On January 8, 2015, the Company entered into a credit agreement with Heartland, as administrative agent (the “Credit Agreement”) which provides for a three-year senior secured term loan in an initial aggregate principal amount of $3.0 million, which principal amount may be increased to a maximum principal amount of $50.0 million at the request of the Company, subject to certain conditions, and pursuant to an accordion advance provision in the Credit Agreement. The availability of additional funds is subject to the discretion of the lenders, and is generally based on the value of the Company’s proved developed producing (“PDP”) and proved undeveloped (“PUD”) reserves. The Company intends to use proceeds borrowed under the Credit Agreement to fund producing property acquisitions in North America, drill wells in the core of the Company’s lease positions and to fund its working capital.

On April 30, 2015, the Company entered into an Asset Purchase Agreement (the “APA”) with an unaffiliated private seller to acquire non-operated leasehold working interests including interests in 53 producing wells and a 640 gross (499 net) acre block of undeveloped leasehold in the core area of the Wattenberg Field in Weld County, Colorado for approximately $5.5 million in cash. The Company further agreed to pay approximately $1.6 million for the Company’s proportionate share of the ongoing cost of drilling and completing the additional active wells that are currently in progress pursuant to outstanding authorizations for expenditures. The transaction is expected to close prior to June 1, 2015.

 The Company intends to fund the $5.5 million purchase price and associated costs for these assets by drawing down on its Credit Agreement with Heartland acting as administrative agent.

On June 6, 2014, T.R. Winston & Company, LLC (“TR Winston”) executed a commitment to purchase or affect the purchase by third parties of an additional $15.0 million in Series A 8% Convertible Preferred Stock, to be consummated within 90 days thereof. The agreement was subsequently extended and expired on February 22, 2015. On February 25, 2015, the Company and TR Winston agreed in principal to a replacement commitment, pursuant to which TR Winston has agreed to purchase or affect the purchase by third parties of an additional $7.5 million in Series A 8% Convertible Preferred Stock, to be consummated no later than February 23, 2016, with all other terms substantially the same as those of the original commitment.

The Company will require additional capital to satisfy its obligations; to fund its current drilling commitments, as well as its acquisition and capital budget plans; to help fund its ongoing overhead; and to provide additional capital to generally improve its negative working capital position. The Company anticipates that such additional funding will be provided by a combination of capital raising activities, including borrowing transactions, the sale of additional debt and/or equity securities, sale of certain assets, and by the development of certain of the Company’s undeveloped properties via arrangements with joint venture partners. If the Company is not successful in obtaining sufficient cash to fund the aforementioned capital requirements, the Company would be required to curtail its expenditures, and may be required to restructure its operations, sell assets on terms which may not be deemed favorable and/or curtail other aspects of its operations, including deferring all or portions of the Company’s capital budget. There is no assurance that any such funding will be available to the Company on acceptable terms, if at all.

NOTE 3 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES AND ESTIMATES

Basis of Presentation

The condensed financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) for interim financial statements and with Form 10-Q and Article 10 of Regulation S-X of the United States Securities and Exchange Commission. Accordingly, they do not contain all information and footnotes required by GAAP for annual financial statements. In the opinion of the Company’s management, the accompanying unaudited condensed financial statements contain all the adjustments necessary (consisting only of normal recurring accruals) to present the financial position of the Company as of March 31, 2015 and the results of operations and cash flows for the periods presented. The results of operations for the three months ended March 31, 2015 are not necessarily indicative of the operating results for the full fiscal year for any future period.

These condensed financial statements should be read in conjunction with the financial statements and related notes thereto included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2014. The Company’s accounting policies are described in the Notes to Financial Statements in its Annual Report on Form 10-K for the year ended December 31, 2014, and updated, as necessary, in this Quarterly Report on Form 10-Q.

Certain amounts in the 2014 financial statements have been reclassified to conform to the March 31, 2015 financial statements presentation. Such reclassification had no effect on net loss.

Use of Estimates

The preparation of financial statements in conformity with U.S. GAAP requires the Company to make a number of estimates and assumptions relating to the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ significantly from those estimates. Management evaluates estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic and commodity price environment. Although actual results may differ from these estimates under different assumptions or conditions, the Company believes that its estimates are reasonable. 

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 acreage and undeveloped properties, fair value of financial instruments, including derivative liabilities, depreciation and accretion, income taxes and contingencies.

Oil and Gas Producing Activities

The Company follows the full cost method of accounting for oil and gas operations whereby all costs related to the exploration, non-production related development and acquisition of oil and natural gas reserves are capitalized. Such costs include land acquisition costs, geological and geophysical expenses, carrying charges on non-producing properties, costs of drilling, developing and completing productive wells and/or plugging and abandoning non-productive wells, and any other costs directly related to acquisition and exploration activities. Proceeds from property sales are generally applied as a credit against capitalized exploration and development costs, with no gain or loss recognized, unless such a sale would significantly alter the relationship between capitalized costs and the proved reserves attributable to these costs. A significant alteration would typically involve a sale of 25% or more of proved reserves.

The Company accounts for its unproven long-lived assets in accordance with Accounting Standards Codification (“ASC”) Topic 360-10-05, Accounting for the Impairment or Disposal of Long-Lived Assets. ASC Topic 360-10-05 requires that long-lived assets be reviewed for impairment whenever events or changes in circumstances indicate that the historical cost carrying value of an asset may no longer be appropriate.

Depletion of exploration and development costs and depreciation of wells and tangible production assets is computed using the units-of-production method based upon estimated proved oil and gas reserves. Costs included in the depletion base to be amortized include (a) all proved capitalized costs including capitalized asset retirement costs net of estimated salvage values, less accumulated depletion, (b) estimated future development cost to be incurred in developing proved reserves; and (c) estimated decommissioning and abandonment/restoration costs, net of estimated salvage values, that are not otherwise included in capitalized costs.

The costs of undeveloped acreage are withheld from the depletion base until it is determined whether or not proved reserves can be assigned to the properties. When proved reserves are assigned to such properties or one or more specific properties are deemed to be impaired, the cost of such properties or the amount of the impairment is added to full cost pool which is subject to depletion calculations.

Under the full cost method of accounting, capitalized oil and gas property costs less accumulated depletion and net of deferred income taxes may not exceed an amount equal to sum of the present value, discounted at 10%, of estimated future net revenues from proved oil and gas reserves and the cost of unproved properties not subject to amortization (without regard to estimates of fair value), or estimated fair value, if lower, of unproved properties that are not subject to amortization. Should capitalized costs exceed this ceiling, an impairment expense is recognized. During the three months ended March 31, 2015, the Company recorded a $5.46 million impairment. No impairment was recorded in 2014.

The present value of estimated future net cash flows was computed by applying: a flat oil price to forecast revenues from estimated future production of proved oil and gas reserves as of period-end, less estimated future expenditures to be incurred in developing and producing the proved reserves (assuming the continuation of existing economic conditions), less any applicable future taxes.

Wells in Progress

Wells in progress connotes wells that are currently in the process of being drilled or completed or otherwise under evaluation as to their potential to produce oil and gas reserves in commercial quantities. Such wells continue to be classified as wells in progress and withheld from the depletion calculation and the ceiling test until such time as either proved reserves can be assigned, or the wells are otherwise abandoned. Upon either the assignment of proved reserves or abandonment, the costs for these wells are then transferred to the full cost pool and become subject to both depletion and the ceiling test calculations in accordance with full cost accounting under Rule 4-10 of Regulation S-X of the Securities Exchange Act of 1934, as amended.

Revenue Recognition

The Company derives revenue primarily from the sale of produced natural gas and crude oil. The Company reports revenue as the gross amount received before taking into account production taxes and transportation costs, which are reported as separate expenses and are included in oil and gas production expense in the accompanying consolidated statements of operations. Revenue is recorded in the month the Company’s production is delivered to the purchaser, but payment is generally received between 30 and 90 days after the date of production. No revenue is recognized unless it is determined that title to the product has transferred to the purchaser. At the end of each month, the Company estimates the amount of production delivered to the purchaser and the price the Company will receive. The Company uses its knowledge of its properties, its historical performance, existing contracts, NYMEX and local spot market prices, quality and transportation differentials, and other factors as the basis for these estimates.

Impairment of 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

Earnings (losses) per share are computed based on the weighted average number of common shares outstanding during the period presented. Diluted earnings per share are computed using the weighted-average number of common shares outstanding plus the number of common shares that would be issued assuming exercise or conversion of all potentially dilutive common shares.

Potentially dilutive securities, such as shares issuable upon the conversion of debt or preferred stock, and exercise of warrants and options, are excluded from the calculation when their effect would be anti-dilutive. As of March 31, 2015 and 2014 shares underlying options, warrants, preferred stock and convertible debentures have been excluded from the diluted share calculations as they were anti-dilutive as a result of net losses incurred.

The Company had the following Common Stock equivalents at March 31, 2015 and 2014:

Recently Issued Accounting Pronouncements 

Various accounting standards updates are issued, most of which represented technical corrections to the accounting literature or were applicable to specific industries, are not expected to have a material impact on the Company’s financial position and, results of operations.

NOTE 4 - OIL AND GAS PROPERTIES & OIL AND GAS PROPERTIES ACQUISITIONS AND DIVESTITURES

During the quarter ended March, 31, 2015, the Company did not buy or sell any of its oil and gas properties.

If commodity prices stay at current early 2015 levels or decline further, the Company may incur additional full cost ceiling impairments in future quarters. Because the ceiling calculation uses rolling 12-month average commodity prices, the effect of lower quarter-over-quarter prices in 2015 compared to 2014 is a lower ceiling value each quarter. This will result in ongoing impairments each quarter until prices stabilize or improve. Impairment charges would not affect cash flow from operating activities, but would adversely affect the Company’s net income and stockholders’ equity. As a result of this lower ceiling value, during the quarter ended March 31, 2015, the Company recognized an impairment expense on its evaluated oil and gas properties of $5.46 million. No impairment was recognized in 2014.

Depreciation, depletion and amortization (“DD&A”) expenses related to the proved properties were approximately $244,000 and $389,000 for three months ended March 31, 2015 and 2014, respectively.

As of March 31, 2015 and December 31, 2014, the Company had $6.04 million of wells in progress, respectively. Wells in progress are related to certain wells in the Company’s core development program within the Northern Wattenberg field. The Company has capitalized and accrued approximately $5.73 million of costs through March 31, 2015 associated with these wells, which are currently in dispute.

The dispute relates to the Company’s interest in certain producing wells and the well operator’s assertion that the Company’s interest was reduced and/or eliminated as a result of a default or a farm-out agreement. Underlying the dispute is a Joint Operating agreement (“JOA”), which provides the parties with various rights and obligations.

On March 6, 2015, the Company filed a lawsuit against the operator. In its complaint, the Company seeks monetary damages and declaratory relief on claims of breach of contract, breach of the implied covenant of good faith and fair dealing, tortious breach of the implied covenant of good faith and fair dealing, unjust enrichment, conversion and declaratory judgment related to the JOA. The operator has not yet responded to the complaint.

During 2014, the Company transferred $516,000 from wells-in progress to developed oil and natural gas properties for one of its other wells in Northern Wattenberg, when it became producing and economic. The amount transferred to producing properties represents 12.5% of the total 25% interest owned by the Company. The remaining 12.5% ownership in the well is currently being accrued at $491,000 for the authorization for expenditure to drill the wells, since the remaining ownership is being disputed by the mineral owners. The Company purchased the rights from both royalty owners which claimed ownership of the mineral rights. The Company has secured its 12.5% ownership by paying both owners $100,000 (total $200,000). The payment was recorded as an asset to obtain the right to the minerals. By securing the interest with both interest owners, the Company’s interest will remain at 25%.

The mineral owners are disputing the validity of an overriding royalty interest, and as a result, the operator of the well is currently holding revenues from the Company until the dispute is resolved. The Company believes the well is near payout and this should be resolved in the near future. The Company is currently accruing the remaining 12.5% authorization of expenditure and deferring the revenue in a suspense receivable account. The Company received notification that the dispute between the royalty owners has been settled. As a result, the Company is working with the operator to receive payment of its interest.

NOTE 5 - DERIVATIVES

The Company periodically enters into various commodity derivative financial instruments intended to hedge against exposure to market fluctuations of oil prices. As of March 31, 2015 and December 31, 2014, the Company did not have any commodity derivative instruments. Through January 31, 2014, the Company maintained an active commodity swap for 100 barrels of oil per day at a price of $99.25 per barrel. The Company recorded a realized loss on oil price hedges of approximately $11,000 for the three months ended March 31, 2014.

Realized gains and losses are recorded as individual swaps mature and settle. These gains and losses are recorded as income or expenses in the periods during which applicable contracts settle. Swaps which are unsettled as of a balance sheet date are carried at fair value, either as an asset or liability. Unrealized gains and losses result from mark-to-market changes in the fair value of these derivatives between balance sheet dates.

NOTE 6 - FAIR VALUE OF FINANCIAL INSTRUMENTS

The Company measures fair value of its financial assets on a three-tier value hierarchy, which prioritizes the inputs, used in the valuation methodologies in measuring fair value:

The fair value hierarchy also requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value.

The Company’s interest rate term loan and convertible debentures are measured using Level 3 inputs.

Executive Compensation

In September 2013, the Company announced the appointment of Abraham Mirman as its new president. In connection with Mr. Mirman’s appointment, the Company entered into an employment agreement with Mr. Mirman (the “Mirman Agreement”). The Mirman Agreement provides for an incentive bonus package that, depending upon the relative performance of the Company’s Common Stock compared to the performance of stocks of certain peer group companies as measured from Mr. Mirman’s initial date of employment through December 31, 2014, may result in a cash bonus payment to Mr. Mirman of up to 3.0 times his base salary. The incentive bonus is recorded as a liability and valued at each reporting period. The Company engaged a valuation firm (“VFIRM”) to complete a valuation of this incentive bonus. As of December 31, 2014, the Company recorded a liability of $40,000 for accrued compensation. As previously announced, on March 30, 2015, the Company entered into an amended and restated employment agreement (the “CEO Agreement”) with Mr. Mirman. The CEO Agreement also provides for Mr. Mirman to receive a cash incentive bonus if certain production thresholds are achieved by the Company. The Company recorded Mr. Mirman’s new incentive bonus liability, valued by VFIRM, at $43,000 at March 31, 2015.

On March 6, 2015, the Company announced the appointment of Kevin Nanke as its new Executive Vice President and Chief Financial Officer. Mr. Nanke will also receive a cash incentive bonus if certain production thresholds are achieved by the Company and a performance bonus of $100,000 if the Company achieves certain goals set forth in the employment agreement. The Company recorded Mr. Nanke’s new incentive bonus liability, valued by VFIRM, at $29,000 at March 31, 2015.

As previously announced, in March 2015, the Company entered into an employment agreement with Ariella Fuchs for services to be performed as General Counsel to the Company. Ms. Fuchs will also receive a cash incentive bonus if certain production thresholds are achieved by the Company. The Company recorded Ms. Fuchs’ new incentive bonus liability, valued by VFIRM, at $27,000 at March 31, 2015.

Asset Retirement Obligation

The fair value of the Company’s asset retirement obligation liability is calculated at the point of inception by taking into account, the cost of abandoning oil and gas wells, which is based on the Company’s and/or Industry’s historical experience for similar work, or estimates from independent third-parties; the economic lives of its properties, which are based on estimates from reserve engineers; the inflation rate; and the credit adjusted risk-free rate, which takes into account the Company’s credit risk and the time value of money. Given the unobservable nature of the inputs, the initial measurement of the asset retirement obligation liability is deemed to use Level 3 inputs. 

Consulting Agreement with Bristol Capital-Warrant Anti-Dilution Feature

As previously disclosed, on September 2, 2014, the Company entered into a Consulting Agreement (the “Consulting Agreement”) with Bristol Capital, LLC (“Bristol”), pursuant to which the Company issued to Bristol a warrant to purchase up to 1,000,000 shares of Common Stock at an exercise price of $2.00 per share (or, in the alternative, 1,000,000 options, but in no case both). The agreement has an anti-dilution feature that will automatically reduce the exercise price if the Company enters into another consulting agreement pursuant to which warrants are issued with a lower exercise price. On March 31, 2015, the Company revalued the warrants/options using the following variables: (i) warrants/options issued 1,000,000 total (as stated above, the Company will only issue a total of 1,000,000 shares of Common Stock under the option or the warrant, but no more than 1,000,000 shares in the aggregate); (ii) stock price $0.98; (iii) exercise price $ 2.00; expected life of 4.42 years; volatility of 104.5%; risk free rate of 1.25% for a total value of $400,000, which adjusted the change in fair value valuation of the derivative by $6,000 for the three months ended March 31, 2015.

Heartland Credit Agreement - Warrant Anti-Dilution Feature

On January 8, 2015, the Company entered into the Credit Agreement which provides for a three-year senior secured term loan in an initial aggregate principal amount of $3.0 million, which principal amount may be increased to a maximum principal amount of $50.0 million at the request of the Company, subject to certain conditions, and pursuant to an accordion advance provision in the Credit Agreement. Heartland is entitled to receive 75,000 warrants for every $1.0 million advance with an exercise price equal to 115% of the 10-day volume weighted average price (“VWAP”) prior to closing. The Company issued 225,000 warrants (“Initial Warrants”) with the initial advance had an exercise price of $2.50. The Initial Warrants have an anti-dilution feature that will automatically reduce the exercise price if the Company enters into another agreement pursuant to which warrants are issued with a lower exercise price. The Company is carrying the Initial Warrants, valued at January 8, 2015, as a long-term derivative liability and will revalue the instrument every periodic period. On March 31, 2015, the Company revalued the warrants/option using the following variables: On March 31, 2015: (i) warrants issued 225,000; (ii) stock price $0.98; (iii) exercise price $ 2.50; expected life of 4.77 years; volatility of 106.9%; risk free rate of 1.31% for a total value of $99,000, which adjusted the change in fair value valuation of the derivative by $43,000 for the three months ended March 31, 2015. On January 8, 2015: (i) warrants issued 225,000; (ii) stock price $0.72; (iii) exercise price $ 2.50; expected life of 5.0 years; volatility of 97.1%; risk free rate of 1.50% for a total value of $56,000.

Convertible Debentures Conversion Derivative Liability

As of March 31, 2015, the Company had $6.84 million in remaining Debentures, which are convertible at any time at the holders’ option into shares of Common Stock at $2.00 per share, or 3,423,233 underlying conversion shares. The debentures have elements of a derivative due to the potential for certain adjustments, including both the conversion option and the price protection embedded in the Debentures. The conversion option allows the Debenture holders to convert their Debentures to the underlying Common Stock at $2.00. Subject to certain adjustments, including the requirement to reset the conversion for any subsequent offering at a lower price per share amount. The Company values this conversion liability at each reporting period using a Monte Carlo pricing model.

At March 31, 2015 and December 31, 2014, the Company valued the conversion feature associated with the Debentures at $1.36 million and $1.25 million, respectively. The Company used the following inputs to calculate the valuation of the derivative as of March 31, 2015: volatility 110%; conversion price $2.00; stock price $0.98; and present value of conversion feature $0.40 per convertible share and as of December 31, 2014: volatility 70%; conversion price $2.00; stock price $0.72; and present value of conversion feature $0.47 per convertible share. 

The following table provides a summary of the fair values of assets and liabilities measured at fair value (in thousands):

March 31, 2015: 

December 31, 2014: 

The following table provides a summary of changes in fair value of the Company’s Level 3 financial assets and liabilities as of March 31, 2015 (in thousands): 

The Company did not have any transfers of assets or liabilities between Level 1, Level 2 or Level 3 of the fair value measurement hierarchy during the three months ended March 31, 2015 and 2014.

NOTE 7 - LOAN AGREEMENTS

Heartland Bank

On January 8, 2015, Lilis Energy, Inc. (the “Company”) entered into a credit agreement (the “Credit Agreement”) with Heartland, as administrative agent, and the financial institutions from time to time signatory thereto (individually a “Lender,” and any and all such financial institutions collectively the “Lenders”).

The Credit Agreement provides for a three-year senior secured term loan in an initial aggregate principal amount of $3,000,000, which principal amount may be increased to a maximum principal amount of $50,000,000 at the request of the Company pursuant to an accordion advance provision in the Credit Agreement subject to certain conditions, including the discretion of the lender (the “Term Loan”). Funds borrowed under the Credit Agreement may be used by the Company to (i) purchase oil and gas assets, (ii) fund certain Lender-approved development projects, (iii) fund a debt service reserve account, (iv) pay all costs and expenses arising in connection with the negotiation and execution of the Credit Agreement, and (v) fund the Company’s general working capital needs.

The Term Loan bears interest at a rate calculated based upon the Company’s leverage ratio and the “prime rate” then in effect. In connection with its entry into the Credit Agreement, the Company also paid a nonrefundable commitment fee in the amount of $75,000, and agreed to issue to the Lenders 75,000, 5-year warrants for every $1 million funded. An initial warrant to purchase up to 225,000 shares of the Company’s common stock at $2.50 per share was issued in connection with closing. As of January 8, 2015, the Company valued the 225,000 warrants at $56,000 which was accounted for as debt discount and amortized over the life of the debt. See Note 6—Fair Value of Financial Instruments for valuation inputs.

The Company has the right to prepay the Term Loan, in whole or in part, subject to certain conditions. If the Company exercises its right to prepay under the Credit Agreement prior to January 8, 2016, it will be assessed a prepayment premium in an amount equal to 3% of the amount of such prepayment. If the Company exercises its right to prepay under the Credit Agreement after January 8, 2016, such prepayment shall be without premium or penalty.

The Credit Agreement contains certain customary representations and warranties and affirmative and negative covenants. The Credit Agreement also contains financial covenants with respect to the Company’s (i) debt to EBITDAX ratio and (ii) debt coverage ratio. In addition, in certain situations, the Credit Agreement requires mandatory prepayments of the Term Loans, including in the event of certain non-ordinary course asset sales, the incurrence of certain debt, and the Company’s receipt of proceeds in connection with insurance claims.

8% Convertible Debentures

In numerous separate private placement transactions between February 2011 and October 2013, the Company issued an aggregate of approximately $15.6 million of Debentures, secured by mortgages on several of its properties. On January 31, 2014, the Company entered into a Debenture Conversion Agreement (the “Conversion Agreement”) with all of the holders of the Debentures.

As of March 31, 2015 and December 31, 2014, the Company had $6.85 million and $6.84, net, respectively, remaining Debentures which are convertible at any time at the holders’ option into shares of Common Stock at $2.00 per share, subject to certain standard adjustments.

Under the terms of the Conversion Agreement, the balance of the Debentures may be converted to Common Stock on the terms provided in the Conversion Agreement (including the terms related to the Warrants) at the election of the holder, subject to receipt of shareholder approval as required by NASDAQ continued listing requirements. The Company intends to present proposals to approve the conversion of the remaining outstanding Debentures at its 2015 annual meeting of shareholders.

As of March 31, 2015, the Company is in compliance with both the Credit Agreement and the 8% Convertible Debenture covenants.

Inducement Expense

On January 31, 2014, as discussed above, the Company entered into the Conversion Agreement with all of the holders of the Debentures. Under the terms of the Conversion Agreement, $9.0 million of the approximately $15.6 million in Debentures outstanding as of January 30, 2014 immediately converted to shares of Common Stock at a price of $2.00 per common share. As additional inducement for the conversions, the Company issued warrants to the converting Debenture holders to purchase one share of Common Stock, at an exercise price equal to $2.50 per share (the “Warrants”), for each share of Common Stock issued upon conversion of the Debentures. The Company utilized a Black Scholes option price model, with a 3 year life and 65% volatility, risk free rate of 0.2%, and the market price of $3.05. The Company recorded an inducement expense of $6.66 million during the year ended December 31, 2014 for the Warrants. TR Winston acted as the investment banker for the Conversion Agreement and was compensated with 225,000 shares of Common Stock valued at a market price of $3.05 per share. The Company valued the investment banker compensation at $686,000, which was expensed immediately.

Interest Expense

For the three months ended March 31, 2015 and 2014, the Company incurred interest expense of approximately $222,000 and $1.21 million, respectively, of which approximately $172,000 and $1.05 million, respectively, were non-cash interest expense conveyed through property, amortization of the deferred financing costs, accretion of the convertible debentures payable discount, and convertible debentures interest paid in Common Stock.

NOTE 8 - COMMITMENTS and CONTINGENCIES

Environmental and Governmental Regulation

At March 31, 2015, there were no known environmental or regulatory matters which are reasonably expected to result in a material liability to the Company. Many aspects of the oil and gas industry are extensively regulated by federal, state, and local governments in all areas in which the Company has operations. Regulations govern such things as drilling permits, environmental protection and air emissions/pollution control, spacing of wells, the unitization and pooling of properties, reports concerning operations, land use, and various other matters including taxation. Oil and gas industry legislation and administrative regulations are periodically changed for a variety of political, economic, and other reasons. As of March 31, 2015 the Company had not been fined or cited for any violations of governmental regulations that would have a material adverse effect upon the financial condition of the Company.

Legal Proceedings

The Company may from time to time be involved in various legal actions arising in the normal course of business. In the opinion of management, the Company’s liability, if any, in these pending actions would not have a material adverse effect on the financial position of the Company. The Company’s general and administrative expenses would include amounts incurred to resolve claims made against the Company.

Parker v. Tracinda Corporation, Denver District Court, Case No. 2011CV561. In November 2012, the Company filed a motion to intervene in garnishment proceedings involving Roger Parker, the Company’s former Chief Executive Officer and Chairman. The Defendant, Tracinda, served various writs of garnishment on the Company to enforce a judgment against Mr. Parker seeking, among other things, shares of unvested restricted stock. The Company asserted rights to lawful set-offs and deductions in connection with certain tax consequences, which may be material to the Company. The underlying judgment against Mr. Parker was appealed to the Colorado Court of Appeals and, by Order dated October 17, 2013, that Court reversed the trial court with respect to Mr. Parker’s claims of waiver, estoppel and mitigation of damages and remanded with instruction to enter judgment for Mr. Parker. The Court of Appeals also ordered the trial court to conduct further proceedings to determine the amount of damages to award Mr. Parker on his breach of contract claim. The trial court conducted a later hearing and found in its Findings of Fact, Conclusions of Law and Order dated January 9, 2015, in favor of Mr. Parker on his claim for breach of contract, awarding him $6,981,302.60. Tracinda has appealed the ruling of the trial court.

In re Roger A. Parker: Tracinda Corp. v. Recovery Energy, Inc. and Roger A. Parker, United States Bankruptcy Court for the District of Colorado, Case No. 13-10897-EEB. On June 10, 2013, Tracinda Corp. (“Tracinda”) filed a complaint (Adversary No. 13-011301 EEB) against the Company and Roger Parker in connection with the personal bankruptcy proceedings of Roger Parker, alleging that the Company improperly failed to remit to Tracinda certain property in connection with a writs of garnishment issued by the Denver District Court (discussed above). The Company filed an answer to this complaint on July 10, 2013. A trial date has not been set and, by Order dated February 2, 2015, the Bankruptcy Court ordered that the Adversary Proceeding be held in abeyance pending final resolution of the state-court action (2011CV561). The Company is unable to predict the timing and outcome of this matter.

Lilis Energy, Inc. v. Great Western Operating Company LLC, Eighth Judicial District Court for Clark County, Nevada, Case No. A-15-714879-B. On March 6, 2015, the Company filed a lawsuit against the operator. The dispute relates to the Company’s interest in certain producing wells and the well operator’s assertion that the Company’s interest was reduced and/or eliminated as a result of a default or a farm-out agreement. Underlying the dispute is the JOA which provides the parties with various rights and obligations. In its complaint, the Company seeks monetary damages and declaratory relief on claims of breach of contract, breach of the implied covenant of good faith and fair dealing, tortious breach of the implied covenant of good faith and fair dealing, unjust enrichment, conversion and declaratory judgment related to the JOA. The operator has not yet responded to the complaint.

The Company believes there is no other litigation pending that could have, individually or in the aggregate, a material adverse effect on its results of operations or financial condition.

NOTE 9 - RELATED PARTY TRANSACTIONS

G. Tyler Runnels

The Company has participated in several transactions with TR Winston, of which G. Tyler Runnels, currently a member of the Company’s board of directors, is chairman and majority owner. Mr. Runnels also beneficially holds more than 5% of the Company’s Common Stock, including the holdings of TR Winston and his personal holdings, and has personally participated in certain transactions with the Company.

On June 6, 2014, TR Winston executed a commitment to purchase or affect the purchase by third parties of an additional $15 million in Series A 8% Convertible Preferred Stock, to be consummated within 90 days thereof. The agreement was subsequently extended and expired on February 22, 2015. On February 25, 2015, the Company and TR Winston agreed in principal to a replacement commitment, pursuant to which TR Winston has agreed to purchase or affect the purchase by third parties of an additional $7.5 million in Series A 8% Convertible Preferred Stock, to be consummated no later than February 23, 2016, with all other terms substantially the same as those of the original commitment.

Ronald D. Ormand

On March 20, 2014, the Company entered into an Engagement Agreement (the “Engagement Agreement”) with MLV & Co. LLC (“MLV”), pursuant to which MLV will act as the Company’s exclusive financial advisor. Ronald D. Ormand, currently a member of the Company’s board of directors as of February 2015, is the Managing Director and Head of Energy Investment Banking Group at MLV. The Engagement Agreement provides for a fee of $25,000 to be paid monthly to MLV, subject to certain adjustments and other specific fee arrangements in connection with the nature of financial services being provided. The Company expensed $75,000 for the three months ended March 31, 2015 and expensed a total of $25,000 for the three months ended March 31, 2014.

NOTE 10 - SHAREHOLDERS’ EQUITY

During the three months ended March 31, 2015, the Company granted 284,188 shares of restricted stock to employees and board members. The Company reduced the total common shares outstanding at March 31, 2015 by 100,000 shares as a result of an adjustment for restricted stock granted which was forfeited before it vested. The total shares of Common Stock then increased during the quarter ended March 31, 2015 by 184,188, net of the adjustment for restricted stock.

Series A 8% Convertible Preferred Stock

On May 30, 2014, the Company consummated a private placement of 7,500 shares of Series A 8% Convertible Preferred Stock (the “Series A Preferred Stock”), along with detachable warrants to purchase up to 1,556,017 shares of Common Stock, at an exercise price of $2.89 per share, for aggregate gross proceeds of $7.50 million. The Series A Preferred Stock has a par value of $0.0001 per share, a stated value of $1,000 per share, a conversion price of $2.41 per share, and a liquidation preference to any junior securities. In connection with the issuance of the Series A Preferred Stock, the Company also issued a warrant for 50% of the amount of shares of Common Stock into which the Series A Preferred Stock is convertible.

In connection with issuance of the Series A Preferred Stock, the beneficial conversion feature (“BCF”) associated with this series, was valued at $2.21 million and the fair value of the warrant was valued at $1.35 million. The aggregate value of the Series A Preferred Stock and warrant, valued at $3.56 million, was considered a deemed dividend and the full amount was expensed immediately. The Company determined the transaction created a beneficial conversion feature which is calculated by taking the net proceeds of $6.79 million and valuing the warrants as of May 2014, utilizing a Black Scholes option pricing model. The inputs for the pricing model are: $2.48 market price per share; exercise price of $2.89 per share; expected life of 3 years; volatility of 70%; and risk free rate of 0.20%. The Company calculated the total consideration given to be $8.40 million comprised of $6.80 million for the Series A Preferred and $1.6 million for the warrants. The Company deemed the value of the beneficial conversion feature to be $2.21 million and immediately accreted that amount as a deemed dividend. As of March 31, 2015, the Company has accrued a cumulative dividend for $150,000. 

Conditionally Redeemable 6% Preferred Stock

In August 2014, the Company designated 2,000 shares of its authorized preferred stock as Conditionally Redeemable 6% Preferred Stock (“Redeemable Preferred”). All 2,000 shares of Redeemable Preferred were issued in September 2014, pursuant to the Settlement Agreement with Hexagon. The Redeemable Preferred has the same par value and stated value characteristics as the Series A Preferred Stock, yet the Conditionally Redeemable 6% Preferred Stock is not convertible into Common Stock or any other securities of the Company. Except as otherwise required by law, holders of the Redeemable Preferred shall not be entitled to voting rights.

The Redeemable Preferred Stock bears a 6% dividend per annum, payable quarterly, and is redeemable at face value (plus any accrued and unpaid dividends) at any time at the Company’s option, or at the Holders option upon the Company’s achievement of certain production and reserves thresholds. These thresholds include, the Company’s annualized gross production average for 90 consecutive days at 2,500 BOE per day or higher or the Company’s PV-10 value of its producing developed properties filed with the Securities and Exchange Commission exceeds $50 million. On March 31, 2015 and December 31, 2014, the Company revalued the Conditionally Redeemable 6% Preferred Stock using the Monte Carlo pricing for a total value of $1.64 million, which adjusted the change in fair value valuation of the derivative by $46,000 for the three months ended March 31, 2015. On December 31, 2014, the Conditionally Redeemable Preferred Stock was valued at approximately $1.69 million. As of March 31, 2015, the Company has accrued a cumulative dividend for $30,000.

Consulting Agreements

In the ordinary course of business, the Company enters into services agreements for various services including but not limited to strategic planning; management and business operations; introductions to further its business goals; advice and services related to the Company’s growth initiatives; public relations; investment banking and any other consulting or advisory services including the one entered into with Bristol, discussed above. Often times, these agreements provide for an equity compensation component which has been paid in Common Stock, stock options and warrants or a combination thereof. During the three months ended March 31, 2015, Company issued a total of 300,000 warrants that were paid to consultants.

Warrants

A summary of warrant activity for the three months ended March 31, 2015:

The aggregate intrinsic value associated with outstanding warrants was zero at March 31, 2015 and December 31, 2014, respectively, as the strike price of all warrants exceeded the market price for Common Stock, based on the Company’s closing Common Stock price of $0.98 and $0.72, respectively. The weighted average remaining contract life as of March 31, 2015 was 1.47 years, and 1.71 years as of December 31, 2014.

During the three months ended March 31, 2015 and 2014, the Company issued warrants to purchase Common Stock for professional services. The warrants were valued using a Black Sholes model and $204,000 and $643,000 were expensed immediately for the three months ended March 31, 2015 and 2014, respectively.

NOTE 11 - SHARE BASED AND OTHER COMPENSATION

Share-Based Compensation

In September 2012, the Company adopted the 2012 Equity Incentive Plan (the “EIP”). The EIP was amended by the stockholders on June 27, 2013 to increase the number of shares of Common Stock available for grant under the EIP from 900,000 shares to 1,800,000 shares and again on November 13, 2013 to increase the number of shares of Common Stock available for grant under the EIP from 1,800,000 shares to 6,800,000 shares and to increase the number of shares of Common Stock eligible for grant under the EIP in a single year to a single participant from 1,000,000 shares to 3,000,000 shares. Each member of the board of directors and the management team has been periodically awarded stock options and/or restricted stock grants, and in the future may be awarded such grants under the terms of the EIP.

The value of employee services received in exchange for an award of equity instruments is based on the grant-date fair value of the award, recognized over the period during which an employee is required to provide services in exchange for such award. 

During the three months ended March 31, 2015, the Company granted 284,188 shares of restricted Common Stock and 3,450,000 stock options, to employees, directors and consultants. Also during the three months ended March 31, 2015, certain of the Company’s employees, directors and consultants forfeited 100,000 shares of restricted Common Stock and 2,233,333 stock options previously issued in connection with various terminations. As a result, the Company currently has 1,814,855 restricted shares and 4,800,000 options to purchase common shares outstanding to employees and directors. Options issued to employees vest in equal installments over specified time periods during the service period or upon achievement of certain performance based operating thresholds.

The Company requires that employees and directors pay the tax on equity grants in order to issue the shares and there is currently no cashless exercise option. Therefore, as of March 31, 2015, 1,426,917 shares remain issued, but not outstanding.

Compensation Costs

Restricted Stock 

A summary of restricted stock grant activity for the three months ended March 31, 2015 is presented below:

As of March 31, 2015, total unrecognized compensation cost related to the 74,166 unvested shares was approximately $77,000, which is expected to be recognized over a weighted-average remaining service period of 1.07 years. 

During the three months ended March 31, 2015 and 2014, the Company granted restricted stock for professional services. The restricted stock granted was valued at the fair value at the date of grant and vested over the useful life of the service contract. During the three months ended March 31, 2015 and 2014 the Company amortized $57,000 and $95,000, respectively relating to these contracts.

Subsequent to March 31, 2015, the Company issued 300,854 shares to employees and a director upon vesting of restricted shares.

Board of Directors

In October 2013, the Company granted each of its independent directors 200,000 non-statutory options to purchase Common Stock at an exercise price of $2.05 per share, equal to the closing price at October 24, 2013. The options vest one-third for the next three years on the anniversary grant date. The value of the 600,000 options at grant date was $0.64 million and will be amortized over the vesting period.

In connection with execution of an amended independent agreement, each director also agreed to receive 31,250 shares of restricted Common Stock in lieu of a portion of their cash salaries, to vest on April 15, 2014. In December 2014, the Company issued each director 31,250 shares (total for three directors 93,750 shares) for a value of $150,000.

During 2014, the Company granted 650,000 options to purchase Common Stock to certain officer and directors, net of 1.50 million options granted and forfeited in 2014 described in more detail above. Additionally, the Company cancelled 867,000 options for certain officer’s directors that are no longer with the Company.

In April of 2015, the Company amended its non-employee director compensation terms and granted 100,000 shares, vesting over three years, and 450,000 options (250,000 which vested immediately and 200,000 which vest in equal installments over three years) to each of G. Tyler Runnels, General Merrill McPeak and Ronald D. Ormand. See Note 14 —Subsequent Events.

Stock Options

A summary of stock options activity for the three months ended March 31, 2015 is presented below:

As of March 31, 2015, total unrecognized compensation costs relating to the outstanding options was $1,789,000, which is expected to be recognized over the remaining vesting period of approximately 2.47 years.

The outstanding options do not have any intrinsic value at year end, as their weighted average price is greater than the trading price at March 31, 2015. The average life of the options is 3 years and has no intrinsic value as of March 31, 2015.

During the three month ended March 31, 2015 and 2014, the Company issued stock options to purchase Common Stock to certain Officers and Directors. The options are valued using a Black Scholes model and amortized over the life of the option. During the three months ended March 31, 2015 and 2014 the Company amortized $555,000 and $225,000, respectively relating to options outstanding.

NOTE 12- SUBSEQUENT EVENTS

Asset Purchase Agreement

On April 30, 2015, the Company entered into an Asset Sale and Purchase Agreement (the “APA”) with an unaffiliated private seller to acquire non-operated leasehold working interests including interests in 53 producing wells and a 640 gross (499 net) acre block of undeveloped leasehold in the core area of the Wattenberg Field in Weld County, Colorado for approximately $5.5 million in cash. The Company further agreed to pay approximately $1.6 million for the Company’s proportionate share of the ongoing cost of drilling and completing the additional active wells that are currently in progress pursuant to outstanding authorizations for expenditures. The transaction is expected to close prior to June 1, 2015.

The Company intends to fund the $5.5 million purchase price and associated costs for these assets by drawing down on its Credit Agreement with Heartland acting as administrative agent.

Board Compensation

On April 16, 2015, the Board adopted amended terms to the Company’s independent director compensation agreements and established an amended non-employee director compensation program. The Company’s non-employee director compensation program is comprised of the following components:

For more information on the grants of equity compensation to non-employee directors see Note11— Share Based and Other Compensation—Share Based Compensation.

ITEM 2.  MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” contained in our Annual Report on Form 10-K for the year ended December 31, 2014, as well as the unaudited condensed consolidated financial statements and notes thereto included in this Quarterly Report on Form 10-Q. This discussion contains forward-looking statements that involve risks and uncertainties. Our actual results could differ materially from those anticipated in these forward-looking statements as a result of various factors including those set forth under Item “1A. Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2014.

General

Lilis Energy, Inc. is an independent oil and gas company engaged in the acquisition, drilling and production of oil and natural gas properties and prospects within the Denver-Julesburg (“DJ”) Basin. Our business strategy is designed to create shareholder value by developing our undeveloped acreage and leveraging the knowledge, expertise and experience of our management team.

We principally target low to medium risk projects that have the potential for multiple producing horizons, and offer repeatable success allowing for meaningful production and reserve growth. Our acquisition and exploration pursuits of oil and natural gas properties are principally in Colorado, Nebraska, and Wyoming within the DJ Basin.  

Financial Condition and Liquidity

As of March 31, 2015, the Company had a negative working capital balance and a cash balance of approximately $6.39 million and $1.33 million, respectively. Also as of March 31, 2015, the Company had $3.0 million outstanding under its credit agreement with Heartland Bank (“Heartland”), of which $500,000 is due within one year, and $6.85 million outstanding under its 8% Senior Secured Convertible Debentures (the “Debentures”).  

As of March 31, 2015, the Company is currently producing approximately 40 barrels of oil equivalent (“BOE”) a day from eight economically producing wells.

On January 8, 2015, the Company entered into a credit agreement with Heartland, as administrative agent (the “Credit Agreement”) which provides for a three-year senior secured term loan in an initial aggregate principal amount of $3.0 million, which principal amount may be increased to a maximum principal amount of $50.0 million at the request of the Company, subject to certain conditions, and pursuant to an accordion advance provision in the Credit Agreement. The availability of additional funds is subject to the discretion of the lenders, and is generally based on the value of the Company’s proved developed producing (“PDP”) and proved undeveloped (“PUD”) reserves. The Company intends to use proceeds borrowed under the Credit Agreement to fund producing property acquisitions in North America, drill wells in the core of the Company’s lease positions and to fund its working capital.

On April 30, 2015, the Company entered into an Asset Purchase Agreement (the “APA”) with an unaffiliated private seller to acquire non-operated leasehold working interests including interests in 53 producing wells and a 640 gross (499 net) acre block of undeveloped leasehold in the core area of the Wattenberg Field in Weld County, Colorado for approximately $5.5 million in cash. The Company further agreed to pay approximately $1.6 million for the Company’s proportionate share of the ongoing cost of drilling and completing the additional active wells that are currently in progress pursuant to outstanding authorizations for expenditures. The transaction is expected to close prior to June 1, 2015.

The Company intends to fund the $5.5 million purchase price and associated costs for these assets by drawing down on its Credit Agreement with Heartland acting as administrative agent.

On June 6, 2014, T.R. Winston & Company, LLC (“TR Winston”) executed a commitment to purchase or affect the purchase by third parties of an additional $15 million in Series A 8% Convertible Preferred Stock, to be consummated within 90 days thereof. The agreement was subsequently extended and expired on February 22, 2015. On February 25, 2015, the Company and TR Winston agreed in principal to a replacement commitment, pursuant to which TR Winston has agreed to purchase or affect the purchase by third parties of an additional $7.5 million in Series A 8% Convertible Preferred Stock, to be consummated no later than February 23, 2016, with all other terms substantially the same as those of the original commitment.

The Company will require additional capital to satisfy its obligations; to fund its current drilling commitments, as well as its acquisition and capital budget plans; to help fund its ongoing overhead; and to provide additional capital to generally improve its negative working capital position. The Company anticipates that such additional funding will be provided by a combination of capital raising activities, including borrowing transactions, the sale of additional debt and/or equity securities, sale of certain assets, and by the development of certain of the Company’s undeveloped properties via arrangements with joint venture partners. If the Company is not successful in obtaining sufficient cash to fund the aforementioned capital requirements, the Company would be required to curtail its expenditures, and may be required to restructure its operations, sell assets on terms which may not be deemed favorable and/or curtail other aspects of its operations, including deferring all or portions of the Company’s capital budget. There is no assurance that any such funding will be available to the Company on acceptable terms, if at all.

Cash Flows

Cash used in operating activities during the three months ended March 31, 2015 was $1.73 million. Cash used in operating activities offset by the cash used in investing activities and cash provided by financing activities by $821,000, and resulted in a corresponding increase in cash.  

The following table compares cash flow items during the three months ended March 31, 2015 and 2014 (in thousands):

During the three months ended March 31, 2015, net cash used in operating activities was $1.73 million, compared to cash used in operating activities of $1.95 million during the three months ended March 31, 2014, a decrease of cash used in operating activities of $220,000.  The conveyance of oil and gas properties to Hexagon for the reduction of term loan debt in 2014 reduced both the Company’s net oil and gas operating income and interest costs in 2015. Additionally in 2015, the Company increased its cash general and administrative on consultants, legal costs and expanding its management team resulting in similar cash used in operating activities for the periods presented.

During the three months ended March 31, 2015, net cash used in investing activities was $1,000, compared to net cash used in investing activity of $369,000 during the three months ended March 31, 2014, a decrease of cash used in investing activities of $368,000. The Company had limited activity in 2015. During 2014, the Company acquired $305,000 of undeveloped acreage and $49,000 on producing oil and gas properties.  

During the three months ended March 31, 2015, net cash provided by financing activities was $2.55 million, compared to net cash provided by financing activities of $5.01 million during the three months ended March 31, 2014, a decrease $2.46 million. During 2015, the Company received proceeds from the issuance of debt of $3 million offset by a debt issuance cost of $266,000 and dividends of $180,000. While in 2014, the Company received proceeds from the issuance of Common Stock of $5.33 million offset by repayment of debt of $315,000.

Capital Resources and Budget

We anticipate a capital budget of up to $50.0 million for 2015. The budget is allocated toward the acquisition of properties and companies in North America and to develop our drilling opportunities that focus on unconventional reservoirs located in the Wattenberg field within the DJ Basin that will apply horizontal drilling in the Niobrara shale and Codell formations.

The entire capital budget is subject to the securing additional capital through equity placement, utilizing the Credit Agreement from Heartland Bank and additional debt instruments and funds contemplated by the Credit Agreement to acquire production in North America. Some of the proceeds from the initial borrowing under the Credit Agreement were applied to the payment and servicing of our term debt and working capital and participating in working interests in the Wattenberg area.

In addition to the need to secure adequate capital to fund our capital budget, the execution of, and results from, our capital budget are contingent on various factors, including, but not limited to, the sourcing of capital, market conditions, oilfield services and equipment availability, commodity prices and drilling/ production results.  Results from the wells identified in the capital budget may lead to additional adjustments to the capital budget. Other factors that could impact our level of activity and capital expenditure budget include, but are not limited to, a reduction or increase in service and material costs, the formation of joint ventures with other exploration and production companies, and the divestiture of non-strategic assets.

As of March 31, 2015, we had $6.04 million of wells in progress. Wells in progress are related to certain wells in the Company’s core development program within the Northern Wattenberg field. We capitalized and accrued approximately $5.73 million of costs through March 31, 2015 associated with these wells, which are currently in dispute.

The dispute relates to our ownership in certain wells being reduced and or eliminated from a possible farm-out.  The operator of the producing wells claims we entered into a farm-out which will reduce our ownership in the wells. Per the terms of the JOA, if we do not generate enough capital from equity or debt raises, then we may be placed in non-pay status with the operator per a Notice of Default. Should this occur, after 30 days without cure, the operator may forward us a Notice of Non-Consent and a penalty of up to 300% may be imposed in order to buy-back working interest in the newly drilled wells.

On March 6, 2015, we filed a lawsuit against the operator.  In our complaint, we seek monetary damages and declaratory relief on claims of breach of contract, breach of the implied covenant of good faith and fair dealing, tortious breach of the implied covenant of good faith and fair dealing, unjust enrichment, conversion and declaratory judgment related to the JOA between the Company and the operator for tortious actions against us.

Results of Operations

Three months ended March 31, 2015 compared to three months ended March 31, 2014

The following table compares operating data for the three months ended March 31, 2015 and March 31, 2014:

Total revenues

Total revenues were $118,000 for the three months ended March 31, 2015, compared to $834,000 for the three months ended March 31, 2014, a decrease of $715,000, or 86%. The decrease in revenues was due primarily to a decrease in production volumes relating to the conveyance of properties to Hexagon on September 2, 2014 compounded by the 55% drop in realized price per BOE from $76.58 in 2014 to $34.64 in 2015. During the three months ended March 2015 and 2014, production amounts were 3,214 and 10,288 BOE, respectively, a decrease of 7,074 BOE, or 69%.

The following table shows a comparison of production volumes and average prices:

Commodity Price Derivative Activities

Changes in the market price of oil can significantly affect our profitability and cash flow.  In the past we have entered into various commodity derivative instruments to mitigate the risk associated with downward fluctuations in oil prices.  These derivative instruments consisted exclusively of swaps.  The duration and size of our various derivative instruments varies, and depends on our view of market conditions, available contract prices and our operating strategy.

As of March 31, 2015, the Company did not maintain any active commodity swaps.

Production costs

Production costs were $20,000 during the three months ended March 31, 2015, compared to $416,000 for the three months ended March 31, 2014, an decrease $396,000 or 95%. The decrease in production costs were due primarily to a decrease in production volumes relating to the conveyance of properties to Hexagon on September 2, 2014. Additionally, the wells conveyed to Hexagon we’re mature in nature resulting in higher operating costs as compared to the wells retained.

Production taxes

Production taxes were $11,000 for the three months ended March 31, 2015, compared to $94,000 for the three months ended March 31, 2014, a decrease of $83,000, or 88%.  The decline in production taxes is consistent with the decline in production costs as expected given the property conveyance to Hexagon in 2014.

General and administrative

General and administrative expenses were $2.35 million during the three months ended March 31, 2015, compared to $2.96 million during the three months ended March 31, 2014, a decrease of $605,000, or 20%.  The $263,000 increase in cash general and administration costs compared to last year can be attributed to increased compensation relating to additional employees along with higher contract services and legal costs. Non-cash general and administrative items for the three months ended March 31, 2015 were $817,000 compared to $1.69 million during the three months ending March 31, 2014, a decrease of $0.87 million, or 51%. In 2015 the Company issued non-cash equity to certain consultants for $204,000, a $540,000 reduction from the $744,000 incurred in 2014. In 2014, the Company incurred an additional $686,000 in placement fees relating to the conversion of its convertible debt.

Depreciation, depletion, and amortization

Depreciation, depletion, and amortization were $244,000 during the three months ended March 31, 2015, compared to $389,000 during the three months ended March 31, 2014, a decrease of $145,000, or 37%.  Decrease in depreciation, depletion, and amortization was from a decrease in production amounts in 2015 from 2014 primarily relating to the property conveyance to Hexagon, offset $9.9 million transferred to the depletion pool from unevaluated properties in 2014 resulting in an increased depletion rate.  Production amounts decreased to 3,214 from 10,288 for the three months ended March 31, 2015 and 2014, respectively, a decrease of 7,074, or 69%. Depreciation, depletion, and amortization per BOE increased to $75.79 from $37.78, respectively, for the three months ended March 31, 2015 and 2014, an increase of $38.01, or 101%. 

Inducement expense

In January 2014, the Company entered into the Conversion Agreement between the Company and all of the holders of the Debentures.  Under the terms of the Conversion Agreement, $9.0 million of the approximately $15.6 million in Debentures then outstanding converted to common stock at a price of $2.00 per common share.  As inducement for the Company issued warrants to the converting Debenture holders to purchase one share of Common Stock, at an exercise price equal to $2.50 per share (the “Warrants”), for each share of Common Stock issued upon conversion of the Debentures. The Company used a Lattice model to value the warrants, utilizing a volatility of 65%, and a life of 3 years, which arrived at a fair value of $6.67 million for the Warrants and expensed immediately.

Impairment of evaluated oil and gas properties

Under the full cost method of accounting, capitalized oil and gas property costs less accumulated depletion and net of deferred income taxes may not exceed an amount equal to sum of the present value, discounted at 10%, of estimated future net revenues from proved oil and gas reserves and the cost of unproved properties not subject to amortization (without regard to estimates of fair value), or estimated fair value, if lower, of unproved properties that are not subject to amortization. Should capitalized costs exceed this ceiling, an impairment expense is recognized.

During the quarter ended March 31, 2015, the Company recognized an impairment expense on its evaluated oil and gas properties of $5.46 million. No impairment was recognized in 2014.

Interest Expense

For the three months ended March 31, 2015 and 2014, the Company incurred interest expense of approximately $222,000 and $1.21 million, respectively, of which approximately $172,000 and $1.05 million, respectively, were non-cash interest expense and amortization of the deferred financing costs, accretion of the convertible debentures payable discount, and convertible debentures interest paid in common stock.

Change in Bristol/Heartland warrant liability

The equity instruments issued to both Bristol and Heartland have an anti-dilution feature that will automatically reduce the exercise price if the Company enters into another consulting agreement (in the case of Bristol) or any agreement (in the case of Heartland) pursuant to which warrants are issued with a lower exercise price. The change in fair value of this warrant provision was $49,000 for the three months ended March 31, 2015.

Change in fair value of derivative liabilities

For the three months ended March 31, 2015 and 2014, we incurred a change in the fair value of the derivative liability related to the convertible debentures of approximately $112,000 and $9.02 million, respectively. During the year ended December 31, 2014, we reduced the conversion price from $4.25 to $2.00, consistent with the January Private Placement. The conversion resulted in a reduction of the convertible debenture liability by $5.69 million and an increase in additional paid in capital.

Off-Balance Sheet Arrangements

We do not have any material off-balance sheet arrangements.

Overview of Our Business, Strategy, and Plan of Operations

We have acquired and developed a producing base of oil and natural gas proved reserves, as well as a portfolio of exploration and other undeveloped assets with conventional and non-conventional reservoir opportunities, with an emphasis on those with multiple producing horizons, in particular the Muddy “J” conventional reservoirs and the Niobrara shale and Codell formation resource plays. We believe these assets offer the possibility of repeatable year-over-year success and significant and cost-effective production and reserve growth. Our acquisition, development and exploration pursuits are principally directed at oil and natural gas properties in the DJ Basin in Colorado, Nebraska, and Wyoming. As of March 31, 2015 we owned interests in approximately 37,000 gross (31,000 net) leasehold acres, of which 30,000 gross (24,000 net) acres are classified as undeveloped acreage and all of which are located in Colorado, Wyoming and Nebraska within the DJ Basin.   We are primarily focused on our North and South Wattenberg Field, assets which include attractive unconventional reservoir drilling opportunities in mature development areas that offer low risk Niobrara and Codell formation productive potential.  We also believe that our conventional reservoir development potential in our Silo-East, Hanson and Wilke/Lukassen well areas will yield competitive results. We expect to pursue an aggressive multi-well program.

Our intermediate goal is to create significant value via the investment of up to $50.0 million in our inventory of low and controlled-risk conventional and unconventional properties, while maintaining a low cost structure. To achieve this, our business strategy includes the following elements:

Pursuing the initial development of our Greater Wattenberg Field unconventional assets.  We plan to drill several horizontal wells on our South Wattenberg property during 2015. Drilling activities will target the well-established Niobrara and Codell formations.  Subject to the securing of additional capital, we expect to drill and operate up to 8 wells, with an expected investment of approximately $18.0 million.

Extending the development of certain conventional prospects within our inventory of other DJ Basin properties.  Subject to the securing of additional capital, we anticipate the expenditure of up to an additional $50.0 million in drilling and development costs on three of our DJ Basin assets where initial exploration has yielded positive results. Additional drilling activities will be conducted on each property in an effort to fully assess each property and define field productivity and economic limits.  

Retain Operational Control and Significant Working Interest.  In our principal development targets, we typically seek to maintain operational control of our development and drilling activities.   As operator, we retain more control over the timing, selection and process of drilling prospects and completion design, which enhances our ability to maximize our return on invested capital and gives us greater control over the timing, allocation and amounts of capital expenditures.  However, due to our recent liquidity difficulties, a significant amount of our current drilling activity on wells in which we own an interest is not operated by us. 

Leasing of Prospective Acreage.  In the course of our business, we identify drilling opportunities on properties that have not yet been leased.  Subject to securing additional capital, we may take the initiative to lease prospective acreage and we may sell all or any portion of the leased acreage to other companies that want to participate in the drilling and development of the prospect acreage.

Hedging. From time to time, we use commodity price hedging instruments to reduce our exposure to oil and natural gas price fluctuations and to help ensure that we have adequate cash flow to fund our debt service costs and capital programs. As such, we will enter into futures contracts, collars and basis swap agreements, as well as fixed price physical delivery contracts. We intend to use hedging primarily to manage price risks and returns on certain acquisitions and drilling programs. Our policy is to consider hedging an appropriate portion of our production at commodity prices we deem attractive. In the future we may also be required by our lenders to hedge a portion of production as part of any financing.

Acreage. Currently, our inventory of developed and undeveloped acreage includes approximately 8,000 net acres that are held by production, approximately, 23,000, 2,000, 5,000 and 1,000 net acres that expire in the years 2015, 2016, 2017, and thereafter, respectively. Approximately 88% of our inventory of undeveloped acreage provides for extension of lease terms from two to five years, at the option of us, via payment of varying, but typically nominal, extension amounts. We’re currently evaluating the 2015 lease expirations to determine if this acreage is a focus for future development. If determined to be a focus for future development, we plan to re-lease if available. If not a focus, we plan to let the acreage expire. We plan to borrow additional funds under the Credit Agreement to acquire additional bolt-on properties, acquire other properties throughout North America, or drill wells on our core properties to hold the property by production.

Capital Raising. The business of oil and natural gas property acquisition, exploration and development is highly capital intensive and the level of operations attainable by oil and natural gas companies is directly linked to and limited by the amount of available capital. Therefore, a principal part of our plan of operations is to raise the additional capital required to finance the exploration and development of our current oil and natural gas prospects and the acquisition of additional properties. We will need to raise additional capital to fund our exploration and development, and operating, budget. We plan to seek additional capital through the sale of our securities, through debt and project financing, joint venture agreements with industry partners, and through sale of assets. Our ability to obtain additional capital through new debt instruments, project financing and sale of assets may be subject to the repayment of our existing obligations.

Outsourcing. We intend to continue to use the services of independent consultants and contractors to provide various professional services, including land, legal, environmental, technical, investor relations and tax services.  We believe that by limiting our management and employee costs, we may be able to better control lifting costs and retain G&A flexibility. 

Marketing and Pricing

We derive revenue principally from the sale of oil and natural gas.  As a result, our revenues are determined, to a large degree, by prevailing prices for crude oil and natural gas.  We sell our oil and natural gas on the open market at prevailing market prices or through forward delivery contracts.  The market price for oil and natural gas is dictated by supply and demand, and we cannot accurately predict or control the price we may receive for our oil and natural gas.

Our revenues, cash flows, profitability and future rate of growth will depend substantially upon prevailing prices for oil and natural gas.  Prices may also affect the amount of cash flow available for capital expenditures and our ability to borrow money or raise additional capital.  Lower prices may also adversely affect the value of our reserves and make it uneconomical for us to commence or continue production levels of oil and natural gas.  Historically, the prices received for oil and natural gas have fluctuated widely.  Among the factors that can cause these fluctuations are:

From time to time, we will enter into hedging arrangements to reduce our exposure to decreases in the prices of oil and natural gas.  Hedging arrangements may expose us to risk of significant financial loss in some circumstances including circumstances where:

In addition, hedging arrangements may limit the benefit we would receive from increases in the prices for oil and natural gas.  We cannot assure you that any hedging transactions we may enter into will adequately protect us from declines in the prices of oil and natural gas.  On the other hand, where we choose not to engage in hedging transactions in the future, we may be more adversely affected by changes in oil and natural gas prices than our competitors who engage in hedging transactions. 

Critical Accounting Policies and Estimates

The preparation of our consolidated financial statements in conformity with generally accepted accounting principles in the United States, or GAAP, requires our management to make assumptions and estimates that affect the reported amounts of assets, liabilities, revenues and expenses, as well as the disclosure of contingent assets and liabilities at the date of our financial statements and the reported amounts of revenues and expenses during the reporting period.  The following is a summary of the significant accounting policies and related estimates that affect our financial disclosures.

Critical accounting policies are defined as those significant accounting policies that are most critical to an understanding of a company’s financial condition and results of operation. We consider an accounting estimate or judgment to be critical if (i) it requires assumptions to be made that were uncertain at the time the estimate was made, and (ii) changes in the estimate or different estimates that could have been selected could have a material impact on our results of operations or financial condition.

Use of Estimates

The financial statements included herein were prepared from our records in accordance with GAAP, and reflect all normal recurring adjustments which are, in the opinion of management, necessary to provide a fair statement of the results of operations and financial position for the interim periods.  The preparation of the financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of oil and gas reserves, assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period.  We evaluate our estimates on an on-going basis and base our estimates on historical experience and on various other assumptions we believe to be reasonable under the circumstances.  Although actual results may differ from these estimates under different assumptions or conditions, we believe that our estimates are reasonable.  Our most significant financial estimates are associated with our estimated proved oil and gas reserves, assessments of impairment imbedded in the carrying value of undeveloped acreage and proven properties, as well as valuation of Common Stock used in various issuances of Common Stock, options and warrants, and estimated derivative liabilities.

Oil and Natural Gas Reserves

We follow the full cost method of accounting.  All of our oil and gas properties are located within the United States, and therefore all costs related to the acquisition and development of oil and gas properties are capitalized into a single cost center referred to as a full cost pool.  Depletion of exploration and development costs and depreciation of production equipment is computed using the units-of-production method based upon estimated proved oil and gas reserves.  Under the full cost method of accounting, capitalized oil and gas property costs less accumulated depletion and net of deferred income taxes may not exceed an amount equal to the present value, discounted at 10%, of estimated future net revenues from proved oil and gas reserves less the future cash outflows associated with the asset retirement obligations that have been accrued on the balance sheet plus the cost, or estimated fair value if lower, of unproved properties.  Should capitalized costs exceed this ceiling, impairment would be recognized.  Under the SEC rules, we prepared our oil and gas reserve estimates as of December 31, 2014, using the average, first-day-of-the-month price during the 12-month period ending December 31, 2014.

Estimating accumulations of gas and oil is complex and is not exact because of the numerous uncertainties inherent in the process.  The process relies on interpretations of available geological, geophysical, engineering and production data.  The extent, quality and reliability of this technical data can vary.  The process also requires certain economic assumptions, some of which are mandated by the SEC, such as gas and oil prices, drilling and operating expenses, capital expenditures, taxes and availability of funds.  The accuracy of a reserve estimate is a function of the quality and quantity of available data; the interpretation of that data; the accuracy of various mandated economic assumptions; and the judgment of the persons preparing the estimate. 

We believe estimated reserve quantities and the related estimates of future net cash flows are the most important estimates made by an exploration and production company such as ours because they affect the perceived value of our company, are used in comparative financial analysis ratios, and are used as the basis for the most significant accounting estimates in our financial statements, including the quarterly calculation of depletion, depreciation and impairment of our proved oil and natural gas properties.  Proved oil and natural gas reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future periods from known reservoirs under existing economic and operating conditions. We determine anticipated future cash inflows and future production and development costs by applying benchmark prices and costs, including transportation, quality and basis differentials, in effect at the end of each quarter to the estimated quantities of oil and natural gas remaining to be produced as of the end of that quarter. We reduce expected cash flows to present value using a discount rate that depends upon the purpose for which the reserve estimates will be used.  For example, the standardized measure calculation requires us to apply a 10% discount rate.  Although reserve estimates are inherently imprecise, and estimates of new discoveries and undeveloped locations are more imprecise than those of established proved producing oil and natural gas properties, we make considerable effort to estimate our reserves, including through the use of independent reserves engineering consultants. We expect that quarterly reserve estimates will change in the future as additional information becomes available or as oil and natural gas prices and operating and capital costs change.  We evaluate and estimate our oil and natural gas reserves as of December 31 and quarterly throughout the year.  For purposes of depletion, depreciation, and impairment, we adjust reserve quantities at all quarterly periods for the estimated impact of acquisitions and dispositions.  Changes in depletion, depreciation or impairment calculations caused by changes in reserve quantities or net cash flows are recorded in the period in which the reserves or net cash flow estimate changes.

Oil and Natural Gas Properties—Full Cost Method of Accounting

We use the full cost method of accounting whereby all costs related to the acquisition and development of oil and natural gas properties are capitalized into a single cost center referred to as a full cost pool.  These costs include land acquisition costs, geological and geophysical expenses, carrying charges on non-producing properties, costs of drilling and overhead charges directly related to acquisition and exploration activities.

Capitalized costs, together with the costs of production equipment, are depleted and amortized on the unit-of-production method based on the estimated gross proved reserves as determined by independent petroleum engineers. For this purpose, we convert our petroleum products and reserves to a common unit of measure.

Costs of acquiring and evaluating unproved properties are initially excluded from depletion calculations.  This undeveloped acreage is assessed quarterly to ascertain whether impairment has occurred.  When proved reserves are assigned or the property is considered to be impaired, the cost of the property or the amount of the impairment is added to the full cost pool and becomes subject to depletion calculations.

Proceeds from the sale of oil and natural gas properties are applied against capitalized costs, with no gain or loss recognized, unless the sale would alter the rate of depletion by more than 25%.  Royalties paid, net of any tax credits received, are netted against oil and natural gas sales. 

In applying the full cost method, we perform a ceiling test on properties that restricts the capitalized costs, less accumulated depletion, from exceeding an amount equal to the estimated undiscounted value of future net revenues from proved oil and natural gas reserves, as determined by independent petroleum engineers.  The estimated future revenues are based on sales prices achievable under existing contracts and posted average reference prices in effect at the end of the applicable period, and current costs, and after deducting estimated future general and administrative expenses, production related expenses, financing costs, future site restoration costs and income taxes.  Under the full cost method of accounting, capitalized oil and natural gas property costs, less accumulated depletion and net of deferred income taxes, may not exceed an amount equal to the present value, discounted at 10%, of estimated future net revenues from proved oil and natural gas reserves, plus the cost, or estimated fair value if lower, of unproved properties. Should capitalized costs exceed this ceiling, we would recognize impairment.

Item 3.  Quantitative and Qualitative Disclosures about Market Risk.

Not Applicable

Item 4.  Controls and Procedures.

Evaluation of Disclosure Controls and Procedures

The Company’s Chief Executive Officer and Chief Financial Officer have evaluated the effectiveness of the Company’s disclosure controls and procedures (as such term is defined in Rules 13a-15(e) under the Securities Exchange Act of 1934, as amended, the Exchange Act) as of March 31, 2015 Disclosure controls and procedures are controls and other procedures designed to ensure that information required to be disclosed by the Company in its reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms and include, without limitation, controls and procedures designed to ensure that information that the Company is required to disclose in such reports is accumulated and communicated to management, including our Chief Executive Officer and our Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosures. Based upon that evaluation, our Chief Executive Officer and our Chief Financial Officer concluded that, as of March 31, 2015, the Company’s disclosure controls and procedures were still not adequate, due to the material weaknesses in internal controls over financial reporting described below.

Internal Controls over Financial Reporting

Management is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Rules 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.

Based on the evaluation and the identification of the material weakness in internal control over financial reporting described below, our Chief Executive Officer and our Chief Financial Officer have concluded that, as of March 31, 2015, the Company’s internal controls and procedures were not effective.

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. In connection with management’s assessment of our internal control over financial reporting, conducted based on the Internal Control—Integrated Framework issued by COSO (1992), we identified the following material weaknesses in our internal control over financial reporting as of December 31, 2014:

Restatement of Previously Issued Financial Statements

In February 2015, the Company discovered an error in the valuation of the conversion derivative liability of the Company’s Debentures for the periods ended December 31, 2011, December 31, 2012, December 31, 2013, March 31, 2014 and June 30, 2014 (together, the “Relevant Periods”). Specifically, the calculation of the conversion liability included in the Company’s financial statements for the Relevant Periods only included the value of the price protection (anti-dilution) feature, when it should have included both the conversion option and the price protection embedded in the Debentures. The changes in the value of the derivative resulted in changes to the Company’s financial statements, which warranted restatement of the Company’s Quarterly Reports on Form 10-Q for the fiscal quarters ended September 30, 2013, March 31, 2014 and June 30, 2014.

As a result of the restatement described herein, the Company’s Chief Executive Officer and Chief Financial Officer, with the assistance of other members of management and expert internal control consultants, re-evaluated the effectiveness of the Company’s internal controls over financial reporting as of December 31, 2014 in accordance with the assessment and testing procedures described above. Based on this re-evaluation, and because the impact of the errors on the Company’s quarterly financial statements for the fiscal quarters ended September 30, 2013, March 31, 2014 and June 30, 2014, was sufficiently material to warrant restatement of the Company’s quarterly reports on Form 10-Q for those periods, we have determined that the following additional material weakness in internal controls over financial reporting existed as of December 31, 2014:

Because of the material weaknesses described above, management has concluded that we did not maintain effective internal control over financial reporting as of March 31, 2015, based on the Internal Control—Integrated Framework issued by COSO (1992).

Remediation Efforts

We plan to make necessary changes and improvements to the overall design of our control environment to address the material weaknesses in internal control over financial reporting described above. In particular, we have hired and expect to hire additional employees to assist with strengthening the segregation of duties and control activities in journal entry processing and complex accounting issues such as those related to our convertible debentures. We also expect to hire an external expert to help with the valuation of convertible debentures. Additionally, we have begun to perform an analysis of all automated and manual procedures to strengthen the effectiveness of our segregation of duties and control environment. At any time, if it appears any control can be implemented to mitigate risks, it is immediately implemented.

In the fourth quarter of 2014, we implemented a new extensive Travel and Expense policy which all employees and directors are required to review and sign. Furthermore, the Company has required all employees and directors to review and sign all of the Company’s corporate documents which include, but are not limited to, the Code of Ethics, By-laws, and Corporate Governance Policy. The Company is planning to test the remediation in second quarter of 2015 and fully remediate the weakness by that time.

In March 2015, we appointed Kevin Nanke Chief Financial Officer. Mr. Nanke will bring additional oversight in financial reporting and strengthen the segregation of duties.

Management believes through their appointment of a new Chief Financial Officer and the implementation of the foregoing policies, they will significantly improve our control environment, the completeness and accuracy of underlying accounting data and the timeliness with which we are able to close our books. Management is committed to continuing efforts aimed at fully achieving an operationally effective control environment and timely filing of regulatory required financial information. The remediation efforts noted above are subject to our internal control assessment, testing, and evaluation processes. While these efforts continue, we will rely on additional substantive procedures and other measures as needed to assist us with meeting the objectives otherwise fulfilled by an effective control environment.

Changes in Internal Control over Financial Reporting

Other than those described above, management has determined that there were no changes in the Company’s internal controls over financial reporting during the first quarter of 2015 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting. 

PART II - OTHER INFORMATION

Item 1. Legal Proceedings.

Parker v. Tracinda Corporation, Denver District Court, Case No. 2011CV561. In November 2012, the Company filed a motion to intervene in garnishment proceedings involving Roger Parker, the Company’s former Chief Executive Officer and Chairman. The Defendant, Tracinda, served various writs of garnishment on the Company to enforce a judgment against Mr. Parker seeking, among other things, shares of unvested restricted stock. The Company asserted rights to lawful set-offs and deductions in connection with certain tax consequences, which may be material to the Company. The underlying judgment against Mr. Parker was appealed to the Colorado Court of Appeals and, by Order dated October 17, 2013, that Court reversed the trial court with respect to Mr. Parker’s claims of waiver, estoppel and mitigation of damages and remanded with instruction to enter judgment for Mr. Parker. The Court of Appeals also ordered the trial court to conduct further proceedings to determine the amount of damages to award Mr. Parker on his breach of contract claim. The trial court conducted a later hearing and found in its Findings of Fact, Conclusions of Law and Order dated January 9, 2015, in favor of Mr. Parker on his claim for breach of contract, awarding him $6,981,302.60. Tracinda has appealed the ruling of the trial court.

In re Roger A. Parker: Tracinda Corp. v. Recovery Energy, Inc. and Roger A. Parker, United States Bankruptcy Court for the District of Colorado, Case No. 13-10897-EEB. On June 10, 2013, Tracinda Corp. (“Tracinda”) filed a complaint (Adversary No. 13-011301 EEB) against the Company and Roger Parker in connection with the personal bankruptcy proceedings of Roger Parker, alleging that the Company improperly failed to remit to Tracinda certain property in connection with a writs of garnishment issued by the Denver District Court (discussed above). The Company filed an answer to this complaint on July 10, 2013. A trial date has not been set and, by Order dated February 2, 2015, the Bankruptcy Court ordered that the Adversary Proceeding be held in abeyance pending final resolution of the state-court action (2011CV561). The Company is unable to predict the timing and outcome of this matter.

Lilis Energy, Inc. v. Great Western Operating Company LLC, Eighth Judicial District Court for Clark County, Nevada, Case No. A-15-714879-B. On March 6, 2015, the Company filed a lawsuit against the operator. The dispute relates to the Company’s interest in certain producing wells and the well operator’s assertion that the Company’s interest was reduced and/or eliminated as a result of a default or a farm-out agreement. Underlying the dispute is the JOA which provides the parties with various rights and obligations. In its complaint, the Company seeks monetary damages and declaratory relief on claims of breach of contract, breach of the implied covenant of good faith and fair dealing, tortious breach of the implied covenant of good faith and fair dealing, unjust enrichment, conversion and declaratory judgment related to the JOA. The operator has not yet responded to the complaint.

The Company believes there is no other litigation pending that could have, individually or in the aggregate, a material adverse effect on its results of operations or financial condition.

Item 1A. Risk Factors.

There has been no material change in our Risk Factors from those reported in Part I, Item 1A of our 2014 Annual Report on Form 10-K filed with the Securities and Exchange Commission, which we incorporate by reference herein.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds.

None.

Item 6. Exhibits.

† Indicates a management contract or any compensatory plan, contract or arrangement.

SIGNATURES

Pursuant to the requirements 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

EXHIBIT INDEX

† Indicates a management contract or any compensatory plan, contract or arrangement.

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