current estimate. In addition, the 10% discount factor we use when calculating discounted future net cash flows for reporting requirements in compliance with the FASB in Accounting Standards Codification (“ASC“) 932 may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and natural gas industry in general.

Our operational risk is concentrated due to our reliance on a small number of wells, operators and oil and gas purchasers.

We have concentrated operational risks both in terms of our producing oil and gas properties, the operators we use and in the purchasers of our oil and gas production. An operational failure by an operator, the decline of production from a property and the termination of a contractual agreement with an operator or purchaser would have a material negative impact on the Company. For the year ended December 31, 2015, revenues from the Company’s 118 producing wells ranged from approximately 0.007% to 9.052% of total revenues and for the year ended year ended December 31, 2014, revenues from the Company’s 139 producing wells ranged from approximately 0.003% to 2.6% of total revenues. These wells are all located in the southern region of Texas, West Texas, New Mexico and central Oklahoma, with the Company operating 97% of these wells.

Table of Contents

For the year ended December 31, 2015, the oil, natural gas, and natural gas liquids produced by the Company are sold and marketed to 10 purchasers. Oil sales to 3 purchasers accounted for 81% of the oil sales, 1 purchaser accounted for approximately 35% and the other two purchasers accounted for approximately 28% and 18% respectively. Natural gas and natural gas liquids sales to one purchaser accounted for 38% of the natural gas and natural gas liquids sales, while the other two purchasers accounted for approximately 28% and 18% respectively.

Low oil and natural gas prices may diminish the quantity and value of our estimated proven undeveloped reserves.

Under SEC requirements estimated proved reserves need to be economically producible. If the price of oil or natural gas falls to a point where certain properties cost more to develop and operate than the revenue they generate, such properties might no longer be deemed to be economically producible. SEC rules would require that such properties be removed from the estimated proved reserves in the Company’s financial statements. Such reclassifications would negatively impact on the Company’s balance sheet. Any write-down would constitute a non-cash charge to earnings and could have a material adverse effect on our results of operations for the periods in which such charges are taken. Once incurred, a writedown of our oil and natural gas properties is not reversible at a later date. Further, this removal of estimated proved reserves may have cascading effects on the Company’s current ratio calculations in its credit facilities. The Company may be required to obtain and pledge different collateral or bring in more assets to cure prospective defaults under its credit facilities.

Seismic studies do not guarantee that hydrocarbons are present or, if present, will produce in economic quantities.

We may use seismic studies to assist us with assessing prospective drilling opportunities on our properties, as well as on properties that we may acquire. Such seismic studies are merely an interpretive tool and do not necessarily guarantee that hydrocarbons are present or if present will produce in economic quantities.

Our business is difficult to evaluate because we have a limited operating history.

We were formed in June 2011, and converted into a C corporation in June 2012. Consequently, we do not have a lengthy operating history. Our business systems have not been tested by adversity. While our management has experience with other oil and gas companies as stated below, we have little experience with our current business infrastructure. As a result, we may have a higher operational risk than an oil and gas company that has operated for many years.

In considering whether to invest in our common stock, you should consider that there is only limited historical financial and operating information available on which to base your evaluation of our performance. We were formed in June 2011 and, as a result, we have limited financial and operating information available. We face challenges and uncertainties in financial planning as a result of the unavailability of historical data and uncertainties regarding the nature, scope and results of our future activities. We may not be successful in implementing our business strategies or in completing the development of the infrastructure necessary to conduct our business as planned. In the event that our development plan and/or merger is not completed or is delayed, our operating results will be adversely affected and our operations will differ materially from the activities described in this report. As a result of industry factors or factors relating specifically to us, we may have to change our methods of conducting business, which may cause a material adverse effect on our results of operations and financial condition.

We may experience difficulty in achieving and managing future growth.

Future growth may place strains on our resources and cause us to rely more on project partners and independent contractors, possibly negatively affecting our financial condition and results of operations. Our ability to grow will depend on a number of factors, including, but not limited to:

our ability to evaluate properties;

our ability to obtain leases or options on properties which we have evaluated;

our ability to acquire additional data on other prospects;

our ability to identify and acquire new exploratory prospects;

our ability to develop existing prospects;

our ability to continue to retain and attract skilled personnel;

our ability to maintain or enter into new relationships with project partners and independent contractors;

the results of our drilling program;

hydrocarbon prices; and

our access to capital.

We may not be successful in upgrading our technical, operations, and administrative resources or in increasing our ability to internally provide certain of the services currently provided by outside sources, and we may not be able to maintain or enter into new relationships with project partners and independent contractors. Our inability to achieve or manage growth may adversely affect our financial condition and results of operations.

Table of Contents

We will not be the operator on all of our drilling locations, and, therefore, we will not be able to control the timing of exploration or development efforts, associated costs, or the rate ofproduction of any non-operated assets.

We were not the operator on 7% of our net acreage as of December 31, 2015.As we carry out our exploration and development programs, we may enter into arrangements with respect to existing or future drilling locations that result in a greater proportion of our locations being operated by others. As a result, we may have limited ability to exercise influence over the operations of the drilling locations operated by our partners. Dependence on the operator could prevent us from realizing our target returns for those locations. The success and timing of exploration and development activities operated by our partners will depend on a number of factors that will be largely outside of our control, including:

the timing and amount of capital expenditures;

the operator’s expertise and financial resources;

approval of other participants in drilling wells;

selection of technology; and

the rate of production of reserves, if any

This limited ability to exercise control over the operations of some of our drilling locations may cause a material adverse effect on our results of operations and financial condition.

A component of our growth may come through acquisitions, and our failure to identify or complete future acquisitions successfully could reduce our earnings and hamper our growth.

We may be unable to identify properties for acquisition or to make acquisitions on terms that we consider economically acceptable. There is intense competition for acquisition opportunities in our industry. Competition for acquisitions may increase the cost of, or cause us to refrain from, completing acquisitions. The completion and pursuit of acquisitions may be dependent upon, among other things, our ability to obtain debt and equity financing and, in some cases, regulatory approvals. Our ability to grow through acquisitions will require us to continue to invest in operations, financial and management information systems and to attract, retain, motivate and effectively manage our employees. The inability to manage the integration of acquisitions effectively could reduce our focus on subsequent acquisitions and current operations, and could negatively impact our results of operations and growth potential. Our financial position, results of operations and cash flows may fluctuate significantly from period to period, as a result of the completion of significant acquisitions during particular periods. If we are not successful in identifying or acquiring any material property interests, our earnings could be reduced and our growth could be restricted.

We may engage in bidding and negotiating to complete successful acquisitions. We may be required to alter or increase substantially our capitalization to finance these acquisitions through the use of cash on hand, the issuance of debt or equity securities, the sale of production payments, the sale of nonstrategic assets, the borrowing of funds or otherwise. If we were to proceed with one or more acquisitions involving the issuance of our common stock, our shareholders would suffer dilution of their interests. Furthermore, our decision to acquire properties that are substantially different in operating or geologic characteristics or geographic locations from areas with which our staff is familiar may impact our productivity in such areas.

We may purchase oil and natural gas properties with liabilities or risks that we did not know about or that we did not assess correctly, and, as a result, we could be subject to liabilities that could adversely affect our results of operations.

Before acquiring oil and natural gas properties, we estimate the reserves, future oil and natural gas prices, operating costs, potential environmental liabilities and other factors relating to the properties. However, our review involves many assumptions and estimates, and their accuracy is inherently uncertain. As a result, we may not discover all existing or potential problems associated with the properties we buy. We may not become sufficiently familiar with the properties to assess fully their deficiencies and capabilities. We do not generally perform inspections on every well or property, and we may not be able to observe mechanical and environmental problems even when we conduct an inspection. The seller may not be willing or financially able to give us contractual protection against any identified problems, and we may decide to assume environmental and other liabilities in connection with properties we acquire. If we acquire properties with risks or liabilities we did not know about or that we did not assess correctly, our financial condition, results of operations and cash flows could be adversely affected as we settle claims and incur cleanup costs related to these liabilities.

The marketability of our production is dependent upon oil and natural gas gathering and transportation facilities owned and operated by third parties, and the unavailability of satisfactory oil and natural gas transportation arrangements would have a material adverse effect on our revenue.

The unavailability of satisfactory oil and natural gas transportation arrangements may hinder our access to oil and natural gas markets or delay production from our wells. The availability of a ready market for our oil and natural gas production depends on a number of factors, including the demand for, and supply of, oil and natural gas and the proximity of estimated reserves to pipelines and terminal facilities. Our ability to market our production depends in substantial part on the availability and capacity of gathering systems, pipelines and processing facilities owned and operated by third parties. Our failure to obtain these services on acceptable terms could materially harm our business. We may be required to shut-in wells for lack of a market or because of inadequacy or unavailability of pipeline or gathering system capacity. If that were to occur, we would be unable to realize revenue from those wells until production arrangements were made to deliver our production to market. Furthermore, if we were required to shut-in wells we might also be obligated to pay shut-in royalties to certain mineral interest owners in order to maintain our leases. The disruption of third party facilities due to maintenance and/or weather could negatively impact our ability to market and deliver our products. These third parties control when or if such facilities are restored and what prices will be charged. Federal and state regulation of oil and natural gas production and transportation, tax and energy policies, changes in supply and demand, pipeline pressures, damage to or destruction of pipelines and general economic conditions could adversely affect our ability to produce, gather and transport oil and natural gas.

Table of Contents

Hedging transactions or the lack thereof, may limit our potential gains and could result in financial losses.

To manage our exposure to price risk, from time to time, we may enter into hedging arrangements, using including “costless collars,” with respect to a portion of our future production. A costless collar provides us with downside price protection through the purchase of a put option which is financed through the sale of a call option. Because the call option proceeds are used to offset the cost of the put option, this arrangement is initially “costless” to us. The goal of these and other hedges is to lock in a range of prices so as to mitigate price volatility and increase the predictability of cash flows. These transactions limit our potential gains if oil or natural gas prices rise above the maximum price established by the call option and may offer protection if prices fall below the minimum price established by the put option only to the extent of the volumes then hedged.

In addition, hedging transactions may expose us to the risk of financial loss in certain other circumstances, including instances in which our production is less than expected or the counterparties to our put and call option contracts fail to perform under the contracts.

Disruptions in the financial markets could lead to sudden changes in a counterparty’s liquidity, which could impair its ability to perform under the terms of the contracts. We are unable to predict sudden changes in a counterparty’s creditworthiness or ability to perform under contracts with us. Even if we do accurately predict sudden changes, our ability to mitigate that risk may be limited depending upon market conditions.

Furthermore, there may be times when we have not hedged our production when, in retrospect, it would have been advisable to do so. Decisions as to whether and what production volumes to hedge are difficult and depend on market conditions and our forecast of future production and oil and gas prices, and we may not always employ the optimal hedging strategy. We may employ hedging strategies in the future that differ from those that we have used in the past, and neither the continued application of our current strategies nor our use of different hedging strategies may be successful.

On April 27, 2012, the SEC and the CFTC issued final rules defining “Swap Dealer,” “Security-Based Swap Dealer,” “Major Swap Participant,” “Major Security-Based Swap Participant” and “Eligible Contract Participant.” These definitions have end-user exceptions. To the extent that the Company uses swaps to hedge its risks, it will attempt to comply with the end-user and size exceptions from these definitions. If the Company is unsuccessful in qualifying for such exceptions in any swap transaction, it may be required to maintain substantial financial reserves relating to its swap transactions and may be required to register with the SEC or CFTC as a swap dealer or participant.

Unless we replace our oil and natural gas estimated reserves, our estimated reserves and production will decline, which would adversely affect our business, financial condition and results of operations.

Unless we conduct successful development, exploitation and exploration activities or acquire properties containing estimated proved reserves, our estimated proved reserves will decline as those reserves are produced. Producing oil and natural gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Our estimated future oil and natural gas reserves and production, and therefore our cash flows and income, are highly dependent on our success in efficiently developing and exploiting our current estimated reserves and economically finding or acquiring additional estimated recoverable reserves. We may not be able to develop, exploit, find or acquire additional reserves to replace our current and future production at acceptable costs. If we are unable to replace our current and future production, the value of our estimated reserves will decrease, and our business, financial condition and results of operations would be adversely affected.

The unavailability or high cost of additional drilling rigs, equipment, supplies, personnel and oilfield services could adversely affect our ability to execute our exploration and development plans within our budget and on a timely basis.

Shortages or the high cost of drilling rigs, equipment, supplies, personnel or oilfield services could delay or adversely affect our development and exploration operations or cause us to incur significant expenditures that are not provided for in our capital budget, which could have a material adverse effect on our business, financial condition or results of operations.

Market conditions or operational impediments may hinder our access to oil and natural gas markets or delay our production.

Market conditions or the unavailability of satisfactory oil and natural gas transportation arrangements may hinder our access to oil and natural gas markets or delay our production. The availability of a ready market for our oil and natural gas production depends on a number of factors, including the demand for and supply of oil and natural gas and the proximity of estimated reserves to pipelines and terminal facilities. Our ability to market our production depends, in substantial part, on the availability and capacity of gathering systems, pipelines and processing facilities owned and operated by third-parties. Our failure to obtain such services on acceptable terms could materially harm our business. We may be required to shut in wells due to lack of a market or inadequacy or unavailability of crude oil or natural gas pipelines or gathering system capacity. If our production becomes shut-in for any of these or other reasons, we would be unable to realize revenue from those wells until other arrangements were made to deliver the products to market.

Table of Contents

We may incur substantial losses and be subject to substantial liability claims as a result of our oil and natural gas operations. Additionally, we may not be insured for, or our insurance may be inadequate to protect us against, these risks.

We are not insured against all risks. Losses and liabilities arising from uninsured and underinsured events could materially and adversely affect our business, financial condition or results of operations. Our oil and natural gas exploration and production activities are subject to all of the operating risks associated with drilling for and producing oil and natural gas, including the possibility of:

environmental hazards, such as uncontrollable flows of oil, natural gas, brine, well fluids, toxic gas or other pollution into the environment, including groundwater and shoreline contamination;

abnormally pressured formations;

mechanical difficulties, such as stuck oilfield drilling and service tools and casing collapse;

personal injuries and death; and

natural disasters.

Any of these risks could adversely affect our ability to conduct operations or result in substantial losses to us as a result of:

injury or loss of life;

damage to and destruction of property, natural resources and equipment;

pollution and other environmental damage;

regulatory investigations and penalties;

suspension of our operations; and

repair and remediation costs.

We may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. The occurrence of an event that is not fully covered by insurance could have a material adverse effect on our business, financial condition and results of operations.

Drilling locations that we decide to drill may not yield oil or natural gas in commercially viable quantities.

We describe some of our drilling locations and our plans to explore those drilling locations in this report. Our drilling locations are in various stages of evaluation, ranging from a location which is ready to drill to a location that will require substantial additional interpretation. There is no way to predict in advance of drilling and testing whether any particular location will yield oil or natural gas in sufficient quantities to recover drilling or completion costs or to be economically viable. The use of technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling whether oil or natural gas will be present or, if present, whether oil or natural gas will be present in sufficient quantities to be economically viable. Even if sufficient amounts of oil or natural gas exist, we may damage the potentially productive hydrocarbon bearing formation or experience mechanical difficulties while drilling or completing the well, resulting in a reduction in production from the well or abandonment of the well. If we drill additional wells that we identify as dry holes in our current and future drilling locations, our drilling success rate may decline and materially harm our business. We cannot assure you that the analogies we draw from available data from other wells, more fully explored locations or producing fields will be applicable to our drilling locations. In sum, the cost of drilling, completing and operating any well is often uncertain, and new wells may not be productive.

We are subject to government regulation and liability, including complex environmental laws, which could require significant expenditures.

The exploration, development, production and sale of oil and natural gas in the United States are subject to many federal, state and local laws, rules and regulations, including complex environmental laws and regulations. Matters subject to regulation include discharge permits, drilling bonds, reports concerning operations, the spacing of wells, unitization and pooling of properties, taxation or environmental matters and health and safety criteria addressing worker protection. Under these laws and regulations, we may be required to make large expenditures that could materially adversely affect our financial condition, results of operations and cash flows. These expenditures could include payments for:

personal injuries;

property damage;

containment and cleanup of oil and other spills;

the management and disposal of hazardous materials;

remediation and cleanup costs; and

other environmental damages.

We do not believe that full insurance coverage for all potential damages is available at a reasonable cost. Failure to comply with these laws and regulations also may result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties, injunctive relief and/or the imposition of investigatory or other remedial obligations. Laws, rules and regulations protecting the environment have changed frequently and the changes often include increasingly stringent requirements. These laws, rules and regulations may impose liability on us for environmental damage and disposal of hazardous materials even if we were not negligent or at fault. We may also be found to be liable for the conduct of others or for acts that complied with applicable laws, rules or regulations at the time we performed those acts. These laws, rules and regulations are interpreted and enforced by numerous federal and state agencies. In addition, private parties, including the owners of properties upon which our wells are drilled or the owners of properties adjacent to or in close proximity to those properties may also pursue legal actions against us based on alleged non-compliance with certain of these laws, rules and regulations.

Table of Contents

Governmental regulation and liability for environmental matters may adversely affect our business, financial condition and results of operations.

All our operations and participations are onshore in the United States. Oil and natural gas operations are subject to various federal, state, and local government regulations that may change from time to time. Matters subject to regulation include:

well locations;

drilling and completion operations and methods;

production amounts limited to below capacity;

price controls;

surface use and restoration;

fluid and waste discharge from drilling operations;

plugging and abandonment of wells (including the posting of bonds);

well spacing;

unitization and pooling of properties;

taxation, marketing, transporting and reporting production;

valuation and payment of royalties’air emissions;

groundwater use and protection;

the construction and operation of underground injection wells to dispose of produced saltwater and other non-hazardous oilfield wastes; and

the construction and operation of surface pits to contain drilling muds and other non-hazardous fluids associated with drilling operations.

Federal, state and local laws may require us to remove or remediate previously disposed wastes, including wastes disposed of or released by us or prior owners or operators in accordance with current laws or otherwise, to suspend or cease operations at contaminated areas, or to perform remedial well plugging operations or response actions to reduce the risk of future contamination. Federal laws, including the Comprehensive Environmental Response, Compensation, and Liability Act, or CERCLA, and analogous state laws impose joint and several liability, without regard to fault or legality of the original conduct, on classes of persons who are considered responsible for releases of a hazardous substance into the environment. These persons include the owner or operator of the site where the release occurred, and persons that disposed of or arranged for the disposal of hazardous substances at the site. CERCLA and analogous state laws also authorize the U.S. Environmental Protection Agency (EPA), state environmental agencies and, in some cases, third parties to take action to prevent or respond to threats to human health or the environment and to seek to recover from responsible classes of persons the costs of such actions. Other environmental laws provide for joint and several strict liabilities for remediation of releases of hazardous substances, rendering a person liable for environmental damage without regard to negligence or fault on the part of such person. In addition, we may be subject to claims alleging personal injury or property damage as a result of alleged exposure to hazardous substances such as oil and natural gas related products. As a result, we may incur substantial liabilities to third parties or governmental entities and may be required to incur substantial remediation costs.

Federal, state, and local laws and regulations relating primarily to the protection of human health and the environment apply to the development, production, handling, storage, transportation, and disposal of oil and natural gas, by-products thereof, and other substances and materials produced or used in connection with oil and natural gas operations. In addition, we may be liable for environmental damages caused by previous owners of property we purchase or lease. We also are subject to changing and extensive tax laws, the effects of which cannot be predicted. Compliance with existing, new, or modified laws and regulations could have a material adverse effect on our business, financial condition, and results of operations.

Various state governments and regional organizations comprising state governments are considering enacting new legislation and promulgating new regulations governing or restricting the emission of greenhouse gases from stationary sources such as our equipment and operations. Legislative and regulatory proposals for restricting greenhouse gas emissions or otherwise addressing climate change could require us to incur additional operating costs and could adversely affect demand for the natural gas and oil that we sell. The potential increase in our operating costs could include new or increased costs to obtain permits, operate and maintain our equipment and facilities, install new emission controls on our equipment and facilities, acquire allowances to authorize our greenhouse gas emissions, pay taxes related to our greenhouse gas emissions and administer and manage a greenhouse gas emissions program. Moreover, incentives to conserve energy or use alternative energy sources could reduce demand for natural gas and oil.

Table of Contents

We may incur losses or costs as a result of title deficiencies in the properties in which we invest.

If an examination of the title history of a property that we have purchased reveals an oil and natural gas lease has been purchased in error from a person who is not the owner of the mineral interest desired, our interest would be worthless. In such an instance, the amount paid for such oil and natural gas lease as well as any royalties paid pursuant to the terms of the lease prior to the discovery of the title defect would be lost.

Prior to the drilling of an oil and natural gas well, however, it is the normal practice in the oil and natural gas industry the operator of the well to obtain a preliminary title review of the spacing unit within which the proposed oil and natural gas well is to be drilled to ensure there are no obvious deficiencies in title to the well. Frequently, as a result of such examinations, certain curative work must be done to correct deficiencies in the marketability of the title, and such curative work entails expense. Our failure to cure any title defects may adversely impact our ability in the future to increase production and reserves. In the future, we may suffer a monetary loss from title defects or title failure. Additionally, unproved and unevaluated acreage has greater risk of title defects than developed acreage. If there are any title defects or defects in assignment of leasehold rights in properties in which we hold an interest, we will suffer a financial loss which could adversely affect our financial condition, results of operations and cash flows.

Federal and State Legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.

Hydraulic fracturing involves the injection of water, sand or other propping agents and chemicals under pressure into rock formations to stimulate natural gas production. We routinely use hydraulic fracturing to produce commercial quantities of oil, liquids and natural gas. Sponsors of bills before the Senate and House of Representatives have asserted that chemicals used in the fracturing process could adversely affect drinking water supplies. Such legislation, if adopted, could increase the possibility of litigation and establish an additional level of regulation at the federal level that could lead to operational delays or increased operating costs and could, and in all likelihood would, result in additional regulatory burdens, making it more difficult to perform hydraulic fracturing operations and increasing our costs of compliance. Moreover, the U.S. Environmental Protection Agency, or EPA, is conducting a comprehensive research study on the potential adverse impacts that hydraulic fracturing may have on drinking water and groundwater. Consequently, even if federal legislation is not adopted soon or at all, the performance of the hydraulic fracturing study by the EPA could spur further action at a later date towards federal legislation and regulation of hydraulic fracturing or similar production operations.

In addition, a number of states are considering or have implemented more stringent regulatory requirements applicable to fracturing, which could include a moratorium on drilling and effectively prohibit further production of natural gas through the use of hydraulic fracturing or similar operations.

The adoption of new laws or regulations imposing reporting obligations on, or otherwise limiting, the hydraulic fracturing process could make it more difficult to complete oil and natural gas wells. In addition, if hydraulic fracturing becomes regulated at the federal level as a result of federal legislation or regulatory initiatives by the EPA, fracturing activities could become subject to additional permitting requirements, and also to attendant permitting delays and potential increases in cost, which could adversely affect our business and results of operations.

Current water regulation relating to hydraulic fracturing, particularly water source and groundwater regulation, could result in increased operational costs, operating restrictions and delays.

Hydraulic fracturing uses large amounts of water. It can require between three to five million gallons of water per horizontal well. We may face regulatory concerns in both the sourcing and the discharge of water used in hydraulic fracturing. In addition, hydraulic fracturing produces water discharges that must be treated and disposed of in accordance with applicable regulatory requirements.

First, as to sourcing water for hydraulic fracturing, we will need to secure water from the local water supply or make alternative arrangements. In order to source water from the local water supply for hydraulic fracturing we may need to pay premium rates and be subject to a lower priority if the local area becomes subject to water restrictions. We may also seek water from alternative providers supporting the hydraulic fracturing industry. If we have an insufficient water supply we will be unable to engage in hydraulic fracturing until such supply is located.

Second, hydraulic fracturing results in water discharges that must be treated and disposed of in accordance with applicable regulatory requirements. Environmental regulations governing the withdrawal, storage and use of surface water or groundwater necessary for hydraulic fracturing may increase operating costs and cause delays, interruptions or termination of operations, the extent of which cannot be predicted, all of which could have an adverse effect on our operations and financial performance. Our ability to remove and dispose of water will affect production, and the cost of water treatment and disposal may affect profitability. The imposition of new environmental initiatives and regulations could also include restrictions on our ability to conduct hydraulic fracturing or disposal of produced water, drilling fluids and other substances associated with the exploration, development and production of gas and oil.

Our business may suffer if we lose key personnel.

We depend to a large extent on the services of certain key management personnel, including Michael Pawelek, our President and Chief Executive Officer, Edward Shaw, our Chief Operating Officer and our other executive officers and key employees. These individuals have extensive experience and expertise in evaluating and analyzing producing oil and natural gas properties and drilling prospects, maximizing production from oil and natural gas properties, marketing oil and natural gas production and developing and executing financing and hedging strategies. The loss of any of these individuals could have a material adverse effect on our operations. We do not maintain key-man life insurance with respect to any of our employees. Our success will be dependent on our ability to continue to employ and retain skilled technical personnel.

Table of Contents

We have an active Board of Directors that meets several times throughout the year and is intimately involved in our business and the determination of our operational strategies. Members of our Board work closely with management to identify potential prospects, acquisitions and areas for further development. Some of our directors have been involved with us since our inception and have a deep understanding of our operations and culture. If any of our directors resign or become unable to continue in their present role, it may be difficult to find replacements with the same knowledge and experience and as a result, our operations may be adversely affected.

Competition in the oil and natural gas industry is intense making it more difficult for us to acquire properties, market natural gas and secure trained personnel.

Our ability to acquire additional prospects and to find and develop reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment for acquiring properties, marketing oil and natural gas and securing trained personnel. Also, there is substantial competition for capital available for investment in the oil and natural gas industry. Many of our competitors possess and employ financial, technical and personnel resources substantially greater than ours. Those companies may be able to pay more for productive oil and natural gas properties and exploratory prospects and to evaluate, bid for and purchase a greater number of properties and prospects than our financial or personnel resources permit. In addition, other companies may be able to offer better compensation packages to attract and retain qualified personnel than we are able to offer. The cost to attract and retain qualified personnel has increased in recent years due to competition and may increase substantially in the future. We may not be able to compete successfully in the future in acquiring prospective reserves, developing reserves, marketing hydrocarbons, attracting and retaining quality personnel and raising additional capital, which could have a material adverse effect on our business.

We may not be able to keep pace with technological developments in our industry.

The oil and natural gas industry is characterized by rapid and significant technological advancements and introductions of new products and services using new technologies. As others use or develop new technologies, we may be placed at a competitive disadvantage or competitive pressures may force us to implement those new technologies at substantial costs. In addition, other oil and natural gas companies may have greater financial, technical, and personnel resources that allow them to enjoy technological advantages and may in the future allow them to implement new technologies before we can. We may not be able to respond to these competitive pressures and implement new technologies on a timely basis or at an acceptable cost. If one or more of the technologies we use now or in the future were to become obsolete or if we are unable to use the most advanced commercially available technology, our business, financial condition, and results of operations could be materially adversely affected.

Financial difficulties encountered by our oil and natural gas purchasers, third party operators or other third parties could decrease our cash flow from operations and adversely affect our exploration and development activities.

We derive essentially all of our revenues from the sale of our oil and natural gas to unaffiliated third party purchasers, independent marketing companies and mid-stream companies. Any delays in payments from our purchasers caused by financial problems encountered by them will have an immediate negative effect on our results of operations and cash flows.

Liquidity and cash flow problems encountered by our working interest co-owners or the third party operators of our non-operated properties may prevent or delay the drilling of a well or the development of a project. Our working interest co-owners may be unwilling or unable to pay their share of the costs of projects as they become due. In the case of a working interest owner, we could be required to pay the working interest owner’s share of the project costs. We cannot assure you that we would be able to obtain the capital necessary to fund these contingencies.

We may not have enough insurance to cover all of the risks we face and operators of prospects in which we participate may not maintain or may fail to obtain adequate insurance.

In accordance with customary industry practices, we maintain insurance coverage against some, but not all, potential losses in order to protect against the risks we face. We do not carry business interruption insurance. We may elect not to carry insurance if our management believes that the cost of available insurance is excessive relative to the risks presented. In addition, we cannot insure fully against pollution and environmental risks. The occurrence of an event not fully covered by insurance could have a material adverse effect on our financial condition and results of operations. The impact of hurricanes in the areas where we operate has resulted in escalating insurance costs and less favorable coverage terms.

Oil and natural gas operations are subject to particular hazards incident to the drilling and production of oil and natural gas, such as blowouts, cratering, explosions, uncontrollable flows of oil, natural gas or well fluids, fires and pollution and other environmental risks. These hazards can cause personal injury and loss of life, severe damage to and destruction of property and equipment, pollution or environmental damage and suspension of operation. We do not operate all of the properties in which we have an interest. In the projects in which we own a non-operating interest directly, the operator for the prospect maintains insurance of various types to cover our operations with policy limits and retention liability customary in the industry. We believe the coverage and types of insurance are adequate. The occurrence of a significant adverse event that is not fully covered by insurance could result in the loss of our total investment in a particular prospect which could have a material adverse effect on our financial condition and results of operations.

Table of Contents

Our producing properties are located in regions which make us vulnerable to risks associated with operating in one major contiguous geographic area, including the risk of damage or business interruptions from hurricanes.

Our properties are located onshore in Texas, Oklahoma and New Mexico. As a result of this geographic concentration, we are disproportionately affected by any delays or interruptions in production or transportation in these areas caused by governmental regulation, transportation capacity constraints, natural disasters, regional price fluctuations or other factors. Such disturbances have in the past and will in the future have any or all of the following adverse effects on our business:

interruptions to our operations as we suspend production in advance of an approaching storm;

damage to our facilities and equipment, including damage that disrupts or delays our production;

disruption to the transportation systems we rely upon to deliver our products to our customers; and

damage to or disruption of our customers’ facilities that prevents us from taking delivery of our products.

Our identified drilling locations are scheduled out over several years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.

Our management has specifically identified and scheduled drilling locations as an estimation of our future multi-year drilling activities on our existing acreage. These scheduled drilling locations represent a significant component of our growth strategy. Our ability to drill and develop these locations depends on a number of uncertainties, including oil and natural gas prices, the availability of capital, costs, drilling results, regulatory approvals and other factors. Because of these uncertainties, we do not know if the potential drilling locations we have identified will ever be drilled or if we will be able to produce oil or natural gas from these or any other potential drilling locations. As such, our actual drilling activities may materially differ from those presently identified, which could adversely affect our business.

Market conditions or operational impediments may hinder our access to oil and natural gas markets or delay our production.

Market conditions or the unavailability of satisfactory oil and natural gas transportation arrangements may hinder our access to oil and natural gas markets or delay our production. The availability of a ready market for our oil and natural gas production depends on a number of factors, including the demand for and supply of oil and natural gas and the proximity of our reserves to pipelines and terminal facilities. Our ability to market our production depends in substantial part on the availability and capacity of transport vessels, gathering systems, pipelines and processing facilities owned and operated by third parties under interruptible or short-term transportation agreements. Under the interruptible transportation agreements, the transportation of our natural gas may be interrupted due to capacity constraints on the applicable system, for maintenance or repair of the system, or for other reasons as dictated by the particular agreements. Our failure to obtain such services on acceptable terms could materially harm our business. We may be required to shut in wells due to lack of a market or the inadequacy or unavailability of natural gas pipeline or gathering system capacity. If that were to occur, we would be unable to realize revenue from those wells unless and until we made arrangements for delivery of their production to market.

Terrorist attacks aimed at our energy operations could adversely affect our business.

The continued threat of terrorism and the impact of military and other government action have led and may lead to further increased volatility in prices for oil and natural gas and could affect these commodity markets or the financial markets used by us. In addition, the U.S. government has issued warnings that energy assets may be a future target of terrorist organizations. These developments have subjected our oil and natural gas operations to increased risks. Any future terrorist attack on our facilities, those of our customers, the infrastructure we depend on for transportation of our products, and, in some cases, those of other energy companies, could have a material adverse effect on our business.

We do not anticipate an immediate market for our shares.

We have not yet obtained an exchange listing or an over-the-counter quotation which are pre-requisites to liquidity for our common stock shares. Further, 17.2348% of our common stock shares are subject to a lawsuit described above in the Connecticut Superior Court for the Judicial District of Stamford/Norwalk at Stamford. Consequently, even if we obtain an exchange listing or over-the-counter quotation, our common stock shares’ liquidity will be materially limited by the unavailability of these shares. Moreover, we currently have only twenty-eight stockholders (plus 2,190,891 common stock shares interplead into the Court in Henry et al. v. Imbruce et al.). Stock purchase and sale decisions by these stockholders will have a material impact on our common stock shares’ liquidity.

Table of Contents

The market price of our common stock may be volatile.

Should the Board of Directors approve the Company seeking an exchange listing or a price quotation for our stock, the trading price of our stock and the price at which we may sell stock in the future are subject to large fluctuations in response to any of the following:

limited trading volume in our common stock;

quarterly variations in operating results;

our involvement in litigation;

general financial market conditions;

the prices of oil and natural gas;

announcements by us and our competitors;

our liquidity;

our ability to raise additional funds;

changes in government regulations; and

other events

We do not intend to pay dividends on our stock.

We have not historically paid dividends on our stock, cash or otherwise, and do not intend to in the foreseeable future. Further, during the Forbearance Period, we are not permitted to make distributions to our equity holders.

Provisions of Delaware law may delay or prevent transactions that would benefit stockholders.

Delaware General Corporation Law contain provisions that may have the effect of delaying, deferring or preventing a change of control of the company.

Because of these provisions, persons considering unsolicited tender offers or other unilateral takeover proposals may be more likely to negotiate with our board of directors rather than pursue non-negotiated takeover attempts. As a result, these provisions may make it more difficult for our stockholders to benefit from transactions that are opposed by an incumbent board of directors.

We may issue shares of preferred stock that could adversely affect holders of shares of our common stock.

Our board of directors may receive the power, without shareholder approval and subject to the terms of our certificate of incorporation, to set the terms of any such classes or series of shares of stock that may be issued, including voting rights, dividend rights, conversion features, preferences over shares of our common stock with respect to dividends or if we liquidate, dissolve or wind up our business and other terms. If we issue shares of preferred stock in the future that have a preference over shares of our common stock with respect to the payment of dividends or upon our liquidation, dissolution or winding up, or if we issue shares of preferred stock with voting rights that dilute the voting power of shares of our common stock, the rights of holders of shares of our common stock or the trading price of shares of our common stock could be adversely affected.

We are an “Emerging Growth Company,” and we cannot be certain if the reduced reporting requirements applicable to Emerging Growth Companies will make our common stock less attractive to investors.

We are an “Emerging Growth Company,” as defined in the Jumpstart Our Business Startups Act, or the JOBS Act. For as long as we continue to be an Emerging Growth Company, we may take advantage of exemptions from various reporting requirements that are applicable to other public companies that are not emerging growth companies, including not being required to comply with the auditor attestation requirements of Section 404 of the Sarbanes-Oxley Act, reduced disclosure obligations regarding executive compensation in our periodic reports and proxy statements and exemptions from the requirements of holding a nonbinding advisory vote on executive compensation and shareholder approval of any golden parachute payments not previously approved. We could be an Emerging Growth Company for up to five years, although circumstances could cause us to lose that status earlier, including if the market value of our common stock held by non-affiliates exceeds $700 million, if we issue $1 billion or more in non-convertible debt during the previous three-year period, or if our annual gross revenues exceed $1 billion. We would cease to be an Emerging Growth Company on the last day of the fiscal year following the date of the fifth anniversary of our first sale of common equity securities under an effective registration statement or a fiscal year in which we have $1 billion in gross revenues. We also would immediately cease to be an Emerging Growth Company if the market value of the common stock held by non-affiliates exceeds $700 million or upon our issuing $1 billion or more in non-convertible debt in a three year period. Finally, at any time we may choose to opt-out of the Emerging Growth Company reporting requirements. If we chose to opt out, we will be unable to opt back in to being an Emerging Growth Company. We cannot predict if investors will find our common stock less attractive because we may rely on these exemptions. If some investors find our common stock less attractive as a result, there may be a less active trading market for our common stock and our stock price may be more volatile.

If we are unable to implement and maintain effective internal control over financial reporting in the future, investors may lose confidence in the accuracy and completeness of our financial reports and the market price of our common stock may decline.

As a public company, we would be required to maintain internal control over financial reporting and to report any material weaknesses in such internal control. Further, we will be required to report any changes in internal controls on a quarterly basis. In addition, we would be required to furnish a report by management on the effectiveness of internal control over financial reporting pursuant to Section 404 of the Sarbanes-Oxley Act. We have been designing, implementing, and testing the internal controls over financial reporting required to comply with these obligations. In addition, our independent registered public accounting firm will be required to attest to the effectiveness of our internal control over financial reporting beginning with our annual report on Form 10-K following the date on which we are no longer an “Emerging Growth Company.” If we identify material weaknesses in our internal control over financial reporting, if we are unable to comply with the requirements of Section 404 in a timely manner or assert that our internal control over financial reporting are effective, or if our independent registered public accounting firm is unable to express an opinion as to the effectiveness of its internal control over financial reporting when required, investors may lose confidence in the accuracy and completeness of our financial reports and the market price of the common stock could be negatively affected, and we could become subject to investigations by the stock exchange on which the securities are listed, the SEC, or other regulatory authorities, which could require additional financial and management resources.

Table of Contents

In the event the merger is consummated, we will have additional resources available to us to increase the effectiveness of our internal controls, including a Chief Financial Officer, and extended management team.

As an Emerging Growth Company, our auditor is not required to attest to the effectiveness of our internal controls.

Our independent auditor is not required to attest to the effectiveness of our internal control over financial reporting while we are an Emerging Growth Company. This means that the effectiveness of our financial operations may differ from our peer companies in that they may be required to obtain independent auditor attestations as to the effectiveness of their internal controls over financial reporting and we are not. While our management will be required to attest to internal control over financial reporting and we will be required to detail changes to our internal controls on a quarterly basis, we cannot provide assurance that the independent auditor’s review process in assessing the effectiveness of our internal controls over financial reporting will not find one or more material deficiencies. Further, once we cease to be an Emerging Growth Company we will be subject to independent auditor attestation regarding the effectiveness of our internal controls over financial reporting. Even if management finds such controls to be effective, our independent auditor may decline to attest to the effectiveness of such internal controls and issue a qualified report.

As a Smaller Reporting Company we are presenting our audited financial statements and selected financial data for only a two-year period, which may not be comparable to those companies that provide audited financial statements and selected financial data for longer periods of time.

Smaller Reporting Companies need not present more than two years of audited financial statements and that they need not present selected financial data as required by SEC Regulation S-K Item 301 for periods that pre-date its audited financial statements. This selected financial data includes a table showing net sales, operating revenue, income or loss from continuing operations per common share, total assets, long-term obligations (including long-term debt, capital leases and redeemable preferred stock) and cash dividends per common share. We are providing only two years of audited financial statements and selected data.

The Company is considered a smaller reporting company and is exempt from certain disclosure requirements, which could make our stock less attractive to potential investors.

Rule 12b-2 of the Exchange Act defines a “smaller reporting company” as an issuer that is not an investment company, an asset-backed issuer), or a majority-owned subsidiary of a parent that is not a smaller reporting company and that:

Had a public float of less than $75 million as of the last business day of its most recently completed second fiscal quarter, computed by multiplying the aggregate worldwide number of shares of its voting and non-voting common equity held by non-affiliates by the price at which the common equity was last sold, or the average of the bid and asked prices of common equity, in the principal market for the common equity; or

In the case of an initial registration statement under the Securities Act or Exchange Act for shares of its common equity, had a public float of less than $75 million as of a date within 30 days of the date of the filing of the registration statement, computed by multiplying the aggregate worldwide number of such shares held by non-affiliates before the registration plus, in the case of a Securities Act registration statement, the number of such shares included in the registration statement by the estimated public offering price of the shares; or

In the case of an issuer whose public float as calculated under paragraph (1) or (2) of this definition was zero, had annual revenues of less than $50 million during the most recently completed fiscal year for which audited financial statements are available

As a “smaller reporting company” (in addition to and without regard to our status as an “emerging growth company”) we are not required and may not include a Compensation Discussion and Analysis (“CD&A”) section in our proxy statements; we provide only 2 years of financial statements; provide fewer years of selected financial data; and have other “scaled” disclosure requirements that are less comprehensive than issuers that are not “smaller reporting companies” which could make our stock less attractive to potential investors, which could make it more difficult for you to sell your shares.

Table of Contents

Our stock is likely to be a penny stock. Trading of our stock may be restricted by the Securities and Exchange Commission's penny stock regulations which may limit a stockholder's ability to buy and sell our stock.

The SEC has adopted Rule 15g-9 which generally defines “penny stock” to be any equity security that has a market price (as defined) less than $5.00 per share or an exercise price of less than $5.00 per share, subject to certain exceptions. Our securities are covered by the penny stock rules, which impose additional sales practice requirements on broker-dealers who sell to persons other than established customers and “accredited investors.” The term “accredited investor” refers generally to institutions with assets in excess of $5,000,000 or individuals with a net worth in excess of $1,000,000 or annual income exceeding $200,000 or $300,000 jointly with their spouse. The penny stock rules require a broker-dealer, prior to a transaction in a penny stock not otherwise exempt from the rules, to deliver a standardized risk disclosure document in a form prepared by the SEC which provides information about penny stocks and the nature and level of risks in the penny stock market. The broker-dealer also must provide the customer with current bid and offer quotations for the penny stock, the compensation of the broker-dealer and its salesperson in the transaction and monthly account statements showing the market value of each penny stock held in the customer's account. The bid and offer quotations, and the broker-dealer and salesperson compensation information, must be given to the customer orally or in writing prior to effecting the transaction and must be given to the customer in writing before or with the customer's confirmation. In addition, the penny stock rules require that prior to a transaction in a penny stock not otherwise exempt from these rules, the broker-dealer must make a special written determination that the penny stock is a suitable investment for the purchaser and receive the purchaser's written agreement to the transaction. These disclosure requirements may have the effect of reducing the level of trading activity in the secondary market for the stock that is subject to these penny stock rules. Consequently, these penny stock rules may affect the ability of broker-dealers to trade our securities. We believe that the penny stock rules discourage investor interest in and limit the marketability of our common stock.

The Financial Industry Regulatory Authority, or FINRA, has adopted sales practice requirements which may also limit a stockholder's ability to buy and sell our stock.

In addition to the “penny stock” rules described above, FINRA has adopted rules that require that in recommending an investment to a customer, a broker-dealer must have reasonable grounds for believing that the investment is suitable for that customer. Prior to recommending speculative low priced securities to their non-institutional customers, broker-dealers must make reasonable efforts to obtain information about the customer's financial status, tax status, investment objectives and other information. Under interpretations of these rules, FINRA believes that there is a high probability that speculative low priced securities will not be suitable for at least some customers. FINRA requirements make it more difficult for broker-dealers to recommend that their customers buy our common stock, which may limit your ability to buy and sell our stock and have an adverse effect on the market for our shares.

Risks Relating to the Proposed Merger

Because all of the merger consideration to be received by our stockholders is a fixed amount of Lilis common stock and the market price of shares of Lilis common stock will fluctuate, our stockholders cannot be sure of the aggregate value of the merger consideration they will receive.

Upon the effective time of the merger, each share of our common stock (other than dissenting shares and shares held in our treasury or owned by Lilis or any subsidiary of us or Lilis, which will be cancelled for no consideration) will be converted into the right to receive merger consideration consisting of a pro rata share of an aggregate of approximately 56,551,185 shares of Lilis common stock based on the exchange ratio contemplated by the merger agreement and the number of shares of our common stock as of December 29, 2015, which will represent approximately 50% of the shares of Lilis’s common stock outstanding immediately following the completion of the merger (without giving effect to the exercise of any outstanding options or warrants to purchase equity securities of Lilis or the Company). Because the aggregate number of shares of Lilis common stock is fixed and will not be adjusted as a result of changes in the market price of Lilis common stock, the value of the merger consideration our stockholders will receive will fluctuate with the market price of Lilis common stock. The merger agreement does not include a price-based termination right or provisions that would limit the impact of increases or decreases in the market price of Lilis common stock or adjust the portion of the merger consideration to be paid in Lilis common stock as a result of any change in the market price of shares of Lilis common stock between the date of the joint proxy statement/prospectus and the date that our stockholders receive shares of Lilis common stock in exchange for their shares of their common stock. The market price of Lilis common stock will likely be different, and may be lower, on the date our stockholders receive their shares of Lilis common stock than the market price of shares of Lilis common stock as of the date of this joint proxy statement/prospectus.

Table of Contents

During the 12-month period ended on December 31, 2015, shares of Lilis common stock traded in a range from a low of $0.07 to a high of $3.15 and ended that period at $0.20 per share. Stock price changes may result from a variety of factors, including general market and economic conditions, changes in oil and natural gas prices, changes in Lilis’s business, operations and prospects, and regulatory considerations. Many of these factors are beyond Lilis’s control. If the market price of Lilis common stock declines after our stockholders vote, they may receive less value than they expected when they voted. Neither Lilis nor the Company is permitted to terminate the merger agreement, adjust the merger consideration or resolicit the vote of our stockholders because of changes in the market price of Lilis common stock.

Current Lilis and Company stockholders will have a reduced ownership and voting interest after the merger and will exercise less influence over management of the combined company.

Lilis will issue approximately 56,551,185 shares of Lilis common stock to our stockholders in the merger. As a result, current Lilis stockholders and our current stockholders are each expected to hold approximately 50% of the shares of the combined company.

Lilis stockholders and Company stockholders currently have the right to vote for their respective board of directors and on other matters affecting the applicable company. When the merger occurs, each of our stockholders that receives shares of Lilis common stock will become a stockholder of Lilis with a percentage ownership of the combined company that is significantly smaller than the stockholder’s percentage ownership in us. Correspondingly, each Lilis stockholder will remain a stockholder of Lilis with a percentage ownership of the combined company that is significantly smaller than the stockholder’s percentage ownership of Lilis prior to the merger. As a result of these reduced ownership percentages, Lilis stockholders will have less influence on the management and policies of the combined company than they now have with respect to Lilis, and our former stockholders will have less influence on the management and policies of the combined company than they now have with respect to us.

The ability of Lilis and us to complete the merger is subject to various closing conditions, including the approval by the stockholders of both Lilis and us, and as a result, the closing of the merger may be delayed or not be completed, which could adversely affect Lilis’s and/or our business operations and stock prices.

In order for the merger to be completed, both Lilis’s stockholders and our stockholders must approve and adopt the merger agreement and related transaction proposals, which requires the affirmative vote of the holders of at least a majority of the issued and outstanding shares of Lilis common stock and our common stock. The merger agreement also contains other closing conditions. We can provide no assurance that the various closing conditions will be satisfied or waived.

The special meetings at which the Lilis stockholders and our stockholders will vote on the transactions contemplated by the merger agreement may take place before all such conditions have been satisfied or waived. As a result, if stockholder approval of the transactions contemplated by the merger agreement is obtained at such meetings, Lilis and we may make decisions after the special meetings to waive a condition or approve certain actions required to satisfy a necessary condition without seeking further stockholder approval. Such actions could have an adverse effect on the combined company.

If Lilis and we are unable to complete the merger, Lilis and we would be subject to a number of risks, including the following:

● Lilis and we would not realize the anticipated benefits of the merger, including, among other things, increased operating efficiencies;

● the attention of management of Lilis and us may have been diverted to the merger rather than to each company’s own operations and the pursuit of other opportunities that could have been beneficial to that company;

● the potential loss of key personnel during the pendency of the merger as employees may experience uncertainty about their future roles with the combined company;

● certain costs relating to the merger, including certain financial advisory, legal and accounting fees and expenses, must be paid even if the merger is not closed;

● Lilis and we will have been subject to certain restrictions on the conduct of their respective businesses, which may prevent them from making certain acquisitions or dispositions or pursuing certain business opportunities while the merger is pending; and

Table of Contents

● the trading price of Lilis common stock may decline to the extent that the current market prices reflect a market assumption that the merger will be completed.

If the merger is not completed on or before April 30, 2015, either Lilis or we 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. Lilis and we are also each required to pay the other a termination fee of $1.2 million if it terminates the merger under certain circumstances specified in the merger agreement. In addition, if the merger agreement is terminated under certain circumstances unrelated to a breach or failure to perform, as applicable, of Lilis’s representations, warranties, covenants or other agreements contained in the merger agreement or as a result of a superior proposal, we may be required to pay to Lilis an amount equal to the refundable deposit, which is $2 million.

The occurrence of any of these events individually or in combination could have a material adverse effect on the companies’ results of operations or the trading price of Lilis common stock.

The pendency of the merger could adversely affect Lilis and/or us.

Lilis and we have each agreed in the merger Agreement to refrain from taking certain actions with respect to their business and financial affairs during the pendency of the merger, which restrictions could be in place for an extended period of time if completion of the merger is delayed and could adversely impact Lilis’s and our financial condition, results of operations or cash flows.

Each of Lilis and Brushy will incur significant transaction, merger-related and restructuring costs in connection with the merger.

Lilis and we expect to incur costs associated with combining the operations of the two companies, as well as transaction fees and other costs related to the merger. The combined company also will incur restructuring and integration costs in connection with the merger. Lilis is in the early stages of assessing the magnitude of these costs and additional unanticipated costs may be incurred in the integration of the businesses of Lilis and us. The costs related to restructuring will be expensed as a cost of the ongoing results of operations of either Lilis or us or the combined company. Although Lilis and we expect that the elimination of duplicative costs, as well as the realization of other efficiencies related to the integration of the businesses, may offset incremental transaction, merger-related and restructuring costs over time, any net benefit may not be achieved in the near term, or at all. Many of these costs will be borne by Lilis and/or us even if the merger is not completed.

The merger agreement limits Lilis’s and our ability to each pursue alternatives to the merger.

The merger agreement contains provisions that could adversely impact competing proposals to acquire Lilis and us. These provisions include the prohibition on Lilis and us generally from soliciting any acquisition proposal or offer for a competing transaction and the requirement that the terminating party pay a termination fee of approximately $1.2 million in cash if the merger agreement is terminated in specified circumstances in connection with a superior proposal for an alternative transaction. In our case, this amount may be as much as $3.2 million in the case we are required to repay the refundable deposit. As a result of these restrictions, neither Lilis nor we may be able to enter into an agreement with respect to a more favorable alternative transaction without incurring potentially significant liability to the other. If such a termination fee is payable, the payment of this fee could have material and adverse consequences to the financial condition and operations of the company making such payment.

In addition, even if the board of directors of Lilis or our board of directors determines that a competing proposal to acquire the other is superior, each of Lilis and we may not exercise its right to terminate the merger agreement unless it notifies the other of its intention to do so and gives the non-terminating party at least four business days to propose revisions to the terms of the merger agreement or to make another proposal in response to the competing proposal.

Lilis and we each agreed to these provisions as a condition to the other’s willingness to enter into the merger agreement. These provisions, however, might discourage a third party that might have an interest in acquiring all or a significant part of either Lilis or us from considering or proposing that acquisition, even if that party were prepared to pay consideration with a higher value than the current proposed merger consideration. Furthermore, the termination fee may result in a potential competing acquiror proposing to pay a lower per share price to acquire Lilis or us than it might otherwise have proposed to pay.

The opinion obtained by our board of directors from its financial advisor will not reflect changes in circumstances between signing the merger agreement and the completion of the merger.

Our board of directors has not requested an updated opinion as of the date of the joint proxy statement/prospectus from ROTH, our financial advisor, nor has it obtained such an update since the board is not aware of any material changes to Lilis, the Company, or their respective businesses, results of operations or financial positions. This opinion was necessarily based on financial, economic, monetary, market and other conditions and circumstances as in effect on, and the information made available to the financial advisor as of, the date of such opinion. Developments subsequent to the date of such opinion, including changes in the operations and prospects of us or Lilis, general market and economic conditions and other factors that may be beyond the control of us and Lilis, may affect such opinion.

Table of Contents

The expected executive officers and directors of Lilis and the Company have interests in the merger that are different from, or in addition to, those of other shareholders and that could have influenced their decision to support or approve the merger.

The expected executive officers and directors after the closing of the merger of the combined company are expected to collectively beneficially own a to be determined amount of the outstanding shares of Lilis common stock after the closing of the merger. Our stockholders should recognize that some of our executive officers and board of directors as well as those of Lilis have interests in the merger that may differ from, or are in addition to, their interests as our stockholders and stockholders of Lilis.

The merger may fail to qualify as a tax-free reorganization for federal income tax purposes, resulting in your recognition of taxable gain or loss in respect of your shares of our common stock.

The merger has been structured with the intent that it qualify as a tax-free reorganization under Sections 368(a)(1)(A) and 368(a)(2)(E) of the Code. Due to the uncertainty surrounding the application of the “control test,” however, neither we nor Lilis can assure you at this time that the merger will qualify as a “reorganization” within the meaning of Section 368(a)(1)(A) and Section 368(a)(2)(E) of the Code. Further, even if Lilis and Brushy later determine to take the position that the merger so qualifies, no assurance can be given that the IRS or the courts will agree that the merger qualifies as a tax-free reorganization under Section 368(a). Further, the IRS will not provide a ruling on this matter, nor will Lilis or Brushy obtain an opinion of legal counsel as to whether the merger will constitute a tax-free reorganization for federal income tax purposes. If the merger fails to qualify as a reorganization, the merger will be fully taxable for U.S. federal income tax purposes with the consequences.

Item 2.

Properties.

We are an independent energy company based in San Antonio, Texas. We were formed in 2011 and we have been engaged in the exploration, development, acquisition and exploitation of crude oil and natural gas properties, with interests throughout Texas, New Mexico and Oklahoma. Our properties cover 22,557 gross acres, or 17,458 net acres, with a majority within the Eagle Ford trend of South Texas and the Delaware Basin of West Texas .

Our total proved reserves, based on our January 1, 2016 independent reserve estimate report, were 1,130 MBOE, consisting of 2,769 MMcf of natural gas and 669 Mbbl of oil. The PV-10 of our proved reserves at January 1, 2016 was $14.7 million based on the average of the beginning of each month prices for 2015 of $50.16 per Bbl and $2.63 per MMBtu and adjusted for location and quality differentials. At January 1, 2016, 100% of our estimated proved reserves were proved developed reserves. Our daily production at year end December 31, 2015 was 543 BOE per day.

Core Areas of Operation and Certain Key Properties

As of December 31, 2015, our proved oil and gas reserves were concentrated primarily in the Giddings and Crittendon Fields in Texas. The fields tend to have stacked multiple producing horizons. Some of the fields have numerous available wellbores capable of providing workover and recompletion opportunities. Additionally, new 3-D seismic data allows definition of numerous proved undeveloped locations throughout the fields. The characteristics of these fields allows us to identify significant resource potential behind pipe and undeveloped reserves.. At January 1, 2016, based on the reserves estimate by our independent reservoir engineers, we had 1,130 MBOE of estimated proved reserves, with 770 MBOE allocated to the Crittendon Field. At January 1, 2016, our proved developed reserves were 100% of the total proved reserves, and 60% of estimated proved reserves were oil and condensate. We sold our non-operated Oklahoma properties in Logan and Kingfisher Counties in July 2015 which consisted of 1,229 net acres (5,055 gross acres). In connection with the merger, we are obligated to convey the Giddings Field Assets to SOSventures in exchange for a release of our obligations under the SOSVentures Credit Agreement.

Giddings – Bastrop and Bigfoot – Texas

We control about 12,300 gross acres (11,000 net acres) located within the Eagle Ford trend. Giddings Field is spread across Bastrop, Burleson, Brazos, Fayette, Lee, and Gonzales counties. We also control the Bigfoot Area which is about 3,000 gross acres across Frio and Atascosa counties in southern Texas. In connection with the merger, we are obligated to convey the “Giddings Field Assets to SOSventures, in exchange for a release of our obligations under the “SOSventures Credit Agreement.

Delaware Basin – Winkler Counties – Texas and Lea County, New Mexico

Table of Contents

Oil and Natural Gas Reserves

Due to the inherent uncertainties and the limited nature of reservoir data, proved reserves are subject to change as additional information becomes available. The estimates of reserves, future cash flows and present value are based on various assumptions, including those prescribed by the SEC and are inherently imprecise. Although we believe these estimates are reasonable, actual future production, cash flows, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves may vary substantially from these estimates. Also, the use of a 10% discount factor for reporting purposes may not necessarily represent the most appropriate discount factor, given actual interest rates and risks to which our business or the oil and natural gas industry in general are subject.

These calculations were prepared using standard geological and engineering methods generally accepted by the petroleum industry and in accordance with SEC financial accounting and reporting standards. The estimated present value of proved reserves does not include indirect expenses such as general and administrative expenses, debt service, future income tax expense or depletion, depreciation, and amortization. In accordance with applicable financial accounting and reporting standards of the SEC, the estimates of our proved reserves and the present value of proved reserves set forth herein are made using the average of oil and natural gas spot prices for the West Texas Intermediate oil and Henry Hub gas on the first day of each of the twelve months during 2015. Estimated quantities of proved reserves and their present value are affected by changes in oil and natural gas prices. The arithmetic average reference prices utilized for the purpose of estimating our proved reserves and the present value of proved reserves as of January 1, 2016 were $50.16 per barrel of oil and $2.63 per MMBtu of natural gas.

The following table sets forth our estimated net total oil and natural gas reserves and the PV-10 value of such reserves as of the January 1, 2016 reserve report. The estimated reserve data and the present value as of January 1, 2016 were prepared by Forrest A. Garb & Associates, independent petroleum engineers. For further information concerning our independent engineer’s estimates of our proved reserves as of January 1, 2016. These reserves estimates were prepared in accordance with the Securities and Exchange Commission’s rules regarding oil and natural gas reserves reporting that were in effect at the time of the preparation of the reserves report. Our total estimated proved reserves are estimated using a conversion ratio of one Bbl per six Mcf. The PV-10 value is not intended to represent the current market value of the estimated oil and natural gas reserves owned by us. For further information concerning the present value of future net revenues from these reserves, see Supplemental Oil and Natural Gas Disclosure in our Financial Statements included elsewhere in this report. All reserves are located in the United States.

	Estimated Net Reserves				Estimated Future Net Revenue ($ thousands)

As of January 1, 2016	Oil and Condensate (MBbl)		Gas (MMcf)		Undiscounted		Discounted at 10% Per Year
Proved:
Developed Producing		669		2,769	$	21,143	$	14,732
Total Proved		669		2,769	$	21,143	$	14,732

We have not reported our reserves to other federal authorities or agencies.

Our reserve report dated January 1, 2016 showed the removal of all estimated net proven undeveloped reserves. The decrease in proven undeveloped reserves was due to the lack of available capital required to drill these PUD locations. Our Consolidated Statement of Cash Flows on page F-6 shows that we spent $5,101,544 on development of oil and gas properties in the year ending December 31, 2015. These payments resulted in reserve discoveries which increased our proven developed reserves for oil and condensate by 328 MBbl, while our proven developed producing natural gas reserves increased by 1,313 MMcf. The increase in proven developed BOE reserves was offset by the loss of reserves sold in the Oklahoma asset divestiture, as well as the removal of all non-producing reserves due to lack of available capital.

We believe that PV-10, a non-GAAP measure of estimated proved reserves is widely used by analysts and investors in evaluating oil and gas companies. Our reconciliation to the most directly comparable GAAP financial measure (standardized measure of discounted future net cash flows) is found in the table below. The table below provides a reconciliation of PV-10 as of January 1, 2016 and January 1, 2015 to the standardized measure of discounted future net cash flows as of December 31, 2015 and December 31, 2014:

	As of January 1, 2016		As of January 1, 2015
	($ in thousands)		($ in thousands)
PV-10	$	14,776	$	128,416
Present value of future income taxes discounted at 10%		-	$	(38,300	)
Standardized income of discounted future net cash flows	$	14,776	$	90,116

Table of Contents

Present value, or PV-10, when used in connection with oil and gas reserves, means the estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development costs, using prices calculated as the average natural gas and oil price during the preceding 12-month period prior to the end of the current reporting period, (determined as the unweighted arithmetical average of prices on the first day of each month within the 12-month period) and costs in effect at the determination date, without giving effect to non-property related expenses such as general and administrative expenses, debt service and future income tax expense or to depreciation, depletion and amortization, discounted using an annual discount rate of 10%.

Estimates of reserves as of January 1, 2016 and January 1, 2015 were prepared using an average price equal to the unweighted arithmetic average of hydrocarbon prices received on a field-by-field basis on the first day of each month within the 12-month periods ended January 1, 2016 and January 1, 2015, in accordance with revised SEC guidelines applicable to reserves estimates as of the end of 2015 and 2014. The reserve estimates represent our net revenue interest in our properties. Although we believe these estimates are reasonable, actual future production, cash flows, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves may vary substantially from these estimates.

Our proved reserve estimate report dated January 1, 2016 uses the following average adjusted prices:

Oil - $47.03 / bbl

Gas - $2.22 / Mcf

Our proved reserve estimate report dated January 1, 2015 uses the following average adjusted prices:

Oil - $91.42 / bbl

Gas - $6.53 / Mcf

The standardized measure of discounted future net cash flows relies on estimates of oil and gas reserves using commodity prices and costs at year- end. The benchmark oil and gas prices used are the preceding 12-month averages of the first-day-of-the month spot prices posted for the WTI oil and Henry Hub natural gas. Oil prices have been adjusted by lease for gravity, transportation fees, and regional price differentials. Gas prices per thousand cubic feet have been adjusted by lease for Btu content, transportation fees, and regional price differentials. The adjustments are based on the differential between historic oil and gas sales and the corresponding benchmark price.

Proved reserves are those oil and gas reserves, which, by analysis of geoscience and engineering data, can be estimated with “reasonable certainty” to be economically producible-from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations-prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain. For proved reserves, the drilling for oil and gas must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time period.

“Reasonable certainty” can be determined under two approaches. If deterministic methods are used, reasonable certainty means a “high degree of confidence” that the quantities will be recovered. A “high degree of confidence” exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to estimate ultimate recovery with time and with reasonable certainty that the estimated ultimate recovery is much more likely to increase or remain constant than to decrease. If probabilistic methods are used, reasonable certainty means at least a 90% probability that the quantities actually recovered will equal or exceed the estimate.

The reserve estimates are prepared by Forrest Garb & Associates, Inc., qualified third party engineering firms by licensed engineers as part of the Company’s internal controls. All of the Company’s reserves were subject to the reserve report by Forrest Garb & Associates, Inc. and the Company has not presented any internally-generated reserve amounts that were not included in the report from Forrest Garb & Associates, Inc. The Company’s technical person primarily responsible for overseeing the Forrest Garb & Associates, Inc. reserve estimates was Edward Shaw, our Chief Operating Officer. Mr. Shaw has been an officer of ImPetro Resources LLC since its inception in February 2010 and our Chief Operating Officer since we were formed in June 2011. Mr. Shaw was also Chief Operating Officer of South Texas Oil Company from 2005 to 2010 and headed its field operations in Texas. Thus, Mr. Shaw has extensive operational experience in the areas in which we concentrate our oil and gas operations. Mr. Shaw worked from 2000 to 2005 in New Zealand researching and developing methods of monitoring oil wells to optimize production, including using existing products integrated with emerging telemetry technologies. Mr. Shaw has a degree in electrical engineering.

Table of Contents

Oil and Natural Gas Volumes, Prices and Operating Expense

The following tables set forth certain information regarding the production volumes, revenue, average prices received and average production costs associated with our sale of oil and natural gas from continuing operations for the two years ended December 31, 2015 and 2014. The drilling operations on the Bigfoot-Texas formations in fiscal years 2015 and 2014 generally targeted drilling out the properties with shallower, less expensive wells thus holding the leases and preventing them from expiring. This means that deeper formations such as Eagle Ford and Pearsall Shales are held by production and can be developed or sold at a later date.

Bigfoot - Texas	Year Ended December 31,
	2015		2014
Net Production:
Oil (Bbl)		2,150		4,431
Natural Gas (Mcf)		0		0
Barrel of Oil Equivalent (Boe)		2,150		4,431
Oil and Natural Gas Sales:
Oil		101,569		402,705
Natural Gas		0		0
Total		101,569		402,705
Average Sales Price:
Oil ($ per Bbl)		47.24		90.89
Natural Gas ($ per Mcf)		0		0
Barrel of Oil Equivalent ($ per Boe)		47.24		90.89
Oil and Natural Gas Costs:
Lease operating expenses		175,080		322,458
Production taxes		4,595		18,267
Other operating expenses		-		-
Average production cost per Boe		83.58		76.90

Crittedon – Texas	Year Ended December 31,
	2015		2014
Net Production:
Oil (Bbl)		40,297		13,786
Natural Gas (Mcf)		217,616		202,007
Barrel of Oil Equivalent (Boe)		76,566		47,454
Oil and Natural Gas Sales:
Oil	$	1,685,038	$	1,106,900
Natural Gas		414,352		825,371
Total	$	2,099,390	$	1,932,271
Average Sales Price:
Oil ($ per Bbl)	$	41.82	$	80.29
Natural Gas ($ per Mcf)		1.90		4.09
Barrel of Oil Equivalent ($ per Boe)	$	27.42	$	40.72
Oil and Natural Gas Costs:
Lease operating expenses	$	895,735	$	1,105,331
Production taxes		115,711		101,625
Other operating expenses		-		-
Average production cost per Boe	$	13.21	$	25.43

Table of Contents

Giddings – Texas	Year Ended December 31,
	2015		2014
Net Production:
Oil (Bbl)		90,358		112,861
Natural Gas (Mcf)		249,427		169,435
Barrel of Oil Equivalent (Boe)		131,930		141,100
Oil and Natural Gas Sales:
Oil	$	4,210,379	$	10,190,042
Natural Gas		658,437		924,976
Total	$	4,868,815	$	11,115,018
Average Sales Price:
Oil ($ per Bbl)	$	46.60	$	90.29
Natural Gas ($ per Mcf)		2.64		5.46
Barrel of Oil Equivalent ($ per Boe)	$	36.90	$	78.77
Oil and Natural Gas Costs:
Lease operating expenses	$	2,341,867	$	3,729,761
Production taxes		215,526		479,201
Other operating expenses		-		-
Average production cost per Boe	$	19.38	$	29.83

Logan, Kingfisher, McClain - Oklahoma (1)	Year Ended December 31,
	2015		2014
Net Production:
Oil (Bbl)		19,468		49,820
Natural Gas (Mcf)		209,805		407,570
Barrel of Oil Equivalent (Boe)		54,435		117,749
Oil and Natural Gas Sales:
Oil	$	964,975	$	4,598,882
Natural Gas		571,857		2,123,917
Total	$	1,536,832	$	6,722,799
Average Sales Price:
Oil ($ per Bbl)	$	49.57	$	92.31
Natural Gas ($ per Mcf)		2.73		5.21
Barrel of Oil Equivalent ($ per Boe)	$	28.23	$	57.09
Oil and Natural Gas Costs:
Lease operating expenses	$	265,163	$	686,940
Production taxes		33,485		96,601
Other operating expenses		-		-
Average production cost per Boe	$	5.49	$	6.65

(1) Includes properties sold in Logan and Kingfisher Counties, Oklahoma on July 31, 2015 of 1,229 net acres (5,055 gross acres).

Exploration, Development and Acquisition Capital Expenditures

The following table sets forth certain information regarding the gross costs incurred in the purchase of proved and unproved properties and in development and exploration activities.

Bigfoot - Texas	Year Ended December 31,
	2015			2014

Unproved prospects	$	0		$	(18,843	)
Proved prospects		30			69,457
Development and exploration costs		0			0

Total consolidated operations		30			50,614

Asset Retirement Obligations (non-cash)	$	(113,369	)	$	(50,614	)

Table of Contents

Crittendon - Texas	Year Ended December 31,
	2015		2014

Unproved prospects	$	36,724	$	482,161
Proved prospects		105,845		17,007,057
Development and exploration costs		7,448,975		652,384

Total consolidated operations		7,591,544		18,141,602

Asset Retirement Obligations (non-cash)	$	5,991	$	798,572

Giddings - Texas	Year Ended December 31,
	2015		2014

Unproved prospects	$	36,772	$	1,191,710
Proved prospects		131,872		(353,988	)
Development and exploration costs		146,528		10,853,435

Total consolidated operations		315,172		11,691,157

Asset Retirement Obligations (non-cash)	$	66,110	$	54,530

Logan, Kingfisher, McClain - Oklahoma (1)	Year Ended December 31,
	2015			2014

Unproved prospects	$	0		$	193,260
Proved prospects		34,699			(3,745	)
Development and exploration costs		292,016			4,676,449

Total consolidated operations		326,715			4,865,964

Asset Retirement Obligations (non-cash)	$	(306	)	$	46,693

(1) Includes properties sold in Logan and Kingfisher Counties, Oklahoma on July 31, 2015 of 1,229 net acres (5,055 gross acres).

Producing Wells

The following table sets forth the number of producing oil and natural gas wells in which we owned an interest as of December 31, 2015 . Some wells produce both oil and natural gas.

	Company Operated				Non-Operated				Total
	Gross		Net		Gross		Net		Gross		Net
Oil		107		97.0		4		1.4		111		98.4
Natural gas		7		5.9		-		-		7		5.9
Total		114		102.9		4		1.4		118		104.3

The following table summarizes our gross and net developed and undeveloped oil and natural gas acreage under lease as of December 31, 2015.

	Developed Acres				Undeveloped Acres
	Gross		Net		Gross		Net
Bigfoot (Texas)		2,930		2,930		0		0
Crittenden Field (Texas)		5,680		3,264		1,537		194
Giddings (Texas)		9,812		8,632		2,518		2,407
McClain (Oklahoma)		80		31		0		0
Total		18,502		14,857		4,055		2,602

Table of Contents

As is customary in the oil and natural gas industry, we can generally retain our interest in undeveloped acreage by drilling activity that establishes commercial production sufficient to maintain the leases or by paying delay rentals during the remaining primary term of leases. The oil and natural gas leases in which we have an interest are for varying primary terms, and if production under a lease continues from our developed lease acreage beyond the primary term, we are entitled to hold the lease for as long as oil or natural gas is produced.

Our oil and natural gas properties consist primarily of oil and natural gas wells and our interests in leasehold acreage, both developed and undeveloped.

Drilling Activity

The following table sets forth our drilling activity during the twelve month period ended December 31, 2015 and 2014 (excluding wells in progress at the end of the period). In the table, “gross” refers to the total number of wells in which we have a working interest and “net” refers to gross wells multiplied by our working interest therein.

	Year Ended December 31,
Crittendon - Texas	2015				2014
	Gross		Net		Gross		Net
Development wells		-		-		-		-
Productive		-		-		-		-
Non-productive		-		-		-		-
Exploratory wells		-		-		-		-
Productive		2		1.6		-		-
Non-productive		-		-		-		-

	Year Ended December 31,
Giddings - Texas	2015				2014
	Gross		Net		Gross		Net
Development wells		-		-		-		-
Productive		-		-		4		3.0
Non-productive		-		-		-		-
Exploratory wells		-		-		-		-
Productive		-		-		-		-
Non-productive		-		-		-		-

	Year Ended December 31,
	2015				2014
McClain - Oklahoma	Gross		Net		Gross		Net
Development wells		-		-		-		-
Productive		1		0.4		-		-
Non-productive		-		-		-		-
Exploratory wells		-		-		-		-
Productive		-		-		-		-
Non-productive		-		-		-		-

Table of Contents

Present Activities

We recently drilled or re-entered and completed our first three wells in the Delaware Basin properties in Winkler County, Texas and Lea County, New Mexico.

Lease Expiration Summary

The following table sets forth expiration dates of the leases of our gross and net undeveloped acres as of December 31, 2015.

	Expiring Acreage (1)
	2016				2017
	Gross		Net		Gross		Net
Bigfoot (Texas)		-		-		-		-
Crittenden Field (Texas)		1,377		163		160		80
Giddings (Texas)		1,280		1,246		1,223		1,075
McClain (Oklahoma)		-		-		-		-
Total		2,657		1,409		1,383		1,155

(1) Based on contractual lease maturities. We may have the option to extend the leases prior to their expiration.

Management’s Experience with Horizontal Drilling

The Company intends to engage in directional drilling, which includes horizontal drilling, to develop our estimated proven undeveloped reserves, particularly in our Eagle Ford Shale play acreage. Our CEO, Michael Pawelek has been engaged in directional drilling and operating wells in our target areas since 1999. Our Chief Operating Officer, Edward Shaw has been engaged in directional drilling and operating wells in our target areas since 2005 and has been involved in over thirty directionally drilled wells during that period.

Delivery Commitments

The Company is not currently committed to providing a fixed and determinable quantity of oil or gas under existing contracts.

Item 3.

LEGAL PROCEEDINGS.

Lawsuit Relating to 17.23% of our Common Stock Shares

Table of Contents

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:

breach of fiduciary duty;

breach of implied covenant of good faith and fair dealing;

partnership dissolution;

unjust enrichment;

breach of contract;

accounting;

violation of Connecticut Unfair Trade Practices Act;

civil theft; and

piercing the corporate veil.

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;”

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)

11)

12)

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

13)

Table of Contents

Bexar County Proceedings

On April 17, 2015, we were 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 our 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 our 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 our assets under the SOSventures Credit Agreement and that we filed for an extension to the filing date for our 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.

Our directors and officers are subject to indemnification under our 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 our insurance.

PART II

Item 4.

Mine Safety Disclosures

N/A

Item 5.

Market for Common Equity and Related Stockholder Matters

There is no public market or exchange for the Company’s common stock.

The information in this item should be read in conjunction with the Management Discussion and Analysis of Financial Condition and Results of Operations in Item 7, and the consolidated financial statements and the related notes thereto in Item 8.

Market Information For The Common Stock

Holders

At February 1, 2016, there were 31 holders of record of common stock, plus we have interpleaded 2,190,891 common stock shares into the Connecticut Superior Court.

Dividends

We have never paid a regular cash dividend on common stock and has no plans to institute payment of regular dividends. Further, during the Forbearance Period we are not permitted to make distributions to equity holders.

Equity Compensation Plan Information

Plan Category	Number of Securities to Be Issued upon Exercise of Outstanding Options, Warrants and Rights		Weighted-Average Exercise Price of Outstanding Options, Warrants and Rights		Number of Securities Remaining Available for Future Issuance under Equity Compensation Plans (Excluding Securities Reflected in Column (a))

	(a)		(b)		(c)
Equity compensation plans approved by security holders		900,000	$	4.75		1,343,266
Equity compensation plans not approved by security holders		-		-		-
Total		900,000	$	4.75		1,343,266

Table of Contents

Recent Sales of Unregistered Securities

None.

Item 6.

Selected Financial Data

The information required in this Item is not required to be disclosed by Smaller Reporting Companies.

Item 7.

Management’s Discussion and Analysis or Plan of Operations

This section should be read in conjunction with “Note 2 — Going Concern” and “Note 9 — Notes Payable” in the Notes to the consolidated financial statements included in this annual report on Form 10-K and Item 1A “Risk Factors”. Our independent registered public accounting firm for the year ended December 31, 2015 issued their report dated April 14, 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 accumulated deficit, working capital deficit, significant net losses and need to raise additional funds to meet our obligations and sustain our operations. The discussion includes certain forward-looking statements. For a discussion of important factors which could cause actual results to differ materially from the results referred to in the forward-looking statements, see “Risk Factors” and “Cautionary Statement Concerning Forward-Looking Statements.”

Overview

We are an independent energy company engaged primarily in the exploration for, and development of, natural gas and crude oil reserves. We generate revenues and cash flows from two primary sources: investing activities and the proceeds from the sale of oil and gas production on properties we hold or participate in.

As of February 1, 2016, we own interests in 118 producing oil and natural gas wells, with 18 wells in the Crittendon Field. We operate 114 or 97% of those wells. Our oil and natural gas production for 2015 consisted of 152,273 bbls of oil and 676,847 Mcf of gas.

We began 2015 with estimated proved reserves of 5,788 MBOE with 1,432 MBOE allocated to the Crittendon Field, and ended the year with 1,130 MBOE, with 770 MBOE allocated to the Crittendon Field.

Strategy

We produce from operated oil and natural gas wells in the liquids rich, oil-bearing window of the Eagle Ford trend of South Texas and the nearby, oil-prone Giddings Field where in combination we controls 15,260 gross acres (13,970 net acres). We also operate acreage in the Delware Basin located in the Crittendon Field and controls 7,217 gross acres (3,458 net acres).

Our total proved reserves, based on our January 1, 2016 independent reserve estimate report, were 1,130 MBOE, (with 770 MBOE allocated to the Crittendon Field), consisting of 2,769 MMcf of natural gas, 669 Mbbl of oil. The PV-10 of our proved reserves at January 1, 2016 was $14.7 million based on the average of the beginning of each month prices through December 2015 of $50.16 per Bbl for oil and condensate and $2.63 per MMBtu for natural gas. At January 1, 2016, 100% of our estimated proved reserves were proved developed reserves and 59% of estimated proved reserves were oil and condensate. Our average daily production for the last month ending December 31, 2015 was 543 BOE per day.

As part of this strategy, we focused on the following areas:

Giddings – Bastrop and Bigfoot – Texas

Delaware Basin – Winkler Counties – Texas and Lea County, New Mexico

In Winkler and Loving Counties, Texas we control about 5,160 gross acres (3,264 net acres). In Lea County, New Mexico we started producing the Mexico P #1 Federal well on September 12, 2015 and now hold 520 gross acres (504.7 net acres) by production.

Results of Operations

Comparison of Year Ended December 31, 2015 to Year Ended December 31, 2014

Total Revenues. Total revenues decreased $11,566,186 to $8,606,606 for 2015 from $20,172,792 for 2014, driven primarily by decrease in oil and natural gas prices. Our average sales price received for natural gas decreased to $2.43 per Mcf for the year ended December 31, 2015 from $5.06 per Mcf for the same period in 2014. Our average sales price received for oil decreased to $45.72 per bbl for the year ended December 31, 2015 from $90.10 per bbl for the same period in 2014.

Oil and Gas Production. Total natural gas and oil production for 2015 consisted of 676,847 Mcf of natural gas and 152,273 bbls of oil, as compared to total natural gas and oil production for 2014, which consisted of 779,012 Mcf of natural gas and 180,898 bbls of oil due to primarily sale of Oklahoma properties which were located in Logan and Kingfisher Counties.

Costs and Expenses. Total costs and expenses (excluding depreciation, depletion, impairment and gain on sales) decreased $2,153,178 to $9,263,694 for 2015 from $11,416,872 for 2014, due generally to decrease production expenses. Lease operating expenses decrease $1,779,626 to $3,677,845 for 2015 from $5,457,471 for 2014, due primarily to sale of Oklahoma properties located in Logan and Kingfisher counties. Depletion, depreciation and amortization expense increased $12,370,138 to $22,510,290 for 2015 from $10,140,152 for 2014, due primarily to decrease in reserves. Impairment of oil and gas properties for 2015 was $55,753,481 compared to $4,428,378 for 2014. The increase in impairment expense is due primarily to the removal of all estimated net proven undeveloped reserves. The decrease in proven undeveloped reserves was due to the lack of available capital required to drill these PUD locations

Net Loss. Net loss was ($65,764,766) or ($5.20) per diluted common share, for 2015 as compared to ($2,760,920) or ($0.22) per diluted common share, for 2014. The increase in net loss was attributable primarily to the impairment of oil and gas properties, decrease in revenues, and increase in DD & A

Other Income (Expenses). Total other income (expenses) increased $2,724,656 to ($3,276,139) in 2015. The increase in other income (expense) was primarily driven by an increase in interest expense increased by $1,531,770 from 2014 to $4,149,251.

Table of Contents

In 2015, we invested $8.2 million in oil and gas properties. We produced 265,081 BOE during the year. In 2014, we invested $34.8 million in oil and gas properties. We produced 310,733 BOE during the year.

	Year Ended			Year Ended
Capital Costs ($000):	2015			2014
Acquisitions	$	-		$	17,671
Exploration and Development		8,233			17,163
Total CAPEX before asset retirement obligations		8,233			34,834
Asset retirement obligation costs		-			-
Total CAPEX	$	8,233		$	34,834

Asset retirement obligation (non-cash)	$	42		$	849

Proved Reserves (MBOE):
Beginning		5,788			5,091
Production		(265	)		(311	)
Purchases		-			1,433
Sale of reserves		(356	)		(139	)
Discoveries and extensions		547			614
Revisions		(4,583	)		(900	)

Ending reserves		1,130			5,788

Reserve additions before revisions (BOE)		(74	)		1,597
Reserve additions after revisions (BOE)		(4,658	)		697

The implementation of our strategy requires that we continually incur significant capital expenditures in order to replace current production and find and develop new oil and gas reserves. In order to finance our capital and exploration program, we depend on cash flow from operations, bank debt and equity offerings as discussed below in Liquidity and Capital Resources.

Oil and Gas Production

Year-over-year production decreased from 310,733 BOE for the year ended December 31, 2014 to 295,081 BOE for the year ended December 31, 2015. This decrease was due to primarily sale of Oklahoma properties which were located in Logan and Kingfisher Counties. The following table reflects the increase (decrease) in oil and gas sales revenue due to changes in price and volume:

	Years Ended December 31,
	2015		2014
Production:
Natural gas-Mcf (1)		676,847		779,012
Crude oil-bbl (2)		152,273		180,898

Average Sales Prices:
Natural gas (1)	$	2.43	$	4.97
Crude oil (2)		45.72		90.10

Revenues

Revenues from continuing operations for the year ended December 31, 2015 totaled $8,606,606 as compared to $20,172,792 for the year ended December 31, 2014 representing a decrease of $11,566,186. Production volumes for the year ended December 31, 2015 were year 152,273 bbls of oil and 676,847 Mcf of natural gas or 265,081 BOE. This compares to 180,898 bbls of oil and 779,012 Mcf of natural gas or 310,733 BOE for the year ended December 31, 2014 representing a 45,652 BOE decrease in production. For the year ended December 31, 2015, the average sales price per barrel of oil was $45.72 and $2.43 per Mcf for natural gas as compared to $90.10 per barrel and $4.97 per Mcf, respectively for the year ended December 31, 2014. These results indicate that the decrease in revenue is primarily attributable to weaker commodity prices.

Table of Contents

Operating expenses

Lease operating expense and production taxes

The following table presents the major components of our lease operating expense for the last two years ended December 31, 2015 and 2014 on a BOE basis:

	Years Ending December 31,
	2015				2014
	Total		Per BOE		Total		Per BOE
Lease operating costs	$	3,677,845	$	13.88	$	5,457,472	$	17.56
Production taxes	$	369,317	$	1.39	$	695,693	$	2.24

Total	$	4,047,162	$	15.27	$	6,153,165	$	19.80

Lease operating expense and production taxes from continuing operations for the year ended December 31, 2015 totaled $4,047,162 versus $6,153,165 for the year ended December 31, 2014. This translated to a decrease of $4.53/BOE on a volume basis. This reduction reflects our cost efficiencies gained as well as a change in production mix due to asset divestitures.

Accretion of asset retirement obligation

Accretion expense for the asset retirement obligations decreased by $132,520 for the year ending December 31, 2015 to $187,183 compared to $319,703 for the year ended December 31, 2014. This decrease is primarily the result of the extension of plugging and abandonment dates.

Depletion, depreciation and amortization (DD&A)

For the year ended December 31, 2015, the Company recorded DD&A expense of $22,510,290 ($84.92/BOE) compared to $10,140,152 ($32.63/BOE) for the year ended December 31, 2014 representing an increase of $52.29. This increase reflects the impact lower reserves due to weaker commodity prices and the removal of proven undeveloped reserves.

General and administrative expense (G&A expense)

G&A expense for the year ended December 31, 2015 increased $61,593 from the year ended December 31, 2014 to $3,938,291 due to the proposed merger.

Credit Facilities and Forbearance Agreement

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. If we do not refinance the IB Credit Agreement or obtain a further extension of the Forbearance Period, the lenders under the IB Credit Agreement will be able to accelerate the repayment of debt. Furthermore, if we are unable to restructure or refinance our current obligations under our existing debt, 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 our 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 we 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.

Table of Contents

Hedging Activities

At December 31, 2015, 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

Recent Activities

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.

Liquidity and Capital Resources

During fiscal 2015 compared to fiscal 2014, net cash flow provided by operating activities declined by $5,732,339 to $827,882. This decline was primarily attributable to lower revenue due to volatility of commodity prices.

Our current assets were $4,911,179 on December 31, 2015. Cash on hand comprised approximately $2,839,266. This compared to cash on hand of $3,574,427 at December 31, 2014. Accounts payable increased from $5,835,145 at December 31, 2014 to $6,301,796 at December 31, 2015.

The consolidated financial statements continue to reflect a curtailed drilling program which amounted to $8,233,461 during 2015. Our capital program is designed to increase production through exploration and workovers within our fields and through joint venture programs. This strategy will involve industry partners in these efforts so as to reduce our upfront cash requirements and reduce risk dollars expended. This represents a decrease of $26,600,251 from our capital investment in 2014.

Historically, our primary sources of liquidity have been borrowings under bank credit facilities, cash flows from operations, and private financings. Our primary use of capital has been for the exploration, development and acquisition of oil and gas properties. As we pursue reserves and production growth, we continually consider which capital resources, including equity and debt financings, are available to meet our future financial obligations, planned capital expenditure activities and liquidity requirements. Our future ability to grow proved reserves and production will be highly dependent on the capital resources available to us. We continually monitor market conditions and consider taking on additional debt, selling non-core assets, or farm-out arrangements. Depending on the timing and concentration of the development of our non-proved locations, we may be required to generate or raise significant amounts of capital to develop all of our potential drilling locations should we endeavor to do so. In the event our cash flows are materially less than anticipated and other sources of capital we historically have utilized are not available on acceptable terms, we may curtail our capital spending.

Table of Contents

The exact amount of capital spending for 2016 will depend upon the ability to refinance the existing debt with Independent Bank and our ability to raise third party financing. We may also need to modify our capital budget based on well performance results and cash flow. In addition, we have offered participations in our drilling program to industry partners over this time frame, further reducing our capital requirements. If necessary, we may also access capital through proceeds from potential non-core property asset dispositions and the future issuance of debt and/or equity securities.

Since the majority of our acreage is held by production, we have the flexibility to develop our acreage in a disciplined manner in order to maximize the resource recovery of the assets. We consistently monitor and adjust our projected capital expenditures in response to success or lack of success in drilling activities, changes in prices, availability of financing, drilling and acquisition costs, industry conditions, the timing of regulatory approvals, the availability of rigs, contractual obligations, internally generated cash flow and other factors both within and outside our control.

On December 29, 2015, we agreed to combine our business with Lilis pursuant to the merger agreement. 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 the Giddings Field assets to SOSventures in exchange for a release of our obligations under the SOSventures Credit Agreement. 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 our ability to continue as a going concern. Our Board of Directors and management team continue to take steps to try to strengthen our 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 us, or at all.

The following table summarizes our contractual obligations and commercial commitments as of December 31, 2015:

	Payments Due By Period
(in thousands)	Total		Less than 1 year		1 - 3 years		4 - 5 years		After 5 years
Contractual obligations:
Principal debt payments	$	32,207	$	32,172	$	35	$	-	$	-
Operating leases		630		258		372		-		-

Total	$	32,837	$	32,430	$	407	$	-	$	-

Sources and Uses of Funds

Cash flow from operations is a significant source of liquidity. We generate our operating cash flow primarily from the sale of oil and natural gas. This operating cash flow is generally attributable to working interests owned and held directly by us in wells on producing oil and gas properties (which generate monthly revenue and cash flow to the extent such wells produce natural gas and oil) and carried working interests in such wells (which also generate monthly revenue and cash flow to the extent such wells produce natural gas and oil), as well as overriding royalty interests and reversionary interests (which may generate additional monthly revenue and cash flow to the extent such wells produce natural gas and oil).

Cash and cash equivalents totaled $2,839,266 as of December 31, 2015, as compared to $3,574,427 as of December 31, 2014. Cash provided by (used in) operating activities was $827,882 for the year ended December 31, 2014, compared to $6,560,221 for the year ended December 31, 2014.

Changes in cash flows from operations are largely due to the same factors that affect our net income, excluding various non-cash items such as impairments of assets, depreciation, depletion and amortization and deferred income taxes. For example, changes in production volumes and market prices for natural gas and oil directly impact the level of our cash flow from operations. See the discussion under "Results of Operations."

We use cash flows from operations to fund expenditures related to our exploration, development and acquisition of natural gas and oil properties. We use cash provided by our oil and natural gas sales. We have historically obtained most of the capital to fund expenditures related to oil and natural gas production from a combination of operating cash flow and borrowing on our bank facility.

Table of Contents

Net cash used by financing activities was $3,545,277 for the year ended December 31, 2015, compared to net cash provided by financing activities was $22,660,960 for the year ended December 31, 2014. These financing activities primarily reflect repaying on our bank facility as well as the term loan.

Although we typically retain a significant degree of control over the timing of our capital expenditures, we may not always be able to defer or accelerate certain capital expenditures to address any potential liquidity issues. In addition, changes in drilling and field operating costs, drilling results that alter planned development schedules, acquisitions or other factors could cause us to revise our drilling program, which is largely discretionary.

As of December 31, 2015, we had a working capital deficit of $37,871,299, which consisted of $4,911,179 of current assets offset by $42,782,478 of current liabilities. Current assets as of December 31, 2015 included cash of $2,839,266 and accounts receivable of $1,272,662. Current liabilities as of December 31, 2015 included accounts payable and accrued liabilities of $6,301,794 and revenue payable of $1,017,823. Included in the current liabilities is Independent Bank note of $12,400,000 and SOSventures note and interest payable as of $20,898,750 as of December 31, 2015. Given these conditions, our independent registered public accounting firm has determined there is substantial doubt about our ability to continue as a going concern due to our accumulated deficit, working capital deficit, significant net losses and need to raise additional funds to meet our obligations and sustain our operations.

Our current credit facility is with Independent Bank. The secured facility has a current borrowing base of $12.6 million, matures in 2016, and has a prime variable interest rate with a 4.0% floor. We have $12.6 million drawn on the facility at December 31, 2015. This credit facility is currently in default. For more information see Item 7 - Management Discussion and Analysis-Credit Facilities and Forbearance Agreement.

On June 3, 2014 we agreed to amend our credit agreement with SOSventures, LLC, 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 our assets. On March 26, 2012 we drew down the full amount of the credit facility to finance an acquisition. The maturity of our second lien note to SOSventures was extended to August 1, 2016 under the Forbearance Agreement. This credit facility is also in default due to the default under the IB Credit Agreement.

On April 15, 2015 we entered the Second Amendment to the First Amendment and Restated Credit Agreement and several other agreements which provided that SOSventures, will provide an additional $3 million on its credit facility to be used to pay the outstanding balance of the Independent Bank term loan, pay on the Independent Bank credit facility and for operations. Additionally, SOSventures deposit $5 million into a controlled account at Independent Bank to be used to drill two wells in the Crittendon Field referenced in the Independent Bank Amendment. Further, SOSventures, will receive interest on its credit facility and a 1% overriding royalty interest on the Company’s Crittendon Field properties effective upon the drilling of these two oil and gas wells until such time as the credit facility is repaid. Finally, SOSventures, shall receive warrants to purchase 2,542,397 of our common shares for $1.00 per share with a two-year term. If fully purchased 2,542,397 would equal 20% of our currently outstanding common stock.

Off Balance Sheet Arrangements.

None.

Critical Accounting Policies and Estimates

The following discussion and analysis of financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of these financial statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses. Certain accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. We evaluate such estimates and assumptions on a regular basis. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates and assumptions used in preparation of our consolidated financial statements. Below, we have provided expanded discussion of the more significant accounting policies, estimates and judgments. We believe these accounting policies reflect the more significant estimates and assumptions used in preparation of our consolidated financial statements. Please read the notes to our audited consolidated financial statements included in this report for a discussion of additional accounting policies and estimates made by management.

Table of Contents

Oil and Gas Producing Activities

Our oil and gas producing activities were accounted for using the successful efforts method of accounting as further defined under FASB ASC 932, Extractive Activities - Oil and Natural Gas. Costs to acquire leasehold rights in oil and gas properties, to drill and equip exploratory wells that find proved reserves, and to drill and equip development wells are capitalized. Costs to drill exploratory wells that do not find proved reserves, delay rentals and geological and geophysical costs are expensed.

Depletion and Depreciation

Estimates of natural gas and oil reserves utilized in the calculation of depletion are prepared using certain assumptions. Reserve estimates are based upon existing economic and operating conditions with no provision for price and cost escalations except by contractual arrangements. Natural gas and oil reserve estimates are inherently imprecise and are subject to change as more current information becomes available. Capitalized costs are depleted and amortized using the units of production method, based upon reserve estimates.

Impairments

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 charges were approximately $55,753,481, and $4,428,378, respectively.

Asset Retirement Obligations

The Company records for the estimated liability for the plugging and abandonment of natural gas and oil wells at the end of their productive lives following the provisions of ASC 410-20, Asset Retirement Obligations. Asset retirement obligations are estimated at the present value of expected future net cash flows based on reserve estimates and federal and state regulatory requirements and are discounted using the Company’s credit adjusted risk free rate. Because the Company uses unobservable inputs in estimating asset retirement obligations, it considers such obligations a Level 3 measurement under ASC 820. At the time of abandonment, we recognize a gain or loss on abandonment to the extent that actual costs do not equal the estimated costs.

Goodwill

At December 31, 2015 and December 31, 2014 the Company had goodwill of $959,681.

Goodwill represents the excess of the purchase price over the fair value of the net assets acquired. The Company follows FASB ASC Topic 350 Goodwill and Intangible Asset Impairment Testing. Our analysis consists of two steps. Step 1 tests the company for impairment by comparing the fair value of equity to the book value of equity. If the fair value is less than the book value, then Step 2 analysis must be performed. If the fair value of goodwill is less than its carrying amount, impairment is recorded based on the difference. The Company annually assesses the carrying value of goodwill for impairment.

Pricing mechanism for oil and gas reserves estimation

The SEC's rules require reserve estimates to be calculated using a 12-month average price. Price changes can still be incorporated to the extent defined by contractual arrangements.

The SEC rules also amend the definition of proved oil and gas reserves to include reserves located beyond development spacing areas that are immediately adjacent to developed spacing areas if economic recoverability can be established with reasonable certainty. These revisions are designed to permit the use of alternative technologies to establish proved reserves in lieu of requiring companies to use specific tests. In addition, they establish a uniform standard of reasonable certainty that applies to all proved reserves, regardless of location or distance from producing wells. Because the revised rules generally expand the definition of proved reserves, proved reserve estimates could increase in the future based upon adoption of the revised rules.

Estimated proved oil and gas reserves

The evaluation of our oil and gas reserves is critical to management of our operations and ultimately our economic success. Decisions such as whether development of a property should proceed and what technical methods are available for development are based on an evaluation of reserves. These oil and gas reserve quantities are also used as the basis of calculating the unit-of-production rates for depreciation, evaluating impairment and estimating the life of our producing oil and gas properties in our asset retirement obligations. Proved reserves are classified as either proved developed or proved undeveloped. Proved developed reserves are those reserves which can be expected to be recovered through existing wells with existing equipment and operating methods. Estimated proved undeveloped reserves include reserves expected to be recovered from new wells from undrilled proven reservoirs or from existing wells where a significant major expenditure is required for completion and production.

Table of Contents

Independent reserve engineers prepare the estimates of our oil and gas reserves presented in this report based on guidelines promulgated under GAAP and in accordance with the rules and regulations of the Securities and Exchange Commission. The evaluation of our reserves by the independent reserve engineers involves their rigorous examination of our technical evaluation and extrapolations of well information such as flow rates and reservoir pressure declines as well as other technical information and measurements. Reservoir engineers interpret this data to determine the nature of the reservoir and ultimately the quantity of total oil and gas reserves attributable to a specific property. Our total reserves in this report include only quantities that we expect to recover commercially using current prices, costs, existing regulatory practices and technology. While we are reasonably certain that the total reserves will be produced, the timing and ultimate recovery can be affected by a number of factors including completion of development projects, reservoir performance, regulatory approvals and changes in projections of long-term oil and gas prices. Revisions can include upward or downward changes in the previously estimated volumes or proved reserves for existing fields due to evaluation of (1) already available geologic, reservoir or production data or (2) new geologic or reservoir data obtained from wells. Revisions can also include changes associated with significant changes in development strategy, oil and gas prices or production equipment/facility capacity.

Standardized measure of discounted future net cash flows

The standardized measure of discounted future net cash flows relies on these estimates of oil and gas reserves using commodity prices and costs at year-end. The benchmark oil and gas prices used are the preceding 12-month averages of the first-day-of-the month spot prices posted for the WTI oil and Henry Hub natural gas. Oil prices are based on a benchmark price of $47.03 per barrel and have been adjusted by lease for gravity, transportation fees, and regional price differentials. Gas prices per thousand cubic feet are based on a benchmark price of $2.22 per million British thermal units and have been adjusted by lease for Btu content, transportation fees, and regional price differentials. The adjustments are based on the differential between historic oil and gas sales and the corresponding benchmark price. While we believe that future operating costs can be reasonably estimated, future prices are difficult to estimate since the market prices are influenced by events beyond our control. Future global economic and political events will most likely result in significant fluctuations in future oil prices.

Unproved reserves

The SEC’s rules permit disclosure of probable and possible reserves and provide definitions of probable reserves and possible reserves. Disclosure of probable and possible reserves is optional. We have chosen not to disclose probable and possible reserves.

Executive Compensation

The Company entered into employment contracts with Michael Pawelek and Edward Shaw which provide for stock grants, stock options and change of control payments. The Company accounts for these grants, options and payments under FASB 718.

No Delayed Adoption of New or Revised Accounting Standards under the Jumpstart our Business Startups Act (JOBS ACT)

We made the irrevocable decision under the JOBS Act to implement new or revised accounting standards applicable to reporting issuers when required of reporting issuers that are not Emerging Growth Companies under the JOBS Act.

Item 7A.

Quantitative and Qualitative Disclosures About Market Risk.

We are exposed to a variety of market risks including commodity price risk, interest rate risk and counterparty and customer risk. We address these risks through a program of risk management which includes the use of derivative instruments

Commodity Price Risk. Our major commodity price risk exposure is to the prices received for our oil, condensate, natural gas and NGLs production. Our results of operations and operating cash flows are affected by changes in market prices. Realized commodity prices received for our production are the spot prices applicable to oil, condensate, natural gas and NGLs in the region produced. Prices received for oil, condensate, natural gas and NGLs are volatile and unpredictable and are beyond our control. To mitigate a portion of our exposure to adverse market changes in the prices for oil, condensate, natural gas and NGLs, we have entered into, and may in the future enter into additional, commodity price risk management arrangements for a portion of our oil, condensate, natural gas and NGLs production. For the year ended December 31, 2015, a 5% change in the prices received for our oil, condensate, natural gas and NGLs production would have had an approximate $430,330 impact on our revenues prior to hedge transactions to mitigate our commodity pricing risk. For the year ended December 31, 2014, a 5% change in the prices received for our oil, condensate, natural gas and NGLs production would have had an approximate $1.0 million impact on our revenues prior to hedge transactions to mitigate our commodity pricing risk. On March 9, 2016, in response to the Forbearance Agreement negotiations, Independent Bank liquidated all hedge positions the Company had in place at the end of the year. For more information regarding our hedging activities, see Item 8. “Financial Statements and Supplementary Data, Note 8 Derivatives” included in this annual report on Form 10-K.

Table of Contents

Counterparty and Customer Credit Risk. Joint interest receivables arise from billing entities which own partial interest in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we wish to drill. We have limited ability to control participation in our wells. We are also subject to credit risk due to concentration of our oil and natural gas receivables with several significant customers. The inability or failure of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial position, results of operations and cash flows. While we do not require our customers to post collateral and we do not have a formal process in place to evaluate and assess the credit standing of our significant customers for oil and natural gas receivables, we do evaluate the credit standing of such counterparties as we deem appropriate under the circumstances. This evaluation may include reviewing a counterparty’s credit rating, latest financial information and, in the case of a customer with which we have receivables, its historical payment record, the financial ability of the customer’s parent company to make payment if the customer cannot and undertaking the due diligence necessary to determine credit terms and credit limits.

Impact of Inflation. Inflation in the United States has been relatively low in recent years and did not have a material impact on our results of operations for the year ended December 31, 2015. But, the drop in oil and gas prices did affect our 2015 financial results and we anticipate a material impact from lower oil and gas prices in 2016. Although the impact of inflation has been generally insignificant in recent years, it is still a factor in the United States economy and while not a current condition, we tend to specifically experience inflationary pressure on the cost of oilfield services and equipment with increases in oil and natural gas prices and with increases in drilling activity in our areas of operations. The unavailability or high cost of drilling rigs, completion equipment and services, supplies and personnel, including hydraulic fracturing equipment and personnel, could adversely affect our ability to establish and execute exploration and development plans within budget and on a timely basis, which could have a material adverse effect on our financial condition, results of operations and cash flows.

Interest Rate Risk. Our earnings are exposed to interest rate risk associated with borrowings under our Independent Bank revolving credit facility, which bear interest at a rate elected by us that is based on the prime rate with a minimum floor of 4.00% depending on the base rate used and the amount of the loan outstanding in relation to the borrowing base. As of March 31, 2016, the weighted average interest rate on outstanding borrowings under our revolving credit facility was 14.90%. If interest rates increase, so will our interest costs, which may have a material adverse effect on our results of operations and financial condition.

Item 8.

Financial Statements and Supplementary Data.

The information required by this Item 8 is hereby included in our Consolidated Financial Statements beginning on page F-1 of the Annual Report on Form 10-K.

PART III

Item 9.

Changes In and Disagreements with Accountants on Accounting and Financial Disclosure.

On June 5, 2013, we engaged Rothstein Kass to audit our financial statements for the year ending December 31, 2013. In 2014 KPMG LLP acquired certain assets of Rothstein Kass. We engaged KPMG LLP to audit its 2014 financial statements on July 31, 2014.

Prior to each appointment, we had not consulted with Rothstein Kass nor KPMG LLP on either (1) the application of accounting principles to a specified transaction, either completed or proposed; or the type of audit opinion that may be rendered on our financial statements, and neither Rothstein Kass nor KPMG provided either a written report or oral advice to us that either Rothstein Kass or KPMG concluded was an important factor considered by the Company in reaching a decision as to the accounting, auditing or financial reporting issue; or (2) any matter that was either the subject of a disagreement, as defined in Item 304(a)(1)(iv) of Regulation S-K, or a reportable event, as defined in Item 304(a)(1)(v) of Regulation S-K.

Further, we have not consulted Rothstein Kass or KPMG LLP regarding disagreements with a former accountant on any matter of accounting principles or practices, financial statement disclosure, or auditing scope or procedure or a reportable event under SEC Regulation S-K Item 304(a)(1)(v).

On May 8, 2015, we dismissed KPMG and engaged Akin Doherty Klein & Feuge, P.C., or ADKF, as their independent registered public accounting firm. Prior to such engagement, we had not consulted with ADKF on either (1) the application of accounting principles to a specified transaction, either completed or proposed; or the type of audit opinion that may be rendered on our financial statements, and ADKF did not provide either a written report or oral advice to us that ADKF concluded was an important factor considered by the Company in reaching a decision as to the accounting, auditing or financial reporting issue; or (2) any matter that was either the subject of a disagreement, as defined in Item 304(a)(1)(iv) of Regulation S-K, or a reportable event, as defined in Item 304(a)(1)(v) of Regulation S-K.

Further, we have not consulted ADKF regarding disagreements with a former accountant on any matter of accounting principles or practices, financial statement disclosure, or auditing scope or procedure or a reportable event under SEC Regulation S-K Item 304(a)(1)(v).

Table of Contents

On January 25, 2016, we formerly notified ADKF of their dismissal and engaged Marcum LLP, or Marcum, as our independent registered public accounting firm to audit our financial statements for the year ending December 31, 2015, which engagement Marcum accepted on January 29, 2016. During ADKF’s brief engagement by us, ADKF did not issue any audit reports relating to us.

We have not consulted Marcum LLP regarding the application of accounting principles to a specified transaction, either completed or proposed. Further, no written report was provided to the registrant or oral advice was provided that Marcum LLP concluded was an important factor considered by the registrant in reaching a decision as to the accounting, auditing or financial reporting issue.

Further, we have not consulted Marcum LLP regarding disagreements with a former accountant on any matter of accounting principles or practices, financial statement disclosure, or auditing scope or procedure or a reportable event under SEC Regulation S-K Item 304(a)(1)(v).

Item 9A.

Controls and Procedures

Management’s Evaluation of Internal Control over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rule 13a-15(f) and 15d-15(f) under the Exchange Act). Internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements in accordance with GAAP. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projection of any evaluation of effectiveness to future periods is subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

As of December 31, 2015, we assessed the effectiveness of our internal control over financial reporting based on the criteria for effective internal control over financial reporting conducted based on the Internal Control—Integrated Framework issued by COSO (2013) and SEC guidance on conducting such assessments. In connection with management’s assessment of our internal control over financial reporting, we concluded that, as of December 31, 2015, our internal controls and procedures were not effective to detect the inappropriate application of GAAP as more fully described below.

The matters involving internal controls and procedures that our management considered to be material weaknesses under the standards of the Public Company Accounting Oversight Board were: (1) while we have implemented written policies and procedures for accounting and financial reporting with respect to the requirements and application of GAAP and SEC disclosure requirements, due to limited resources, we have not conducted a formal assessment of whether the policies that have been implemented address the specific risks of misstatement; accordingly, we could not conclude whether the control activities are designed effectively nor whether they operate effectively, and (2) we do not have a fully effective mechanism for monitoring the system of internal controls.

A material weakness is a control deficiency, or combination of control deficiencies, that results in more than a remote likelihood that a material misstatement of the annual or interim financial statements will not be prevented or detected. Management believes that the material weaknesses set forth above did not have a material adverse effect on our financial results for the year ended December 31, 2015.

We are committed to improving our financial organization. Our control weaknesses are largely a function of not having sufficient staff. In the event the merger is consummated, we will have additional resources available to us to increase the effectiveness of our internal controls, including a Chief Financial Officer, and extended management team. Additionally, as financial resources become available, we have been engaging third-party consultants to assist with control activities.

We will continue to monitor and evaluate the effectiveness of our internal control over financial reporting on an ongoing basis and are committed to taking further action by implementing additional enhancements or improvements, or deploying additional human resources as may be deemed necessary.

Changes in Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting during our most recent fiscal quarter that materially affected, or were reasonably likely to materially affect, our internal control over financial reporting.

Table of Contents

Item 9B.

Other Information

Material Impairments

We are reporting an impairment of $55,753,481, which is material. The impairment was recently determined in conjunction with the preparation of the financial statements included with this Form 10-K. The Company reported a material weakness in its internal controls in connection with its accounting for this material impairment further described in Item 9A herein.

Changes in Control of Registrant

SOSventures, is part of a group that currently owns approximately 38% of our Company stock. As described above, SOSventures, now has warrants that could allow it to purchase a controlling interest in the Company.

Table of Contents

Item 10.

Directors, Executive Officers and Corporate Governance

DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Each of our executive officers shall serve until his successor is elected and qualified. Each member of our board of directors serves until the next annual meeting of stockholders unless removed for breaches of director duties under our By-laws. The directors listed below were appointed in connection with the adoption of our Amended and Restated Limited Liability Company Operating Agreement dated January 20, 2012 and will serve until our next annual meeting or until their earlier resignation.

Name	Age	Position
Michael Pawelek (1)	57	Chief Executive Officer and Director
Edward Shaw	53	Chief Operating Officer
Kim Vo	43	Chief Accounting Officer
Bill Liao (1)	48	Director and Chairman of Board of Directors
Charles S. Henry, III (1)	47	Director
Peter Benz(1)	55	Director
Craig Dermody (1)	57	Director

(1)

Pawelek, Liao, Henry, Benz and William Mahoney were elected to the Board pursuant Starboard Resources, LLC Restated and Amended Operating Agreement dated January 20, 2012, which provided for the designation of new members of the board of directors. Craig Dermody was elected to the Board of Directors in May 2012 pursuant to the Operating Agreement. Under that Agreement one designated director was the Chief Executive Officer (Michael Pawelek), one director was designated by SOSventures, LLC (Bill Liao), one director was designated by Summerline Asset Management, LLC on behalf of Longview Marquis Fund, L.P., LMIF Investments, LLC, SMF Investments, LLC, and Summerline Capital Partners, LLC (Peter Benz), and one director was designated by Asym Energy Investments LLC (Craig Dermody). Additionally, two other directors, designated “independent directors” were designated under the Operating Agreement, Charles Henry, III and William Mahoney. William Mahoney resigned from the Board of Directors in April 2013 for personal reasons and has not been replaced. He subsequently passed away. The same director structure and designations were carried over to Starboard Resources, Inc. upon its conversion from a limited liability company.

Michael Pawelek became a Director of our Company on January 20, 2012 and has been our and Chief Executive Officer since our acquisition of the assets of ImPetro Resources LLC on June 10, 2011. Mr. Pawelek has over 27 years of exploration and production and oilfield services industries experience. Prior to Brushy, he was the CEO and President of ImPetro Resources LLC from 2010 to 2011 and CEO and President of South Texas Oil Company in 2009. South Texas Oil Company was a reporting company that filed bankruptcy in 2009 in San Antonio, Texas in Cause No. 09-54233 and was liquidated in bankruptcy. From 2004 to 2008 Mr. Pawelek was President of BOSS Exploration & Production Corporation, a privately held Gulf Coast exploration and production company. Mr. Pawelek began his career as a geophysicist with Clayton Williams Company; was a district geophysicist with TXO Production Corporation; founded CPX Petroleum which drilled over 60 wells under his management; founded and was the CEO of Universal Seismic Associates, Inc.; served as VP of Operations of Amenix USA, Inc., a private exploration and production company focused on oil and natural gas exploration in Louisiana and served as President of Sonterra Resources, Inc., a company that has oil and natural gas assets in Texas state waters in Matagorda Bay. He received a BS degree in Petroleum Engineering from Texas A&M. As a result of these professional experiences, Mr. Pawelek possesses particular knowledge and experience in the operations of oil and gas companies that strengthen the board’s collective qualifications, skills, and experience.

Edward Shaw has been our Chief Operating Officer since our acquisition of the assets of ImPetro Resources LLC on June 10, 2011. Mr. Shaw was Chief Operating Officer of ImPetro Resources LLC from 2010-2011. From 2005 to 2009 Mr. Shaw was COO and Vice-President of Operations for Nutek Oil and South Texas Oil Company. South Texas Oil Company was a reporting company that filed bankruptcy in 2009 in San Antonio, Texas in Cause No. 09-54233 and was liquidated in bankruptcy. Mr. Shaw began his career as a systems analyst before becoming involved in the oil and gas industry. He has prior experience in Saudi Arabia and in New Zealand researching and developing methods of monitoring oil wells to optimize production, including using existing products integrated with emerging telemetry technologies. He holds a Diploma in Electrical Engineering.

Kim Vo has been our Controller and Chief Accounting Officer since our acquisition of the assets of ImPetro Resources LLC on June 10, 2011. Ms. Vo previously worked as the Controller of ImPetro Resources from February 2010 to June 2011 and the Controller of South Texas Oil Company from June 2008 to January 2010. Previously Ms. Vo was the controller for Blackbrush Oil & Gas and Aminex USA. Ms. Vo earned a Masters in Professional Accounting and BBA from the University of Texas at Austin.

Bill Liao became a Director and Chairman of the Board of Directors of our Company on January 20, 2012. Mr. Liao has extensive experience with public company dynamics, governance and investor relations. Mr. Liao has been a venture partner with SOSventures, LLC since 2011. Mr. Liao was also a director of XING AG from 2003 to 2009. XING AG is listed on the Frankfurt stock exchange. Mr. Liao also has worked in the commodities trading arena with several boutique Swiss investment funds and has established BandWithVentures an Irish based tech startup. As a result of these professional experiences, Mr. Liao possesses particular knowledge and experience in developing companies that strengthen the board’s collective qualifications, skills, and experience. Mr. Liao serves on our Audit Committee and Compensation Committee.

Charles S. Henry III became a Director of our Company on January 20, 2012. Since August 2007 Mr. Henry has been a Senior Geological Advisor for the Gulf of Mexico for Energy XXI (Bermuda) Limited. (NASDAQ: EXXI). Energy XXI’s oil and gas operations focus on South Louisiana and the Gulf of Mexico and do not overlap with our oil and gas operations onshore in Texas and Oklahoma. From 2006 to 2007 Mr. Henry worked as a Senior Asset Geoscientist for Energy Partners, Ltd. focusing on South Louisiana exploration. From 2002 to 2006 Mr. Henry was a Senior Geologist for Domination Exploration & Production, Inc. focusing on South Louisiana exploration. Mr. Henry has a B.S in Geology from Louisiana State University, a M.S. in Geology from the University of New Orleans and a M.B.A. from Tulane University. As a result of these professional experiences and academic training, Mr. Henry possesses particular knowledge and experience in understanding and advising on geological and oil and gas issues involving our current and accretive oil and gas properties that strengthen the board’s collective qualifications, skills, and experience. Mr. Henry serves on our Compensation Committee.

Table of Contents

Mr. Henry is a respondent in an arbitration filed by Gregory Imbruce and business entities controlled by Mr. Imbruce. On March 18, 2014, Gregory Imbruce, Giddings Investments, LLC, Giddings Genpar LLC, Hunton Oil Genpar, LLC, Asym Capital III LLC, Glenrose Holdings, LLC and Asym Energy Investment LLC filed a claim through the American Arbitration Association against Charles S. Henry, III, John P. Vaile, as Trustee of John P. Vaile Living Trust, John Paul Otierno, SOSventures LLC, Bradford Higgins, William Mahoney, Edwards M. Conrads, Robert J. Conrads, Giddings Oil & Gas LP, Hunton Oil Partners LP and Asym Energy Fund III LP and named other limited partners in the partnerships as relief defendants. Claimants make the following claims against Mr. Henry: (i) breach of limited partnership agreements; (ii) breach of implied covenant of good faith and fair dealing; (iii) conversion of stock certificates subject to Company’s Amended Interpleader action includes as Exhibit 99.1.5; (iv) theft of stock certificates subject to Company’s Amended Interpleader action includes as Exhibit 99.1.5; (v) unjust enrichment; (vi) violations of the Delaware Uniform Limited Partnership Act; and (vii) breach of fiduciary duty. The claimants seek declaratory and injunctive relief as to who has authority to act as general partner of the partnerships, constructive trust on our common stock shares previously distributed to limited partners in the partnerships and damages. Mr. Henry had previously made claims in 2012 in litigation against Mr. Imbruce and the other claimants in Connecticut Superior Court. Mr. Henry and the other claimants allege fiduciary duty breaches, conversion, civil theft, violations of Connecticut Unfair Trade Practices Act, unjust enrichment, common law fraud, negligence, fraudulent conveyance and civil conspiracy and seek damages, injunctive relief, a constructive trust and an accounting.

Peter Benz became a Director of our Company on January 20, 2012. Mr. Benz serves as the Chairman and Chief Executive Officer of Viking Asset Management, LLC and is a member of its Investment Committee. He has been affiliated with Viking Asset Management, LLC since 2001. His responsibilities include assuring a steady flow of candidate deals, making asset allocation and risk management decisions and overseeing all business and investment operations. He has more than 25 years of experience specializing in investment banking and corporate advisory services for small growth companies in the areas of financing, merger/acquisition, funding strategy and general corporate development. Prior to founding Viking in 2001, Mr. Benz founded Bi Coastal Consulting Company where he advised hundreds of companies regarding private placements, initial public offerings, secondary public offerings and acquisitions. He has founded three public companies and served as a director for four other public companies. Prior to founding Bi Coastal Consulting, Mr. Benz was responsible for private placements and investment banking activities at Gilford Securities in New York, NY. Mr. Benz became a director of usell.com, Inc. (“USEL”) on May 15, 2014. Mr. Benz is a graduate of Notre Dame University. As a result of these professional experiences, Mr. Benz possesses particular knowledge and experience in developing companies and capital markets that strengthen the board’s collective qualifications, skills, and experience. Mr. Benz serves on our Audit Committee.

Craig Dermody became a Director of our Company on May 20, 2012. Mr. Dermody brings over 30 years of experience in the institutional investment securities industry. Mr. Dermody is currently a partner with Johnson Rice & Co. LLC, an energy investment banking securities firm Mr. Dermody has been employed by Johnson Rice since 1994. Prior to Johnson Rice, he was a Sr. Vice President with Prudential Securities and a Sr. Vice President with Howard Weil Labouisse Friedrichs, where he began his career in 1981. He served on the Board of Directors of Halter Environmental, a company focused on oil spill recovery vessels from 1990-1991. Mr. Dermody received his BS from Southeastern Louisiana University. As a result of these professional experiences, Mr. Dermody possesses particular knowledge and experience in developing companies and capital markets that strengthen the board’s collective qualifications, skills, and experience. Mr. Dermody serves on our Audit Committee and Compensation Committee.

Evaluation of Section 16 Compliance

The Section 16 filings relating to the Company since it last reported its Section 16 Compliance in its Form 10-K for the year ending December 31, 2013 were timely filed except for two Forms 4 relating to stock options granted to Michael J. Pawelek and Edward Shaw filed September 11, 2014. These stock option grants were timely reported by the Company through a Form 8-K on September 4, 2014, but the follow up Forms 4 were not filed until September 11, 2014.

Code of Ethics

The Company has adopted a Code of Business Conduct and Ethics that applies to all of its directors, officers and employees. The Code of Ethics will be posted the Company’s website at www.starboardresources.com.

Table of Contents

Item 11.

Executive Compensation

Michael Pawelek-Chief Executive Officer

Amended and Restated Employment Agreement

We entered into an employment agreement with Mr. Pawelek on April 1, 2012, which was amended in August 2014 and December 2015.

Mr. Pawelek’s employment agreement provides that, if Mr. Pawelek’s employment is involuntarily terminated, we would provide to Mr. Pawelek the following severance benefits: (i) a lump sum payment equal to three years of his current base salary; and (ii) 18 months of continued group medical and dental insurance at our expense for Mr. Pawelek and his immediate family. In connection with the merger, Mr. Pawelek’s termination would qualify as an involuntary termination, and he would be entitled to the foregoing payments, if he does not receive a timely notice at least five days prior to the merger confirming his continued employment.

Mr. Pawelek’s employment agreement also provides that he would receive additional severance payments if his involuntary termination occurs in connection with a change in control (the merger constitutes a “change in control” for purposes of Mr. Pawelek’s employment agreement). In such circumstance, if the change in control occurs prior to August 14, 2016, Mr. Pawelek would be entitled to (i) a guaranteed bonus of $500,000, to be paid promptly following a 20-day period after the effective date of the merger, if Mr. Pawelek has not been guaranteed continued employment at least five days prior to the merger, and (ii) 150,000 options to purchase our Stock with an exercise price of $4.75 per share to vest immediately prior to the merger, along with the continued vesting of any unvested options according to their current vesting schedule through July 15, 2024. If the change in control occurs on or after August 14, 2016, all of Mr. Pawelek’s unvested shares would vest pursuant to the acceleration clause.

Mr. Pawelek’s employment agreement also would entitle him to a gross-up payment for any severance or other payments that may subject him to an excise tax under Code Section 280G. Finally, Mr. Pawelek’s current employment agreement includes provisions with regard to non-disparagement (during the term of the employment agreement and for three years following the termination of Mr. Pawelek’s employment) and non-disclosure of confidential information.

Option Agreement

We entered into an option agreement with Mr. Pawelek on August 30, 2014 granting him an option to purchase a maximum of 450,000 shares of our common stock at an exercise price of $4.75 per share, under the Starboard Resources Inc. 2014 Equity Incentive Plan (the 2014 Plan). In addition, under his option agreement, if the merger occurs before July 15, 2016, Mr. Pawelek would be entitled to an additional 150,000 stock options to be fully vested and exercisable in connection with the merger. Due to the value of our stock, Mr. Pawelek’s option agreement, and all of his options and other rights thereunder and under the 2014 Plan, will be terminated in connection with the merger without payment to Mr. Pawelek.

Proposed Employment Agreement with Lilis

Lilis intends to enter into a new employment agreement with Mr. Pawelek in connection with the merger, which will supersede Mr. Pawelek’s current employment agreement in its entirety.

Edward Shaw-Chief Operating Officer

Amended and Restated Employment Agreement

We entered into an employment agreement with Mr. Shaw on April 1, 2012, which was amended in August 2014 and December 2015.

Mr. Shaw’s current employment agreement provides that, if Mr. Shaw’s employment is terminated due to an involuntary termination, we would provide to Mr. Shaw the following severance benefits: (i) a lump sum payment equal to three years of his current base salary; and (ii) 18 months of continued group medical and dental insurance at our expense for Mr. Shaw and his immediate family. In connection with the merger, Mr. Shaw’s termination would qualify as an involuntary termination, and he would be entitled to the foregoing payments, if he does not receive a timely notice at least five days prior to the merger confirming his continued employment.

Mr. Shaw’s current employment agreement also provides that he would receive additional severance payments if his involuntary termination occurs in connection with a change in control (the merger constitutes a “change in control” for purposes of Mr. Shaw’s current employment agreement). In such circumstance, if the change in control occurs prior to August 14, 2016, Mr. Shaw would be entitled to (i) a guaranteed bonus of $500,000, to be paid promptly following a 20-day period after the effective date of the merger, if Mr. Shaw has not been guaranteed continued employment at least five days prior to the merger, and (ii) 150,000 options to purchase our Stock with an exercise price of $4.75 per share to vest immediately prior to the merger, along with the continued vesting of any unvested options according to their current vesting schedule through July 15, 2024. If the change in control occurs on or after August 14, 2016, all of Mr. Shaw’s unvested shares would vest pursuant to the acceleration clause.

Mr. Shaw’s current employment agreement also would entitle him to a gross-up payment for any severance or other payments that may subject him to an excise tax under Code Section 280G. Finally, Mr. Shaw’s current employment agreement includes provisions with regard to non-disparagement (during the term of the employment agreement and for three years following the termination of Mr. Shaw’s employment) and non-disclosure of confidential information.

Table of Contents

Option Agreement

We entered into an option agreement with Mr. Shaw on August 30, 2014 granting him an option to purchase a maximum of 450,000 shares of our common stock at an exercise price of $4.75 per share, under the 2014 Plan. In addition, under his option agreement, if the merger occurs before July 15, 2016, Mr. Shaw would be entitled to an additional 150,000 stock options to be fully vested and exercisable in connection with the merger. Due to the value of our stock, Mr. Shaw’s option agreement, and all of his options and other rights thereunder and under the 2014 Plan, will be terminated in connection with the merger without payment to Mr. Shaw.

Proposed Employment Agreement with Lilis

Lilis intends to enter into a new employment agreement with Mr. Shaw in connection with the merger, which will supersede Mr. Shaw’s current employment agreement in its entirety.

Summary Compensation Table—Executive Compensation

The Summary Compensation Table below displays the total compensation awarded to, earned by or paid to the Named Executive Officers for the fiscal years ending December 31, 2015 and 2014. All amounts shown below are in dollars.

Name and Principal Position	Year	Salary		Bonus		Stock Award(s)		Option Award(s)			All Other Compensation		Total
Michael Pawelek	2015	$	295,000	$	-	$	-	$	-		$	12,000	$	307,000
Chief Executive Officer	2014	$	268,750	$	-	$	-	$	1,237,500	⁽¹⁾	$	4,000	$	1,510,250
Edward Shaw	2015	$	255,000	$	-	$	-	$	-		$	12,000	$	267,000
Chief Operating Officer	2014	$	220,555	$	-	$	-	$	1,237,500	⁽¹⁾	$	4,000	$	1,462,055
N. Kim Vo	2015	$	120,175	$	-	$	-	$	-		$	-	$	120,175
Comptroller	2014	$	120,175	$	-	$	-	$	-		$	-	$	120,175

(1)

Under our amended and restated employment agreements with Michael Pawelek and Edward Shaw dated August 15, 2014, Michael Pawelek and Edward Shaw each received 450,000 stock options priced at $4.75 issued under our stockholder-ratified 2014 Equity Incentive Plan that vest over three years. See Note 10 - "Stock Based Compensation and Conditional Performance Awards" for the basis for the calculation of the value of the option grants.

The material terms of Mr. Pawelek’s and Mr. Shaw’s current employment agreements are described below under “Potential Payments Upon Termination or Change of Control.”

Outstanding Equity Awards at Fiscal Year-End

The Outstanding Equity Awards at Fiscal Year-End Table reflects each Named Executive Officer’s unexercised option award holdings and unvested restricted stock awards at December 31, 2015 on an individual award basis.

Option Awards
Name	Number of Securities Underlying Unexercised Options (#) Exercisable		Number of Securities Underlying Unexercised Options Unexercisable			Option Exercise Price			Option Expiration Date
Michael Pawelek		212,500		237,500	⁽¹⁾		$	4.75	August 15, 2024
Edward Shaw		212,500		237,500	⁽¹⁾		$	4.75	August 15, 2024

(1)

Under Brushy’s amended and restated employment agreements with Michael Pawelek and Edward Shaw dated August 15, 2014, Michael Pawelek and Edward Shaw each received 450,000 stock options priced at $4.75 issued under our stockholder-ratified 2014 Equity Compensation Plan. The options vest as follows: 1) 150,000 options each vest in August 2015; and 2) the remaining options vest at 12,500 each per month over the following two years. All options will be vested by August 2017.

Director Compensation

Non-employee members of the our board of directors have not been paid in the past for participation on our board of directors or on any committees. Further, our board of directors has not adopted any policy on paying members of the board of directors. Finally, none of the members of our board of directors has a written agreement with Brushy. Mr. Michael Pawelek serves as a director but is not entitled to any additional compensation for such service.

Table of Contents

The Director Compensation Table below displays the total compensation awarded to, earned by or paid to directors for the fiscal year ending December 31, 2015. All amounts shown below are in dollars.

Name

Fees Earned or Paid in Cash

($)

Stock Awards

($)

Option Awards

($)

Non-Equity Incentive Plan Compensation

($)

Change in Pension Value and Non-qualified Deferred Compensation Earnings

($)

All other Compensation

($)

Total

($)

Bill Liao

Peter Benz

Charles Henry, III

Craig Dermody

Potential Payments Upon Termination or Change of Control

This section discusses the incremental compensation that we would pay to each Named Executive Officer in the event of the Named Executive Officer’s termination of employment with Brushy as of December 31, 2015 under various scenarios (“termination events”) including 1) voluntary resignation; 2) involuntary termination; 3) termination without cause or for Good Reason in connection with a change in control; 4) termination in the event of disability; and 5) termination in the event of death.

Pursuant to applicable SEC rules, the analysis contained in this section does not consider or include payments made to a Named Executive Officer with respect to contracts, agreements, plans or arrangements to the extent they do not discriminate in scope, terms or operation, in favor of our Named Executive Officers and that are available generally to all salaried employees, such as our 401(k) Plan. The actual amounts that would be paid upon a Named Executive Officer’s termination of employment can only be determined at the time of such Named Executive Officer’s termination. Due to the number of factors that affect the nature and amount of any compensation or benefits provided upon the termination events, any actual amounts paid or distributed may be higher or lower than reported below. Factors that could affect these amounts include the timing during the year of any such event and our stock price.

Michael Pawelek, Edward Shaw and Kim Vo

We entered into employment agreements with Michael Pawelek, Edward Shaw and Kim Vo effective as of April 1, 2012. We entered into Amended and Restated Employment Agreements with Michael Pawelek and Edward Shaw effective August 14, 2014, which were amended again in December 2015. The April 1, 2012 agreement with Ms. Vo had a three-year term. Ms. Vo’s employment agreement expired on April 1, 2015. Ms. Vo became an at-will employee thereafter. The August 14, 2014 agreements, with Mr. Pawelek and Mr. Shaw have three-year terms with renewals for one-year terms.

Mr. Pawelek’s and Mr. Shaw’s 450,000 stock options, each with a $4.75 exercise price, will vest on an accelerated schedule under certain conditions. First, if there is: 1) a business combination on or after August 14, 2016; 2) a termination without “Cause;” 3) the death or disability of Mr. Pawelek or Mr. Shaw, or 4) Mr. Pawelek’s or Mr. Shaw’s “Good Reason Resignation,” then the stock option grant will vest in full. “Cause” generally means: 1) dishonesty in the performance of duties and obligations to Brushy, 2) final conviction of a felony or misdemeanor involving moral turpitude which materially and adversely affects our reputation and financial condition; or 3) a deliberate and material breach by Mr. Pawelek or Mr. Shaw of material covenants in the employment agreement that result in material adverse effect on our financial condition with a 30-day cure period for Mr. Pawelek and Mr. Shaw. “Disability” means that despite any reasonable accommodation required by law, Mr. Pawelek or Mr. Shaw are unable to perform the essential functions of the position as a result of physical or mental incapacity and that inability has persisted for a period of 120 consecutive days or more in any twelve month period or for more than 180 days. “Good Reason Resignation” means: 1) a material breach of the employment agreement by Brushy; 2) our board of directors determining to move the principal office from San Antonio, Texas; 3) Mr. Pawelek is removed from the position of Chief Executive Officer and/or President or Mr. Shaw is removed from the position of Chief Operating Officer; 4) Mr. Pawelek is required to report to any person other than the our board of directors; 5) a material diminution of Mr. Pawelek’s or Mr. Shaw’s duties, responsibilities and authority as provided in the employment agreement; 6) Mr. Pawelek and Mr. Shaw being required to travel from our principal office in San Antonio, Texas more than 10 days in a three-month period (with a carve out for travel related to road shows and securities offerings); 7) Mr. Pawelek or Mr. Shaw receives a non-extension notice or is not notified of continued employment in a pending business combination; and 8) we fail to deliver new equity compensation awards by the grant dates.

Upon termination by Mr. Pawelek’s or Mr. Shaw’s death, Mr. Pawelek’s estate or Mr. Shaw’s estate receives six months additional base salary plus adjustments with the survival of all vested equity entitlements, indemnity rights and tax benefits. Upon termination by Mr. Pawelek’s or Mr. Shaw’s disability, the officer receives the survival of all vested equity entitlements, indemnity rights and tax benefits plus 18 months of group medical and dental insurance for the officer and his family. Upon termination for Cause, Mr. Pawelek and Mr. Shaw are to receive the survival of all vested equity entitlements, indemnity rights and tax benefits. If Mr. Pawelek or Mr. Shaw is terminated without “Cause” or is subject to a “Good Reason Resignation,” the officer will receive: 1) three years of additional base salary payable as a lump sum; 2) the survival of all vested equity entitlements, indemnity rights and tax benefits; ; 3) 18 months of group medical and dental insurance coverage; and 4) a $500,000 “trigger bonus” (but only if such termination occurs after a business combination).

Table of Contents

Golden Parachute Compensation(1)(2)

Name	Cash ($)(3)			Equity ($)			Perquisites/ Benefits ($)			Tax Reimbursement ($)			Total ($)
Michael Pawelek		1,385,000	(4)		0	(5)		32,018	(6)		621,376	(7)		2,038,394
Chief Executive Officer and President

Edward Shaw		1,175,000	(8)		0	(9)		32,018	(10)		532,693	(11)		1,739,711
Chief Operating Officer

(1)

All amounts reflected in the table are attributable to double-trigger arrangements (i.e., the amounts are triggered by the merger and payment is conditioned upon another event, such as the officer’s involuntary termination or the occurrence of the merger prior to a certain date), except for the lump sum payment of three years of the officer’s base salary conditioned upon involuntary termination only (reflected in footnotes 4 and 8), and the continuation of medical and dental coverage conditioned upon involuntary termination (reflected in footnotes 6 and 10).

(2)	The merger constitutes a “change in control” for purposes of the plans and agreements giving rise to amounts payable reflected in the table.

(3)	As noted in the paragraph preceding the table, the amounts in the table are estimates based on the assumption that the merger will be completed on May 31, 2016.

(4)

Amount reflects the following due to Mr. Pawelek under his employment agreement if his employment is terminated by the employer other than for cause or by him for good reason: (i) $885,000 - a lump sum severance payment equal to three times his annual base salary; and (ii) $500,000 - a guaranteed bonus, to be paid promptly following a 20-day period after the effective date of the merger, if Mr. Pawelek has not been guaranteed continued employment at least five days prior to the merger.

(5)

Pursuant to his employment and option agreements, Mr. Pawelek would be entitled to accelerated vesting of 387,500 Brushy stock options immediately prior to the merger (including 150,000 stock options granted to Mr. Pawelek upon the merger). However, due to the value of our stock, all of Mr. Pawelek’s stock options and other rights thereunder will be terminated in connection with the merger without payment to Mr. Pawelek.

(6)	Amount reflects employer-paid continued group medical and dental insurance for Mr. Pawelek and his immediate family for 18 months following the date of his termination.

(7)	Amount reflects a tax gross-up payment to which Mr. Pawelek would be entitled under his employment agreement in the event that he is subject to excise taxes under Code Section 280G in connection with payments that are contingent upon a change in control.

(8)

Amount reflects the following due to Mr. Shaw under his employment agreement if his employment is terminated by the employer other than for cause or by him for good reason: (i) $675,000 - a lump sum severance payment equal to three times his annual base salary; and (ii) $500,000 - a guaranteed bonus, to be paid promptly following a 20-day period after the effective date of the merger, if Mr. Shaw has not been guaranteed continued employment at least five days prior to the merger.

(9)

Pursuant to his employment and option agreements, Mr. Shaw would be entitled to accelerated vesting of 387,500 Brushy stock options immediately prior to the merger (including 150,000 stock options granted to Mr. Shaw upon the merger). However, due to the value of our stock, all of Mr. Shaw’s stock options and other rights thereunder will be terminated in connection with the merger without payment to Mr. Shaw.

(10)	Amount reflects employer-paid continued group medical and dental insurance for Mr. Shaw and his immediate family for 18 months following the date of his termination.

(11)	Amount reflects a tax gross-up payment to which Mr. Shaw would be entitled under his employment agreement in the event that he is subject to excise taxes under Code Section 280G in connection with payments that are contingent upon a change in control.

Table of Contents

Security Ownership of Management

Title of Class	Name and Address of Beneficial Owner(1)	Amount and Nature of Beneficial Ownership (1)		Percentage of Class
Common Stock	Michael Pawelek, Chief Executive Officer and Director		116,550		0.8957	%
Common Stock	Edward Shaw, Chief Operating Officer		116,550		0.8957	%
Common Stock	N. Kim Vo, Controller		116,550		0.8957	%
Common Stock	Bill Liao, Director,		-		-
Common Stock	Peter Benz, Director and Chairman of Board of Directors⁽²⁾		2,274,778		17.4822	%
Common Stock	Craig Dermody, Director⁽²⁾		254,935		1.9592	%
Common Stock	Charles Henry, III, Director		255,725		1.2250	%
Common Stock	All executive officers, directors and director nominees as a group (8 persons)		3,135,088		24.0938	%

(1)

Beneficial ownership number and percentage is based upon shares of common stock as of February 1, 2016. For purposes of this table, a person or group of persons is deemed to have “beneficial ownership” of any shares which such person has the right to acquire within 60 days. For purposes of computing the percentage of outstanding shares held by each person or group of persons named above, any security which such person or group of persons has the right to acquire within 60 days is deemed to be outstanding for the purpose of computing the percentage ownership for such person or persons, but is not deemed to be outstanding for the purpose of computing the percentage ownership of any other person. As a result, the denominator used in calculating the beneficial ownership among our stockholders may differ.

(2)

2,174,778 shares of common stock are owned by Longview Marquis Fund, L.P., LMIF Investments, LLC, SMF Investments, LLC, all of which are managed by Viking Asset Management, LLC or its affiliates. Mr. Benz is the Chairman of Viking Asset Management, LLC and is one of three persons with voting control over these shares of common stock. Mr. Benz also owns 100,000 shares of common stock personally.

(3)	Mr. Dermody owns 100,000 shares of common stock personally. Rubicon Resources, LLC, a limited liability company co-owned by Mr. Dermody owns 155,725 shares of common stock.

Item 13.

Certain Relationships and Related Transactions, and Director Independence.

CERTAIN RELATIONSHIPS, RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE

Certain Relationships and Related Transactions

Subordinated Credit Facility with SOSventures

The Chairman of our 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 our common stock shares.

On June 3, 2014 we agreed to amend our 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 our assets.

The SOSventures credit agreement requires us to maintain certain financial ratios. First, we must maintain an interest coverage ratio of 3:1 at the end of each quarter so that our consolidated net income less our 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 our interest expense under the credit facility. Second, we must maintain a debt to EBITDAX ratio of less than 3.5:1 at the end of each quarter. Third, we must maintain a current ratio of at greater than 1:1 at the end of each quarter, meaning that our 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 our consolidated current liabilities (excluding non-cash obligations under ASC 410 and 815 and current maturities under the credit facility.)

The credit agreement prevents us from incurring indebtedness to banks or lenders, other than Independent Bank, without the consent of SOSventures, LLC. It also prevents us from incurring most contingent obligations or liens (other than to Independent Bank). It also restricts our ability to pay dividends, issue options and warrants and repurchase our 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 we have $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, we are accruing interest payments to SOSventures since the date of that notice.

Table of Contents

Director Independence

The Company defines “independent director” as an independent director defined by Nasdaq Rule 5605(a)(2). Under the Company’s independent director policy, all references to the Company include the Company’s subsidiaries and “Family Member” means a director’s spouse, parents, children and siblings, whether by blood, marriage or adoption, or anyone residing in the director’s home. Specifically, the Company’s independent directors:

are not Company executive officers or employees or family members of Company executive officers and neither the director nor the family member has been so employed as an executive officer or (for the director only) employee in the past three years;

do not have a relationship which, in the opinion of our Board of Directors, would interfere with the exercise of independent judgment in carrying out the responsibilities of directors or would interfere with the exercise of independent judgment in carrying out the director’s responsibilities;

have not accepted (and have not had a family member accept) compensation from the Company in excess of $120,000 during any twelve consecutive months within the three years preceding the determination of independence except for:

compensation for board or board committee service;

employee compensation paid to a family member of the director, provided that the family member is not an executive officer of the Company;

benefits under tax-qualified retirement plans; and

non-discretionary compensation;

are not and have no family members who are, partners in, or a controlling shareholders or executive officers of, any organization to which the Company made, or from which the Company received, payments for property or services in the current or any of the past three fiscal years that exceed 5% of the recipient's consolidated gross revenues for that year, or $200,000, whichever is more, other than the following:

payments arising solely from investments in our securities; or

payments under non-discretionary charitable contribution matching programs;

are not employed and have no family member who are employed as executive officers of another business entity where, at any time in the past three years, an executive officer of the Company has served on the compensation committee of that entity; or

are not employed and have no family member who are employed as a current partner of our outside auditor, or were partners or employees of our outside auditor who worked on our audit at any time during any of the past three years.

Under these standards, the Company currently views Bill Liao, Charles S. Henry, III and Craig Dermody to be independent directors. We consider payments payable pursuant to the SOSventures subordinated credit facility to be payments arising solely from investments in the Company’s securities.

Peter Benz is affiliated with Viking Asset Management, LLC which manages Longview Marquis Mater Fund, L.P., LMIF Investments LLC and SMF Investments LLC. These shareholders currently have approval rights over our material transactions pursuant to the July 20, 2012 Put Option Waiver Agreement. Those rights terminate upon the Company obtaining an exchange listing. Consequently, if we obtain an exchange listing we anticipate viewing Peter Benz as an independent director.

On May 8, 2013 the Company was notified that the limited partners of these limited partnerships have appointed Charles S. Henry, III the “replacement general partner” of Giddings Oil & Gas LP, Asym Energy Fund III LP and Hunton Oil Partners LP. From May 8, 2013 through February 25, 2014, Giddings Oil & Gas LP, Asym Energy Fund III LP and Hunton Oil Partners LP owned approximately 77.94% of our outstanding common stock. From February 25, 2014 to March 17, 2014, these partnerships owned approximately 13.27% of our outstanding common stock. Thus, Mr. Henry was an affiliated director during this designated time period. Mr. Henry ceased to be an affiliated director no later than March 18, 2014 when the Company interpleaded the common stock shares relating to Giddings Oil & Gas LP, Asym Energy Fund III LP and Hunton Oil Partners LP into the Connecticut Superior Court.

Item 14.

Principal Accountant Fees and Services

Audit Fees.

The aggregate fees billed for earch of the last two fiscal years for professional services rendered by KPMG LLP, one of our former principal accountants, for the audit of our annual financial statements and review of our financial statements included in or Form 10-Q amount to $185,250 for 2014. We had no engagement with KPMG LLP for 2015.

The aggregate fees billed for earch of the last two fiscal years for professional services rendered by Akin Doherty Klein & Fuege, PC, one of our former principal accountants, for the review of our financial statements included in or Form 10-Q amount to $94,500 for 2015. We had no engagement with Akin Doherty Klein & Fuege, PC for 2014.

The aggregate fees billed for professional services by Marcum LLP, our current principal accountants for 2015, for the audit of our annual financial statements amount to $150,000 for 2015. We had no engagement with Marcum LLP for 2014.

Table of Contents

Audit-Related Fees

The Company paid no other aggregate fees billed in each of the last two fiscal years for assurance and related services by KPMG LLP, Akin Doherty Klein & /Fuege, PC or Macrum LLP, our former and current principal accountants, that are reasonably related to the performance of the audit or review of our financial statements.

Tax Fees.

The aggregate fees billed in each of the last two fiscal years for professional services rendered by Rothstein Kass, our former principal accountant, for tax compliance, tax advice, and tax planning amount to $14,000 for 2014.

All Other Fees.

There were no other fees billed in each of the last two fiscal years for products and services by Rothstein Kass, our principal accountant, other than the services reported above.

Audit Committee’s Pre-Approval Policies and Procedures

Our Audit Committee Charter requires that the Audit Committee preapprove all audit services to be provided to the Company, whether provided by the principal auditor or other firms, and all other services (review, attest and non-audit) to be provided to the Company by the independent auditor; provided, however, that de minimis non-audit services may instead be approved in accordance with applicable SEC rules.

Percentage of Services Approved by Audit Committee

Our Audit Committee approved the following percentages of Audit Fees, Audit-Related Fees and Tax Fees for Marcum LLP, Akin Doherty Keline & Fuege PC, and KPMG LLP, our current and former principal accountants, for the designated years.

	Audit Fees			Audit-Related Fees		Tax Fees
2015 – Marcum LLP		100	%		0		0	%
2015 – Akin Doherty Klein & Fuege PC		100	%		-		0	%
2014 – KPMG, LLP		100	%		0		0	%

PART IV

Item 15.

Exhibits, Financial Statement Schedules

EXHIBIT LIST

The following exhibits are included as part of this Form 10-K. References to “the Company” in this Exhibit List mean Brushy Resources, Inc., a Delaware corporation.

Exhibit No.	Reference Description
2.1	Agreement and Plan of Merger, between Lilis Energy, Inc., Lilis Merger Sub, Inc. and Brushy Resources, Inc., dated December 29, 2015 (incorporated by reference to Exhibit 2.1 of the Company’s Form 8-K filed with the SEC on December 31, 2015).

3.1.1	Certificate of Incorporation (incorporated by reference to Exhibit 3.1.1 of the Company’s Form 10 filed with the SEC on June 7, 2013 which became effective August 6, 2013).

3.1.2	Certificate of Conversion (incorporated by reference to Exhibit 3.1.2 of the Company’s Form 10 filed with the SEC on June 7, 2013 which became effective August 6, 2013).

3.1.3	Certificate of Amendment (incorporated by reference to Exhibit 3.1 of the Company’s Form 8-K filed with the SEC on November 13, 2014).

3.2.1	Amended and Restated Bylaws (incorporated by reference to Exhibit 3.2 of the Company’s Form 8-K filed with the SEC on October 31, 2014).

3.2.2	Starboard Resources, LLC Amended and Restated Operating Agreement dated January 20, 2012 (incorporated by reference to Exhibit 3.2.3 of the Company’s Form 10 filed with the SEC on June 7, 2013 which became effective August 6, 2013).

4.1	Securities Purchase and Exchange Agreement between Starboard Resources, LLC, Longview Marquis Master Marquis Fund, L.P., Summerview Marquis Fund, L.P., Longview Marquis Fund, L.P., LMIF Investments, LLC, SMF Investments, LLC, and Summerline Capital Partners, LLC dated June 10, 2011(incorporated by reference to Exhibit 4.1 of the Company’s Form 10 filed with the SEC on June 7, 2013 which became effective August 6, 2013).

Table of Contents

Exhibit No.	Reference Description
4.2	Agreement between Asym Capital III LLC, Giddings Genpar LLC, Hunton Oil Genpar LLC and SOSventures, LLC regarding Starboard Resources, LLC dated January 20, 2012 (incorporated by reference to Exhibit 4.2 of the Company’s Form 10 filed with the SEC on June 7, 2013 which became effective August 6, 2013).

4.3	Agreement between Starboard Resources, LLC, Longview Marquis Master Marquis Fund, L.P., Summerview Marquis Fund, L.P., Longview Marquis Fund, L.P., LMIF Investments, LLC, SMF Investments, LLC, and Summerline Capital Partners, LLC dated July 20, 2012 (Relating to Waiver of Put Option) (incorporated by reference to Exhibit 4.3 of the Company’s Form 10 filed with the SEC on June 7, 2013 which became effective August 6, 2013).

4.4	2014 Equity Compensation Plan (incorporated by reference to Exhibit 3.2 of the Company’s Form 8-K filed October 31, 2014).

10.1.01	Amended and Restated Employment Agreement, dated as of August 14, 2014, between Starboard Resources, Inc. and Michael Pawelek (incorporated by reference to Exhibit 10.1 of the Company’s Form 8-K filed with the SEC on September 4, 2014).

10.1.02	Voting Agreement, between Lilis Energy, Inc., Lilis Merger Sub, Inc., Brushy Resources, Inc. and SOSVentures, LLC, dated December 29, 2015 (incorporated by reference to Exhibit 10.1 of the Company’s Form 8-K filed with the SEC on December 31, 2015).

10.1.03	First Amendment to Forbearance Agreement, between Brushy Resources, Inc., ImPetro Resources, LLC, ImPetro Operating, LLC and Independent Bank, dated February 18, 2016 (incorporated by reference to Exhibit 10.1 of the Company’s Form 8-K filed with the SEC on February 24, 2016).

10.1.04	Second Amendment to Forbearance Agreement, between Brushy Resources, Inc., ImPetro Resources, LLC, ImPetro Operating, LLC and Independent Bank, dated March 9, 2016 (incorporated by reference to Exhibit 10.1 of the Company’s Form 8-K filed with the SEC on March 11, 2016).

10.2.01	Amended and Restated Employment Agreement, dated as of August 14, 2014, between Starboard Resources, Inc. and Edward Shaw (incorporated by reference to Exhibit 10.2 of the Company’s Form 8-K filed with the SEC on September 4, 2014).

10.2.02	Voting Agreement, between Lilis Energy, Inc., Lilis Merger Sub, Inc., Brushy Resources, Inc., Longview Marquis Fund, L.P., LMIF Investments, LLC and SMF Investments LLC, dated December 29, 2015 (incorporated by reference to Exhibit 10.2 of the Company’s Form 8-K filed with the SEC on December 31, 2015).

Table of Contents

Exhibit No.	Reference Description
10.4	Participation Agreement with Husky Ventures, LLC (incorporated by reference to Exhibit 10.4 of the Company’s Form 10 filed with the SEC on June 7, 2013 which became effective August 6, 2013).

10.5.01	Credit Agreement dated as of June 27, 2013 between Starboard Resources, Inc. as borrower and Independent Bank as lender (incorporated by reference to Exhibit 10.5.01 of the Company’s Form 10/A filed with the SEC on July 26, 2013 which became effective August 6, 2013).

10.5.02	Security Agreement dated as of June 27, 2013 between Starboard Resources, Inc. as debtor and Independent Bank as secured party (incorporated by reference to Exhibit 10.5.02 of the Company’s Form 10/A filed with the SEC on July 26, 2013 which became effective August 6, 2013).

10.5.03	Mortgage, Deed of Trust, Security Agreement, Fixture Filing and Financing Statement for Texas oil and gas properties from Starboard Resources, Inc., Mortgagor, to John E. Davis, Trustee, and Independent Bank, mortgagee (incorporated by reference to Exhibit 10.5.03 of the Company’s Form 10/A filed with the SEC on July 26, 2013 which became effective August 6, 2013).

10.5.04	Note from Starboard Resources, Inc. to Independent Bank dated July 27, 2012 (incorporated by reference to Exhibit 10.5.04 of the Company’s Form 10/A filed with the SEC on July 26, 2013 which became effective August 6, 2013).

10.5.05	Certificate of Ownership Interests - Starboard Resources, Inc. dated June 27, 2013 (incorporated by reference to Exhibit 10.5.05 of the Company’s Form 10/A filed with the SEC on July 26, 2013 which became effective August 6, 2013).

10.5.06	Omnibus Certificate - Starboard Resources, Inc. dated June 27, 2013 (incorporated by reference to Exhibit 10.5.06 of the Company’s Form 10/A filed with the SEC on July 26, 2013 which became effective August 6, 2013).


10.5.07	Guaranty dated June 27, 2013 from ImPetro Operating, LLC (incorporated by reference to Exhibit 10.5.07 of the Company’s Form 10/A filed with the SEC on July 26, 2013 which became effective August 6, 2013).

10.5.08	Security Agreement dated June 27, 2013 between ImPetro Operating, LLC and Independent Bank (incorporated by reference to Exhibit 10.5.08 of the Company’s Form 10/A filed with the SEC on July 26, 2013 which became effective August 6, 2013).

10.5.09	Omnibus Certificate - ImPetro Operating, LLC dated June 27, 2013 (incorporated by reference to Exhibit 10.5.09 of the Company’s Form 10/A filed with the SEC on July 26, 2013 which became effective August 6, 2013).

10.5.10	Waiver of Operator’s Lien - ImPetro Operating, LLC dated June 27, 2013 (incorporated by reference to Exhibit 10.5.10 of the Company’s Form 10/A filed with the SEC on July 26, 2013 which became effective August 6, 2013).

10.5.11	Guaranty dated June 27, 2013 from ImPetro Resources, LLC (incorporated by reference to Exhibit 10.5.11 of the Company’s Form 10/A filed with the SEC on July 26, 2013 which became effective August 6, 2013).

10.5.12	Security Agreement dated June 27, 2013 between ImPetro Resources, LLC and Independent Bank (incorporated by reference to Exhibit 10.5.12 of the Company’s Form 10/A filed with the SEC on July 26, 2013 which became effective August 6, 2013).

10.5.13	Omnibus Certificate - ImPetro Resources, LLC dated June 27, 2013 (incorporated by reference to Exhibit 10.5.13 of the Company’s Form 10/A filed with the SEC on July 26, 2013 which became effective August 6, 2013).

10.5.14	Note dated June 27, 2013 - Starboard Resources, Inc. (incorporated by reference to Exhibit 10.5.14 of the Company’s Form 10/A filed with the SEC on July 26, 2013 which became effective August 6, 2013).

10.5.15	Fourth Amendment to Credit Agreement with Independent Bank dated April 15, 2015 (incorporated by reference to Exhibit 10.5.15 of the Company’s Form 10-K filed with the SEC on April 16, 2015)

10.5.17	Forbearance Agreement, between Brushy Resources, Inc., ImPetro Resources, LLC, ImPetro Operating, LLC and Independent Bank, dated November 24, 2015 (incorporated by reference to Exhibit 10.5.17 of the Company’s Form 8-K filed with the SEC on November 27, 2015).

10.5.18	Third Amendment to the First Amended and Restated Credit Agreement, between SOSVentures, LLC and Brushy Resources, Inc., dated November 24, 2015 (incorporated by reference to Exhibit 10.5.18 of the Company’s Form 8-K filed with the SEC on November 27, 2015).

10.6.1	Credit Agreement dated July 25, 2013 between Starboard Resources, Inc. and SOSventures, LLC (incorporated by reference to Exhibit 10.6.1 of the Company’s Form 10/A filed with the SEC on July 26, 2013 which became effective August 6, 2013).

10.6.2	Intercreditor Agreement dated July 25, 2013 between Independent Bank, and SOSventures LLC (incorporated by reference to Exhibit 10.6.2 of the Company’s Form 10/A filed with the SEC on July 26, 2013 which became effective August 6, 2013).

Table of Contents

Exhibit No.	Reference Description
10.6.3	Second Amendment to Credit Agreement between SOSventures, LLC and Starboard Resources dated April 15, 2015 (incorporated by reference to Exhibit 10.6.3 of the Company’s Form 10-K filed with the SEC on April 16, 2015)

10.6.4	Amendment to Intercreditor Agreement between Independent Bank, SOSventures, LLC and Starboard Resources, Inc. dated April 15, 2015 (incorporated by reference to Exhibit 10.6.4 of the Company’s Form 10-K filed with the SEC on April 16, 2015)

10.7.1	Sunoco - Texon LP Crude Purchase Agreement (incorporated by reference to Exhibit 10.7.1 of the Company’s Form 10/A filed with the SEC on July 26, 2013 which became effective August 6, 2013).

10.7.2	Sunoco - Texon LP Crude Purchase Agreement Amendment (incorporated by reference to Exhibit 10.7.2 of the Company’s Form 10/A filed with the SEC on July 26, 2013 which became effective August 6, 2013).

10.8	DCP Midstream, LP Gas Purchase Agreement (incorporated by reference to Exhibit 10.8 of the Company’s Form 10/A filed with the SEC on July 26, 2013 which became effective August 6, 2013).

14	Code of Ethics (incorporated by reference to Annex 3 of the Company’s Schedule 14A filed with the SEC on September 26, 2014).

16.1	Letter from KPMG LLP, dated May 12, 2015 (incorporated by reference to Exhibit 16.1 of the Company’s Form 8-K filed with the SEC on May 12, 2015).

16.2	Letter from Akin, Doherty, Kelin & Feuge, P.C., dated February 2, 2016 (incorporated by reference to Exhibit 16.1 of the Company’s Form 8-K filed with the SEC on February 3, 2016).

21	List of subsidiaries (incorporated by reference to Exhibit 21 of the Company’s Form 10-K filed with the SEC on April 16, 2015)

23.2	Consent of Forrest A. Garb & Associates, Inc., independent petroleum engineers (filed herewith).

31.1	Management Certification - Principal Executive Officer (filed herewith).

31.2	Management Certification - Principal Accounting Officer (filed herewith).

32.1	Section 1350 Certification (filed herewith).

99.1	Fifth Amendment to Credit Agreement with Independent Bank, dated July 31, 2015 (incorporated by reference to Exhibit 99.1 of the Company’s Form 8-K filed with the SEC on August 5, 2015).

99.2	Reserve Report as of January 1, 2016 from Forrest Garb & Associates, Inc (filed herewith )

Table of Contents

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities and Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	BRUSHY RESOURCES, INC.

DATE: April 20, 2016	BY:	/s/ Michael J. Pawelek
		Michael J. Pawelek,
		Chief Executive Officer

Signature	Title	Date

/s/ Michael J. Pawelek	CEO and Director	April 20, 2016
Michael J. Pawelek

/s/ Peter Benz	Director	April 20, 2016
Peter Benz

/s/ Craig Dermody	Director	April 20, 2016
Craig Dermody

/s/ Charles S. Henry, III	Director	April 20, 2016
Charles S. Henry, III

Table of Contents

BRUSHY RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED FINANCIAL STATEMENTS

AND

REPORT OF INDEPENDENT REGISTERED

PUBLIC ACCOUNTING FIRM

DECEMBER 31, 2015 AND 2014

Table of Contents

BRUSHY RESOURCES, INC. AND SUBSIDIARIES

Reports of Independent Registered Public Accounting Firms	F-1

Financial Statements

Consolidated Balance Sheets	F-3

Consolidated Statements of Operations	F-4

Consolidated Statements of Changes in Stockholders' (Deficit) Equity	F-5

Consolidated Statements of Cash Flows	F-6 - F-7

Notes to Consolidated Financial Statements	F-8 - F-20

Supplemental Information

Supplemental Oil and Natural Gas Disclosures	F-21 - F-27

Table of Contents

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

F-1

Table of Contents

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.

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.

KPMG LLP

/s/ KPMG LLP

Dallas, Texas

April 15, 2015

F-2

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

F-3

Table of Contents

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

F-4

Table of Contents

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 Excess of Par		Retained Earnings (Deficit)			Total
	Shares		Amount		Paid-In Capital in Excess of Par		Retained Earnings (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	)

F-5

Table of Contents

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

F-6

Table of Contents

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

F-7

Table of Contents

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.

F-8

Table of Contents

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, geophysic 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.

F-9

Table of Contents

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.

F-10

Table of Contents

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.

F-11

Table of Contents

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.

F-12

Table of Contents

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.

F-13

Table of Contents

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.

F-14

Table of Contents

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.

F-15

Table of Contents

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%.

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.

F-16

Table of Contents

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 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.

F-17

Table of Contents

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.

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:

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.

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:

breach of fiduciary duty;

breach of implied covenant of good faith and fair dealing;

partnership dissolution;

unjust enrichment;

breach of contract;

accounting;

violation of Connecticut Unfair Trade Practices Act;

civil theft; and

piercing the corporate veil.

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.

F-18

Table of Contents

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;

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;”

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)

11)

12)

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

13)

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

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 were 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 were zero. As such, the Company has placed no value on the warrants issued.

F-19

Table of Contents

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.

F-20

Table of Contents

SUPPLEMENTAL INFORMATION

Presented in accordance with

FASB ASC Topic 932, Extractive Activities - Oil and Gas

F-21

Table of Contents

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	)

F-22

Table of Contents

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.

F-23

Table of Contents

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.

F-24

Table of Contents

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

F-25

Table of Contents

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.

F-26

Table of Contents

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.

F-27

Attached files

Brushy Resources, Inc. Reports

Also read