LILIS ENERGY, INC. (Form: 10-Q, Received: 06/17/2014 06:02:53)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

x QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2014

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

For the transition period from ______to______.

	001-35330
	(Commission File No.)

Lilis ENERGY, INC.

(Exact name of registrant as specified in charter)

NEVADA		74-3231613
(State or other jurisdiction of incorporation or organization)		(IRS Employee Identification No.)

1900 Grant Street, Suite #720

Denver, CO 80203

(Address of Principal Executive Offices)

(303) 951-7920

(Registrant’s telephone number, including area code)

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

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company (as defined in Rule 12b-2 of the Act):

Large accelerated filer	o	Accelerated filer	o
Non-accelerated filer	o	Smaller reporting company	x

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

As of June 16, 2014, 27,728,827 shares of the registrant’s common stock were issued and outstanding.

Lilis Energy, Inc.

INDEX

PART I– FINANCIAL INFORMATION

Item 1.	Financial Statements (Unaudited)	1
	Consolidated Balance Sheets as of March 31, 2014 and December 31, 2013		1
	Consolidated Statements of Operations for the Three Months Ended March 31, 2014 and 2013		3
	Consolidated Statements of Cash Flows for the three Months Ended March 31, 2014 and 2013		4
	Notes to Consolidated Financial Statements		5

Item 2.	Management’s Discussion and Analysis of Financial Condition		18

Item 3.	Quantitative and Qualitative Disclosures About Market Risk		26

Item 4.	Control and Procedures		27

PART II– OTHER INFORMATION

Item 1.	Legal Proceedings	28
Item 1A.	Risk Factors	28
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	28
Item 3.	Defaults Upon Senior Securities	28
Item 4.	Mine Safety Disclosures	28
Item 5.	Other Information	29
Item 6.	Exhibits	29

SIGNATURES		30

EXHIBIT INDEX		31

FORWARD-LOOKING STATEMENTS

This quarterly report, including materials incorporated by reference herein, contains “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. All statements other than statements of historical fact are “forward-looking statements” for purposes of federal and state securities laws, including, but not limited to, any projections of earnings, revenue or other financial items; any statements of the plans, strategies and objectives of management for future operations; any statements concerning future production, reserves or other resource development opportunities; any projected well performance or economics, or potential joint ventures or strategic partnerships; any statements regarding future economic conditions or performance; any statements regarding future capital-raising activities; any statements of belief; and any statements of assumptions underlying any of the foregoing.

Forward-looking statements may include the words “may,” “should,” “could,” “estimate,” “intend,” “plan,” “project,” “continue,” “believe,” “expect” or “anticipate” or other similar words. These forward-looking statements present our estimates and assumptions only as of the date of this presentation. Except as required by law, we do not intend, and undertake no obligation, to update any forward-looking statement.

Although we believe that the expectations reflected in any of our forward-looking statements are reasonable, actual results could differ materially from those projected or assumed in any of our forward-looking statements. Our future financial condition and results of operations, as well as any forward-looking statements, are subject to change and inherent risks and uncertainties. The factors impacting these risks and uncertainties include, but are not limited to:

●	the risk factors discussed in Part I, Item 1A of our 2013 Annual Report on Form 10-K for the year ended December 31, 2013;
●	availability of capital on an economic basis, or at all, to fund our capital needs;
●	failure to meet requirements under our debt instruments, which could lead to foreclosure of significant assets;
●	potential default of our settlement agreement with our term loan instruments;
●	failure to fund our authorization for expenditures from other operators for key projects which will reduce our interest in the wells
●	inability to address our negative working capital position;
●	the inability of management to effectively implement our strategies and business plans;
●	potential default under our secured obligations or material debt agreements;
●	estimated quantities and quality of oil and natural gas reserves;
●	exploration, exploitation and development results;

●	fluctuations in the price of oil and natural gas, including reductions in prices that would adversely affect our revenue, cash flow, liquidity and access to capital;
●	availability of, or delays related to, drilling, completion and production, personnel, supplies and equipment;
●	the timing and amount of future production of oil and gas;
●	the completion, timing and success of our drilling activity;
●	lower oil and natural gas prices negatively affecting our ability to borrow or raise capital, or enter into joint venture arrangements;
●	declines in the values of our natural gas and oil properties resulting in write-downs;
●	inability to hire or retain sufficient qualified operating field personnel;
●	our ability to successfully identify and consummate acquisition transactions;
●	our ability to successfully integrate acquired assets or dispose of non-core assets;
●	increases in interest rates or our cost of borrowing;
●	deterioration in general or regional (especially Rocky Mountain) economic conditions;

●	the strength and financial resources of our competitors;
●	the occurrence of natural disasters, unforeseen weather conditions, or other events or circumstances that could impact our operations or could impact the operations of companies or contractors we depend upon in our operations;
●	inability to acquire or maintain mineral leases at a favorable economic value that will allow us to expand our development efforts;
●	inability to successfully develop the acreage we currently hold;
●	transportation capacity constraints or interruptions, curtailment of production, natural disasters, adverse weather conditions, or other issues affecting the DJ Basin;
●	technique risks inherent in drilling in existing or emerging unconventional shale plays using horizontal drilling and completion techniques;
●	delays, denials or other problems relating to our receipt of operational consents and approvals from governmental entities and other parties;
●	unanticipated recovery or production problems, including cratering, explosions, fires and uncontrollable flows of oil, gas or well fluids;
●	environmental liabilities;
●	operating hazards and uninsured risks;
●	loss of senior management or technical personnel;
●	adverse state or federal legislation or regulation that increases the costs of compliance, or adverse findings by a regulator with respect to existing operations, including those related to climate change and hydraulic fracturing;

●	changes in U.S. GAAP or in the legal, regulatory and legislative environments in the markets in which we operate; and
●	other factors, many of which are beyond our control.

Many of these factors are beyond our ability to control or predict. These factors are not intended to represent a complete list of the general or specific factors that may affect us.

For a detailed description of these and other factors that could cause actual results to differ materially from those expressed in any forward-looking statement, we urge you to carefully review and consider the disclosures made in the “Risk Factors” sections of our Annual Report on Form 10-K for the year ended December 31, 2013 and other SEC filings, available free of charge at the SEC’s website ( www.sec.gov ).

Part 1. FINANCIAL INFORMATION

Item 1. Financial Statements

LILIS ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

(UNAUDITED)

	March 31,			December 31,
	2014			2013
Assets
Current assets:
Cash	$	2,856,033		$	165,365
Restricted cash		507,260			504,623
Accounts receivable (net of allowance of $50,000 at March 31, 2014 and December 31, 2013, respectively)		375,030			467,337
Prepaid assets		179,477			195,716
Commodity price derivative receivable		-			6,679
Total current assets		3,917,800			1,339,720

Oil and gas properties (full cost method), at cost:
Evaluated properties		68,265,711			68,213,467
Unevaluated acreage, excluded from amortization		18,957,997			18,663,569
Wells in progress, excluded from amortization		6,366,010			1,145,794
Total oil and gas properties, at cost		93,589,718			88,022,830

Less accumulated depreciation, depletion, amortization, and impairment		(45,818,716	)		(45,457,637	)
Total oil and gas properties, net		47,771,002			42,565,193

Other assets:
Office equipment, net		85,171			91,161
Deferred financing costs, net		100,243			294,699
Restricted cash and deposits		215,541			215,541
Total other assets		400,955			601,401
Total assets	$	52,089,757		$	44,506,314

The accompanying notes are an integral part of these condensed consolidated financial statements.

LILIS ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

(UNAUDITED)

	March 31,			December 31,
	2014			2013
Liabilities and Shareholders' Equity
Current liabilities:
Accounts payable	$	6,728,678		$	1,932,618
Accrued expenses		1,376,829			1,439,956
Short term loans payable		10,482,840			10,662,904
Convertible notes payable, net of discount		6,396,648			-
Total current liabilities		24,984,995			14,035,478

Long term liabilities:
Asset retirement obligation		1,125,750			1,104,952
Term loans payable		8,083,623			8,111,436
Convertible notes payable, net of discount		-			14,586,618
Convertible notes conversion derivative liability		-			1,150,000
Total long-term liabilities		9,209,373			24,953,006

Total liabilities		34,194,368			38,988,484

Commitments and contingencies – Notes 2, 8, 9,11, and 12

Shareholders’ equity:
Preferred stock, 10,000,000 authorized, none issued and outstanding		-			-
Common stock, $0.0001 par value:100,000,000 shares authorized; 27,551,467 and 19,671,901 shares issued and outstanding as of March 31, 2014 and December 31, 2013, respectively		2,756			1,967
Additional paid in capital		143,878,985			121,451,232
Accumulated deficit		(125,986,352	)		(115,935,369	)
Total shareholders' equity		17,895,389			5,517,830
Total liabilities and shareholders’ equity	$	52,089,757		$	44,506,314

The accompanying notes are an integral part of these condensed consolidated financial statements.

LILIS ENERGY, INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

(UNAUDITED)

	Three months ended March 31,
	2014			2013
Revenues:
Oil sales	$	700,087		$	1,127,333
Gas sales		87,667			106,397
Operating fees		34,727			48,503
Realized gain on commodity price derivatives		11,143			19,890
Total revenues		833,624			1,302,123

Costs and expenses:
Production costs		416,323			303,847
Production taxes		93,680			115,994
General and administrative		2,958,416			984,259
Depreciation, depletion and amortization		388,635			689,654
Total costs and expenses		3,857,054			2,093,754

Loss from operations		(3,023,429	)		(791,631	)

Other Income (expenses):
Other income		53			251
Inducement expense		(6,661,275	)		-
Convertible notes conversion derivative gain (loss)		1,150,000			(20,000	)
Interest expense		(1,516,331	)		(1,636,159	)
Total other expenses		(7,027,553	)		(1,655,908	)

Net loss	$	(10,050,982	)	$	(2,447,539	)
Net loss per common share (basic and diluted)	$	(0.40	)	$	(0.13	)
Weighted average shares outstanding (basic and diluted)		25,087,037			18,438,905

The accompanying notes are an integral part of these condensed consolidated financial statements.

LILIS ENERGY, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(UNAUDITED)

	Three months ended
	March 31,
	2014			2013

Cash flows from operating activities:
Net loss	$	(10,050,983	)	$	(2,447,539	)
Adjustments to reconcile net loss to net cash used in operating activities:
Debt inducement of conversion of convertible debentures		6,661,275			-
Common stock issued for convertible note interest		148,129			270,032
Common stock issued for financing cost		686,273			-
Common stock for services and compensation		444,787			250,846
Amortization of deferred financing costs		194,456			177,246
Change in fair value of convertible notes conversion derivative		(1,150,000	)		20,000
Accretion of debt discount		661,900			563,571
Depreciation, depletion, amortization and accretion of asset retirement obligation		388,635			689,654
Changes in operating assets and liabilities:
Accounts receivable		92,307			307,841
Restricted cash		(2,637	)		(88,054	)
Other assets		431,809			(66,831	)
Accounts payable and other accrued expenses		(458,581	)		(580,466	)
Net cash provided by (cash used) operating activities		(1,952,630	)		(903,700	)

Cash flows from investing activities:
Acquisition of undeveloped acreage		(305,000	)		(7,061	)
Drilling capital expenditures		(14,494	)		(21,462	)
Sale of oil and gas properties		-			640,000
Additions to oil and gas properties		(49,201	)		-
Additions to office equipment		(768	)		(23,276	)
Investments in operating bonds		-			(105	)
Net cash provided by (cash used) in investing activities		(369,463	)		588,096

Cash flows from financing activities:
Proceeds from issuance of common stock		5,327,687			-
Repayment of debt		(314,926	)		(177,375	)
Net cash provided by (cash used) financing activities		5,012,761			(177,375	)

Change in cash and cash equivalents		2,690,668			(492,979	)
Cash and cash equivalents at beginning of period		165,365			970,035

Cash and cash equivalents at end of period	$	2,856,033		$	477,056
Non-cash transactions:
Additions to drilling capital expenditures from an increase in accounts payable and other accrued expenses	$	5,198,193		$	-
Stock issued for payment on long-term debt	$	8,744,836		$	-

The accompanying notes are an integral part of these condensed consolidated financial statements

LILIS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

AS OF MARCH 31, 2013

(UNAUDITED)

NOTE 1 – ORGANIZATION

On September 21, 2009, Universal Holdings, Inc. (“Universal”), a Nevada corporation, completed the acquisition of Coronado Acquisitions, LLC (“Coronado”). Under the terms of the acquisition, Coronado was merged into Universal. On October 12, 2009, Universal changed its name to Recovery Energy, Inc. On December 1, 2013, Recovery Energy, Inc. changed its name to Lilis Energy, Inc. (“Lilis”, “Lilis Energy”, “we”, “our”, and the “Company”). The acquisition was accounted for as a reverse acquisition with Coronado being treated as the acquirer for accounting purposes. Accordingly, the financial statements of Coronado and Recovery Energy have been adopted as the historical financial statements of Lilis.

The Company is an independent oil and gas exploration and production company focused on the Denver-Julesburg Basin (“DJ Basin”) where it holds 107,000 net acres. Lilis drills, operates and produces oil and natural gas wells through the Company’s land holdings located in Wyoming, Colorado, and Nebraska.

All references to production, sales volumes and reserves quantities are net to our interest unless otherwise indicated.

NOTE 2 – LIQUIDITY

As of March 31, 2014, the Company had $18.57 million outstanding under its term loans with Hexagon, LLC (“Hexagon”) and $6.40 million outstanding under its 8% Senior Secured Convertible Debentures (the “Debentures”). Both the term loans and the Debentures were to mature on May 16, 2014. Subsequent to March 31, 2014, as discussed below, the maturity date under the Debentures was extended to January 15, 2015 and the maturity dates under each of the term loans was extended to August 15, 2014.

Since March 31, 2014, the Company has consummated the following transactions: (i) on May 19, 2014, the Company received extensions from both Hexagon and the remaining Debenture holders of the maturity dates under the Company’s term loans and outstanding Convertible Debentures, respectively, from May 16, 2014 to August 15, 2014; (ii) on May 30, 2014, the Company and Hexagon entered into an agreement providing for the settlement of all amounts outstanding under the term loans, in exchange for two cash payments of $5.0 million each to be made by the Company to Hexagon which are due May 30, 2014 and June 30, 2014, as well as the issuance to Hexagon of a two-year $6.0 million unsecured 8% note and 943,208 shares of unregistered Common Stock. As of June 1, 2014, the Company paid the first $5.00 million to Hexagon; (iii) on May 30, 2014 the Company consummated a private placement to accredited investors of 8% Convertible Preferred Stock and three-year warrants to purchase Common Stock equal to 50% of the number of shares issuable upon full conversion of the Preferred Stock for gross proceeds of $7.50 million; (iv) on June 6, 2014, the holders of the remaining Debentures agreed to further extend the maturity date under the Debentures from August 15, 2014 to January 15, 2015; and (v) on June 6, 2014, TR Winston executed a commitment to purchase or effect the purchase by third parties of an additional $15 million in Preferred Stock, which transaction is to be consummated within ninety (90) days. The consummation of these transactions has been partially reflected in the Company’s balance sheet via the classification of certain portions of the Hexagon term loans and Debentures as long-term debt. (See Note 12 -Subsequent Events.)

The closing of these transactions provided the Company with working capital for general corporate purposes, as well as a portion of the initial capital requirements to initiate further development activities on two of its Wattenberg prospects. However, the Company will require additional capital to satisfy its obligations to Hexagon under the settlement agreement, to fund its current drilling commitments and capital budget plans, to help fund its ongoing overhead, and to provide additional capital to generally improve its working capital position. We anticipate that such additional funding will be provided by a combination of capital raising activities, including the selling of additional debt and/or equity securities, the selling of certain assets and by the development of certain of the Company’s undeveloped properties via arrangements with joint venture partners. If we are not successful in obtaining sufficient cash sources to fund the aforementioned capital requirements, we may be required to curtail our expenditures, restructure our operations, sell assets on terms which may not be deemed favorable and/or curtail other aspects of our operations, including deferring portions of our capital budget. There is no assurance that any such funding will be available to the Company.

NOTE 3 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

The accompanying financial statements were prepared by Lilis in accordance with generally accepted accounting principles (“GAAP”) in the United States. The financial statements 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.

Reclassification

Certain amounts in the 2013 consolidated financial statements have been reclassified to conform to the March 31, 2014 consolidated financial statement presentation. Such reclassifications had no effect on net loss.

Use of Estimates

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 ongoing 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.

Cash and Cash Equivalents

Cash and cash equivalents include cash in banks and highly liquid debt securities which have original maturities of 90 days or less at the purchase date.

Restricted Cash

Restricted cash consists of severance and ad valorem tax proceeds which are payable to various tax authorities. As of March 31, 2014 and December 31, 2013, the restricted cash balance was $0.51 million and $0.50 million, respectively.

Accounts Receivable

The Company records actual and estimated oil and gas revenue receivable from third parties at its net revenue interest. The Company also reflects costs incurred on behalf of joint interest partners in accounts receivable. Management periodically reviews accounts receivable amounts for collectability and records an allowance for uncollectible receivables under the specific identification method. The Company recorded allowances for uncollectible receivables of $50,000 at March 31, 2014 and December 31, 2013. Allowances for doubtful accounts are based primarily on joint interest billings for expenses related to oil and natural gas wells. Receivables derived from sales of certain oil and gas production are collateral for our term loans and debentures. (See Note 7-Fair Value of Financial Instruments.)

During the three months ended March 31, 2014 and year ended December 31, 2013, the Company did not write off any accounts receivable.

Oil and Gas Properties

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.

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 costs 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 i.) the present value, discounted at 10%, of estimated future net revenues from proved oil and gas reserves, plus ii.) 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.

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.

The Company did not recognize impairment charges for the three months ended March 31, 2014 or 2013.

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. (See Note 5 – Wells in Progress.)

As of March 31, 2014, the Company has $6.37 million in wells in progress compared to $1.15 million in wells in progress as of December 31, 2013. (See Note 5 – Wells in Progress.)

Net Loss per Common Share

Earnings (losses) per common share are computed based on the weighted average number of common shares outstanding during the period presented. Diluted earnings (losses) 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 conversion derivatives and stock purchase warrants, are excluded from the calculation when their effect would be anti-dilutive. As of March 31, 2014, a total of 14,950,264 and 3,198,324 shares underlying warrants and convertible debentures, respectively, have been excluded from the diluted share calculations as they were anti-dilutive as a result of net losses incurred. Accordingly, basic shares equal diluted shares for all periods presented.

Recent 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 a have a material impact on the Company's financial position, results of operations or cash flows.

NOTE 4 – OIL AND GAS PROPERTIES

In January 2014, the Company secured an additional interest in their properties within Weld County, Colorado for $0.3 million. These properties are located in the Northern Wattenberg.

NOTE 5 – WELLS IN PROGRESS

As of March 31, 2014, the Company has $6.37 million in wells in progress compared to $1.15 million as of December 31, 2013. The Company incurred wells-in-progress within their properties in Weld County, CO within the Northern and Southern Wattenberg Field areas. As of March 31, 2014, one of the four wells is performing completion techniques and was in production as of April 2014. The remaining three wells in wells-in –progress started completion techniques in May 2014.

NOTE 6 - DERIVATIVES

The Company periodically enters into various commodity derivative financial instruments intended to hedge against exposure to market fluctuations of oil prices. The Company maintained a commodity swap during the first month of 2014, but as of March 31, 2014, the Company did not maintain any active commodity swaps.

The amount of gain (loss) recognized in income related to our derivative financial instruments was as follows (in thousands):

	For the three months Ended March 31,
	2014		2013
Realized gain on oil price hedges	$	11	$	20

Realized gains and losses are recorded as income or expenses in the periods during which applicable contracts mature and settle. Swaps which are unsettled as of a balance sheet date are carried at fair market 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. (See Note 7 - Fair Value of Financial Instruments.)

NOTE 7 - 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:

● Level 1 – Observable inputs that reflect quoted prices (unadjusted) for identical assets or liabilities in active markets.

● Level 2 – Other inputs that are directly or indirectly observable in the market place.

● Level 3 – Unobservable inputs which are supported by little or no market activity.

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 cash equivalents, short-term investments, accounts receivable, accounts payable, accrued expenses, interest payable and customer deposits approximate fair value due to the short-term nature or maturity of the instruments. The Company’s fixed rate 10% and 8% term loans and convertible debentures, respectively, are measured using Level 3 inputs.

January 2014 Private Placement

In January 2014, the Company entered into and closed a series of subscription agreements with accredited investors, pursuant to which the Company issued an aggregate of 2,959,125 units, with each unit consisting of (i) one share of the Company’s common stock, par value $0.0001 (the “Common Stock”) and (ii) one three-year warrant to purchase one share of Common Stock, at an exercise price equal to $2.50 per share (together, the “Units”), for a purchase price of $2.00 per Unit, for aggregate gross proceeds of $5,918,250 (the “January Private Placement”). The Company’s officers and directors have agreed to purchase an additional $1,425,000 of Units subject to receipt of shareholder approval as required by NASDAQ’s continued listing requirements. The warrants are not exercisable for six months following the closing of the January Private Placement and must be registered before exercising. The Company valued the warrants within the unit, utilizing a Black Scholes Model using a volatility calculation of 65%, and 3 year term, which resulted in an increase in paid in capital of $1.69 million for the period ended March 31, 2014.

Executive Compensation

In September, 2013, we announced the appointment of Abraham (“Avi”) Mirman as our new president. In connection with Mr. Mirman’s appointment, the Company entered 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 will be valued every quarter. The Company engaged a third party to complete a valuation of this conversion liability. As of March 31, 2014, the Company recorded an additional expense of $0.05 million, for the three months ended, which resulted in a total liability of $0.20 million. (See Note 11-Share Based and Other Compensation.)

Derivative Instruments

The Company determines its estimate of the fair value of derivative instruments using a market approach based on several factors, including quoted market prices in active markets, quotes from third parties, and the credit rating of its counterparty. The Company also performs an internal valuation to ensure the reasonableness of third-party quotes.

The primary type of derivative instrument utilized by the Company is the commodity swap. The oil derivative markets are highly active. Although the Company’s economic hedges are valued using public indices, the instruments themselves are traded with third-party counterparties and are not openly traded on an exchange. As such, the Company has classified these instruments as Level 2.

In evaluating counterparty credit risk, the Company assessed the possibility of whether the counterparty to the derivative would default by failing to make any contractually required payments. The Company considered that the counterparty is of substantial credit quality and has the financial resources and willingness to meet its potential repayment obligations associated with the derivative transactions. As of March 31, 2014, the Company did not have any derivative instruments. (See Note 6-Derivitives.)

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: 1) 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; 2) the economic lives of its properties, which are based on estimates from reserve engineers; 3) the inflation rate; and 4) 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.

Convertible Debentures Conversion Derivative Liability

In February 2011, the Company issued in a private placement $8.40 million aggregate principal amount of three year 8% Senior Secured Convertible Debentures (“Debentures”) with a group of accredited investors. During the year ended December 31, 2012, the Company issued an additional $5.00 million of Debentures, resulting in a total of $13.40 million of Debentures outstanding as of December 31, 2012. Through December 31, 2013, the Company issued an additional $2.20 million of supplemental convertible debentures. As of December 31, 2013 the Company had a total debenture amount of $15.58 million. On January 31, 2014, the "Company entered into a Debenture Conversion Agreement (the "Agreement") between the Company and all of the holders of the Debentures. Pursuant to the terms of the Agreement, $9 million converted at a price of $2.00 per share of the Company’s common stock. In addition, the Company issued warrants to the Debenture holders to purchase one share of Common Stock, at an exercise price equal to $2.50 per share (the "Warrants"), equal to the number of Common Stock issued pursuant to the Debenture holder's conversion elections. As of March 31, 2014, the remaining Debentures are convertible at any time at the holders’ option into shares of our common stock at $2.00 per share, subject to certain adjustments, including the requirement to reset the conversion price based upon any subsequent equity offering at a lower price per share amount. The Company engaged a third party to complete a valuation of this conversion liability.

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

March 31, 2014:

	Level 1		Level 2		Level 3			Total
Liability
Executive employment agreement compensation	$	-	$	-	$	(200	)	$	(200	)
Total liability, at fair value	$	-	$	-	$	(200	)	$	(200	)

December 31, 2013:

	Level 1		Level 2		Level 3			Total
Assets
Derivative instruments	$	-	$	7	$	-		$	7
Total assets, at fair value	$	-	$	7	$	-		$	7

Liability
Executive employment agreement	$	-	$	-	$	(145	)	$	(145	)
Convertible debentures conversion derivative liability	$	-	$	-	$	(1,150	)	$	(1,150	)
Total liability, at fair value	$	-	$	-	$	(1,295	)	$	(1,295	)

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, 2014 (in thousands):

Beginning balance, December 31, 2013	$	(1,295	)
Executive compensation liability		(55	)
Convertible debentures conversion derivative gain		1,150
Ending balance, March 31, 2014	$	(200	)

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, 2014 or 2013.

NOTE 8 – LOAN AGREEMENTS

Term Loans

The Company entered into three separate loan agreements with Hexagon in January, March and April 2010. All three loans originally bore annual interest at a rate of 15% (which has been reduced, as discussed below), each had an original maturity date of December 1, 2010 (which has been extended, as discussed below), and have similar terms, including customary representations and warranties and indemnification, and require the Company to repay the loans with the proceeds of the monthly net revenues from the production of the acquired properties. The loans contain cross collateralization and cross default provisions and are collateralized by mortgages against a portion of the Company’s developed and undeveloped leasehold acreage.

In April 2013, Hexagon agreed to amend all three loan agreements to extended the maturity date to May 16, 2014, reduce the annualized interest rate to 10% from 15% beginning retroactively with March 2013, decrease our minimum monthly payment under the term loans to $0.23 million and allow us to make interest-only payments for March, April, May, and June. In consideration for the extended maturity date, reduced interest rate, and reduced minimum loan payment, we provided Hexagon an additional security interest in 15,000 acres of our undeveloped acreage.

On May 19, 2014, the Company received an extension from Hexagon of the maturity date under its term loans, from May 16, 2014 to August 15, 2014.

On May 30, 2014, the Company entered into a Settlement Agreement (the “Settlement Agreement”) with Hexagon, which provides for the settlement of all amounts outstanding under the Term Loans. In connection with the execution of the Settlement Agreement, the Company made initial cash payment of $5.0 million. The Settlement Agreement requires the Company to make an additional cash payment of $5.0 million (the “Second Cash Payment”) by June 30, 2014, and at that time issue to Hexagon (i) a two-year $6.0 million unsecured note (the “Replacement Note”), bearing interest at an annual rate of 8%, requiring principal and interest payments of $90,000 per month, and (ii) 943,208 shares of unregistered common stock (the “Shares”). The parties have also agreed that if the Second Cash Payment is not made by June 30, 2014, an additional $1.0 million in principal will be added to the Replacement Note, and if the Replacement Note is not retired by December 31, 2014, the Company will issue an additional 1.0 million shares of its common stock to Hexagon. Finally, Hexagon will not, until the earlier of June 30, 2014 or the date the Company achieves sustained average trading volume in excess of 100,000 shares per day for at least ten consecutive trading days, sell or otherwise transfer for value any shares of the Company’s common stock or any securities convertible into the Company’s common stock, and thereafter until December 31, 2014, Hexagon will not sell or otherwise transfer for value more than 10,000 shares per week of the Company’s common stock or any securities convertible into the Company’s common stock. Under the Settlement Agreement, Hexagon will release its security interest under the Term Loans once the Company has delivered the Second Cash Payment, the Replacement Note and the Shares. (See Note 12-Subsequent Events.)

The Company is subject to certain non-financial covenants with respect to the Hexagon loan agreements. As March 31, 2014, the Company was in compliance with all covenants under the facilities.

As of March 31, 2014, the total amount outstanding on the three loan agreements was $18.57 million.

As a result of the Hexagon Settlement Agreement, the term notes are being carried on the balance sheet as of March 31, 2014 as follows (in thousands):

	As of March 31, 2014
Total Term Notes	$	18,565
Short term notes payable		(10,482	)
Long term notes payable	$	8,083

Annual debt maturities as of March 31, 2014 (in thousands):

Year 1	$	16,879
Year 2		8,083
Thereafter		-
Total	$	24,962

Convertible Debentures Payable

In February 2011, the Company completed a private placement of $8.40 million aggregate principal amount of the Debentures, secured by mortgages on several of our properties. Initially, the Debentures were convertible at any time at the holders' option into shares of our common stock at $9.40 per share, subject to certain adjustments, including the requirement to reset the conversion price based upon any subsequent equity offering at a lower price per share amount. Interest at an annualized rate of 8% is payable quarterly on each May 15, August 15, November 15 and February 15 in cash or, at the Company's option, in shares of common stock, valued at 95% of the volume weighted average price of the common stock for the 10 trading days prior to an interest payment date. The Company can redeem some or all of the Debentures at any time. The redemption price is 115% of principal plus accrued interest. If the holders of the Debentures elect to convert the Debentures, following notice of redemption, the conversion price will include a make-whole premium equal to the interest accruable through the 18 month anniversary of the original issue date of the Debenture less the amount of any interest paid on the portion of the Debenture being redeemed prior to the optional redemption date, payable in common stock. TR Winston acted as placement agent for the private placement and received $0.04 million of Debentures equal to 5% of the gross proceeds from the sale. The Company is amortizing the $0.04 million over the life of the loan as deferred financing costs. The Company amortized $0.01million of deferred financing costs into interest expense during the three months ended March 31, 2014, and has $0.03 million of deferred financing cost to be amortized through May 2014.

In December 2011, the Company agreed to amend the Debentures to lower the conversion price to $4.25 from $9.40 per share. This amendment was an inducement consideration to the Debenture holders for their agreement to release a mortgage on certain properties so the properties could be sold. The sale of these properties was effective December 31, 2011, and a final closing occurred during first quarter of 2012.

On March 19, 2012, the Company entered into agreements with some of its existing Debenture holders to issue up to $5.0 million in additional debentures (the “Supplemental Debentures”). Under the terms of the Supplemental Debenture agreements, proceeds derived from the issuance of Supplemental Debentures were used principally for the development of certain of the Company's proved undeveloped properties and other undeveloped acreage currently targeted by the Company for exploration, as well as for other general corporate purposes. Any new producing properties developed from the proceeds of Supplemental Debentures are to be pledged as collateral under a mortgage to secure future payment of the Debentures and Supplemental Debentures. All terms of the Supplemental Debentures are substantively identical to the Debentures. The Agreements also provided for the payment of additional consideration to the purchasers of Supplemental Debentures in the form of a proportionately reduced 5% carried working interest in any properties developed with the proceeds of the Supplemental Debenture offering.

Through July 2012, we received $3.04 million of proceeds from the issuance of Supplemental Debentures, which were used for the drilling and development of six new wells, resulting in a total investment of $3.69 million. Four of these wells resulted in commercial production, and two wells was plugged and abandoned.

In August 2012, the Company and holders of the Supplemental Debentures agreed to renegotiate the terms of the Supplemental Debenture offering. These negotiations concluded with the issuance of an additional $1.96 million of Supplemental Debentures. The August 2012 modifications to the Supplemental Debenture agreements increased the carried working interest from 5% to 10% and also provided for a one-year, proportionately reduced net profits interest of 15% in the properties developed with the proceeds of the Supplemental Debenture offering, as well as the next four properties to be drilled and developed by the Company. In conjunction with commitments to additional Debentures in June 2013 (see below), the commitment to provide a 10% carried interest and a 15% one year net profits interest related to the development of four future properties was modified to a 15% carried interest in such properties. As a result of the modified carried working interest to 15%, $0.16 million of debt discount was reversed.

On September 8, 2012, the Company issued 50,000 shares, valued at $0.23 million, to TR Winston for acting as a placement agent of the Supplemental Debentures. The Company is amortizing the $0.23 million over the life of the loan as deferred financing costs. The Company amortized $0.03 million and $0.03 million of deferred financing costs into interest expense during the three months ended March 31, 2014 and 2013, and has $0.02 million of deferred financing costs to be amortized through May 2014.

In April 2013, the holders of the Debentures agreed to extend their maturity date to May 16, 2014. On May 19, 2014, the Company received an extension on the Debentures until August 15, 2014. The Debentures waived their right to declare an event of default in connection with the May 15, 2014 maturity date under the Debenture agreement. In consideration for the extended maturity date the Company provided an additional security interest in 15,000 acres of our undeveloped acreage, as additional collateral for the Debentures.

In April 2013, we received approval from our existing secured debt and convertible debenture holders to issue up to $5.00 million of additional convertible debentures with terms substantially identical to our existing convertible debentures. As of November 8, 2013 we have issued $2.20 million of such convertible debt, inclusive of $2.21 million that had been issued as of December 31, 2013. Two officers of the Company participated in the additional convertible debentures for a combined total of $0.43 million. Proceeds from the issuance of this convertible debt have been used toward the development of certain specific properties, and to a lesser extent, general corporate purposes. The recent commitments were subject to certain yield enhancements, including a 25% carried interest in certain properties scheduled to be developed with the proceeds. During the year ended December 31, 2013, the Company paid TR Winston $0.04 million as acting placement agent for the additional $2.20 million of supplemental debentures. The Company amortized $.02 million for the three months ended March 31, 2014, and has $0.01 million of deferred financing costs to be amortized through May 2014.

We periodically engage a third party valuation firm to complete a valuation of the conversion feature associated with the Debentures, and with respect to March 31, 2014, the Supplemental Debentures. This valuation resulted in an estimated derivative liability as of March 31, 20134 and December 31, 2013 of $0 million and $1.15 million, respectively. (See Note 7-Fair Value of Financial Instruments.)

During the three months ended March 31, 2014 and 2013, the Company amortized $0.66 million and $0.56 million, respectively, of debt discounts.

On January 31, 2014, the Company entered into a Debenture Conversion Agreement (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 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. Utilizing a Lattice model, with a 3 year life and 65% volatility, the Company recorded an inducement expense of $6.61 million, for the three months ended March 31, 2014, for the warrants issued to induce the convertible debentures to convert their debt to common stock and a warrant. T.R. Winston acted as the investment banker for the Conversion agreement and was compensation 8% of the $9.0 million which was payable in common stock and valued at a market rate of $3.05 per share. During the three months ended March 31, 2104, the Company valued the compensation at $0.69 million.

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); subject to receipt of shareholder approval as required by NASDAQ continued listing requirements. The Company intends to present proposals to approve participation by officers and directors in the January Private Placement and the conversion of the remaining outstanding Debentures at its 2014 annual meeting of shareholders, which is expected to take place in July 2014.

On May 19, 2014, the holders of the Debentures agreed to extend the maturity date of the Debentures until August 15, 2014, and waived their right to declare an event of default in connection with the May 16, 2014 maturity date under the Debentures. On June 6, 2014, the holders of the remaining Debentures agreed to further extend the maturity date under the Debentures from August 15, 2014 to January 15, 2015. (See Note 12-Subsequent Events.)

As of March 31, 2014 and December 31, 2013, the convertible debt is recorded as follows (in thousands):

	As of March 31, 2014			As of December 31, 2013
Convertible debentures	$	6,728		$	15,580
Debt discount		(332	)		(993	)
Total convertible debentures, net	$	6,396		$	14,587

Because they mature on January 15, 2015, the Debentures are being carried on the balance sheet as of March 31, 2014 as a current liability.

Interest Expense

NOTE 9 - COMMITMENTS and CONTINGENCIES

Environmental and Governmental Regulation

At March 31, 2014, 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, royalty rates 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, 2014 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 has 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 has asserted rights to lawful set-offs and deductions in connection with certain tax consequences, which may be material to the Company. As a result of bankruptcy proceedings filed by Mr. Parker, the garnishment proceedings have been stayed. At this stage, we cannot express an opinion as to the probable outcome of this matter.

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. 13-01301 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.

There are no other material pending legal proceedings to which we or our properties are subject.

NOTE 10 - SHAREHOLDERS’ EQUITY

Common Stock

As December 31, 2013, the Company had 100,000,000 shares of common stock and 10,000,000 shares of preferred stock authorized, of which 27,551,467 shares of common stock were issued and outstanding. No preferred shares were issued or outstanding.

During the three months ended March 31, 2014, the Company issued 7,863,166 shares of common stock, including 4,500,000 common stock shares to debenture conversion agreement, 250,000 for finance expense to complete the conversion of convertible debentures. 3,037,500 for the stock issued for the January 2014 Private Placement, and 129,150 shares of common stock as restricted stock grants to employees, board members, or consultants. (See Note 11-Share Based and Other Compensation.)

Investment Banking Agreement

During the year ended December 31, 2013, the Company was party to a one-year, non-exclusive investment banking agreement with TR Winston, pursuant to which the Company issued to TR Winston 100,000 common shares, and 900,000 common stock purchase warrants. All warrants have a term of three years and a strike price of $4.25 per share. The investment banking agreement also provided for additional commissions and compensation in the event that TR Winston arranged a successful equity or debt financing during the term of the agreement. The 900,000 warrants were valued at $0.26 million and the 100,000 common shares were valued at $0.16 million. Both equity instruments are classified as prepaid assets and amortized over the life of the agreement. During the three months ended March 31, 2014, $0.11 million was included in general and administrative expense as amortization of the value of these grants.

January 2014 Private Placement

In January 2014, the Company entered into and closed a series of subscription agreements with accredited investors, pursuant to which the Company issued an aggregate of 2,959,125 units, with each unit consisting of (i) one share of the Company’s common stock, par value $0.0001 (the “Common Stock”) and (ii) one three-year warrant to purchase one share of Common Stock, at an exercise price equal to $2.50 per share (together, the “Units”), for a purchase price of $2.00 per Unit, for aggregate gross proceeds of $5,918,250 (the “January Private Placement”). The Company’s officers and directors have agreed to purchase an additional $1,425,000 of Units subject to receipt of shareholder approval as required by NASDAQ’s continued listing requirements. The warrants are not exercisable for six months following the closing of the January Private Placement. Since the warrants are unregistered, they are being carried as a liability. As of March 31, 2014, the Company calculated the value of the warrants within the January Private Placement as $1.69 million, once the shares become registered; the value will be transferred to pay in capital. T.R Winston and John Carris Investments acted as the placement agents and was compensated 8% for the completion of the private placement. Their fees were paid in 288,840 warrants with an assumed strike price of $2.16 per share, volatility of 65%, which resulted in a value of $0.24 million. The fees were an offset against paid in capital.

Convertible Debenture Interest

During the three months ended March 31, 2014, the Company issued 74,064 shares for payment of yearly interest expense on the convertible debentures valued at $0.15 million.

Debenture Conversion Agreement

Warrants

A summary of warrant activity for the three months ended March 31, 2014 is presented below:

	Warrants		Weighted-Average Exercise Price
Outstanding at December 31, 2013		6,773,913	$	5.24
Granted-January private placement		3,012,500		2.5
Granted-debenture conversion agreement		4,500,011		2.5
Granted-other		663,840		2.88
Exercised, forfeited, or expired		-		-
Outstanding at March 31, 2014		14,950,264	$	3.76

In January 2014, the Company entered into a consulting agreement with a public relations company. The agreement provided for the issuance by the Company of 350,000 warrants and 90,000 shares of stock which vest on a monthly basis until December 31, 2014. During the three months ended March 31, 2014, the Company recognized a total expense of $0.46 million for the consulting agreement.

The aggregate intrinsic value associated with outstanding warrants as of March 31, 2014 and 2013 was $56.18 million and $40.12 million, 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 $3.76 and $1.73, respectively. The weighted average remaining contract life as of March 31, 2014 was 1.31 years, and 2.31 years as of December 31, 2013.

NOTE 11 - SHARE BASED AND OTHER COMPENSATION

Share-Based Compensation

In September 2012, the Company adopted the 2012 Equity Incentive Plan (the “Plan”). The Plan was amended by the stockholders on June 27, 2013 to increase the number of common shares 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 common shares available for grant under the EIP from 1,800,000 shares to 6,800,000 shares and to increase the number of common shares 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 restricted stock grants, and in the future will be awarded such grants under the terms of the Plan.

The costs of employee services received in exchange for an award of equity instruments are 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, 2014, the Company granted 129,150 shares of restricted common stock to employees, directors and consultants.

The Company recognized a stock compensation expense of approximately $0.08 million and a credit of $0.01 million for cancelled shares, respectively, for the three months ended March 31, 2014.

Stock Options

A summary of stock options activity for three months ended March 31, 2014 is presented below:

	Stock Options
Outstanding at December 31, 2013		3,800,000
Granted		-
Exercised, forfeited, or expired		-
Outstanding at March 31, 2014		3,800,000

In June 2013, the Company entered into employment agreements with the CEO and the then President/CFO for non-cash compensation which consisted of each individual receiving 300,000 stock options of which 100,000 vested immediately and 200,000 were scheduled to vest over the following 2 years. The options had a five-year life and an exercise price of $1.60. The 600,000 stock options were valued at $0.52 million on date of grant. During the year ended December 31, 2013, the Company recognized $0.27 million as non-cash compensation expense and $0.25 million is to be amortized over the remaining vesting period.

In connection with execution of these employment contracts, each executive also agreed to receive 93,750 shares of restricted common stock in lieu of a portion of their cash salaries, to vest on April 15, 2014.

In September, 2013, the Company entered an employment agreement with Abraham (“Avi”) Mirman (the “Mirman Agreement”). As an inducement for joining the Company, Mr. Mirman was granted 100,000 shares of the Company’s common stock, which vested immediately, was valued at $0.25 million, and was expensed as of the date of the grant. Mr. Mirman was also granted an option to purchase up to 600,000 shares of common stock of the Company, at a strike price of $2.45 per share, equal to the Company’s closing share price on September 16, 2013. This option will become exercisable upon the date the Company receives gross cash proceeds and/or drawing availability under a line of credit of at least $30,000,000, measured on a cumulative basis and including certain restructuring transactions. As such, the Company anticipates that this option will become exercisable if our shareholders subsequently approve the conversion of the remaining Debentures.

Mr. Mirman was also granted options to purchase up to 2,000,000 shares of the Company’s common stock, 666,667 of which become exercisable if the Company has a reported share price of $7.50 per share for at least 20 Trading Days during the Term of the Agreement and the average daily production of hydrocarbons of the Company equals or exceeds 2,500 barrels of oil equivalent per day (as determined in accordance with the SEC guideline under which six (6) Mcf of natural gas equals one (1) Bbl of oil) during any three calendar month period, and 666,667 and 666,666 of which become exercisable upon the same daily production condition and reported share prices of $10.00 per share and $12.50 per share, respectively.

The Company received independent valuations of the i) option to purchase 600,000 shares of common stock; ii) the incentive bonus; and iii) the options to purchase 2,000,000 shares. The option to purchase 600,000 shares was valued at $0.61 million and is being amortized over the life of the Mirman Agreement, which expires on December 31, 2014. During the three months ended March 31, 2014, the Company recorded an additional expense for the incentive bonus of $0.05 million for a total valued of $0.20 million, and is recorded as a liability. This liability will be revalued at each balance sheet date. The options to purchase 2,000,000 shares were valued at $0.05 million and are being amortized over the life of the Mirman Agreement.

In October 2013, the Company granted each of its independent directors 200,000 non-statutory options to purchase the Company’s common stock at an exercise price of $2.05, 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.

A summary of restricted stock grant activity for the period ended March 31, 2014 is presented below:

	Shares
Balance outstanding at December 31, 2013		2,024,375
Granted		112,750
Vested		(55,209	)
Expired/ cancelled		(12,084	)
Balance outstanding at March 31, 2014		2,069,832

As of March 31, 2014, total unrecognized compensation cost related to unvested stock grants was approximately $0.21 million as of March 31, 2014. The cost at March 31, 2014 is expected to be recognized over a weighted-average remaining service period of 3 years.

Separation Agreement

In April 2014, the Company entered into a separation agreement with the W. Phillip Marcum, the Chief Executive Officer until April 16, 2014. The company provided Mr. Marcum with one year of severance compensation, to be paid through normal payroll practices. Furthermore, he received the immediate vesting of 200,000 options to purchase stock and the conversion of the remaining amount of the 2013 compensation into $0.15 million cash from 93,780 shares of stock. (See Note 12-Subsequent Events.)

Employment Agreement

In April 2014, in connection with the appointment of Robert A. (Bob) Bell as our new President and Chief Operating Officer, the Company entered an employment agreement with Mr. Bell, which provides for the issuance of 100,000 shares of common stock, of which 1/3 vest immediately and the balance over three years, subject to certain conditions. In addition, Mr. Bell will receive an equity incentive bonus consisting of a non-statutory stock option to purchase up to 1,500,000 shares of common stock subject to Mr. Bell’s continued employment and the Company’s achievement of certain pre-defined production thresholds. (See Note 12-Subsequent Events.)

Other Compensation

We sponsor a 401(k) savings plan. All regular full-time employees are eligible to participate. We make contributions to match employee contributions up to 5% of compensation deferred into the plan. The Company made cash contributions of $0.01 million for the three months ended March 31, 2014

NOTE 12- SUBSEQUENT EVENTS

In April 2014, we announced the appointment of Robert A. (Bob) Bell as our new President and Chief Operating Officer. In connection with Mr. Bell’s appointment, the Company entered an employment agreement with Mr. Bell (the “Bell Agreement”), which has an initial term of three years, provides for an annual base salary of $240,000 subject to adjustment by the Company, as well as a signing bonus of $100,000 and 100,000 shares of common stock of which 1/3 vest immediately and the balance vest over three years, subject to certain conditions set forth in the Bell Agreement. In addition, Mr. Bell will receive an equity incentive bonus consisting of a non-statutory stock option to purchase up to 1,500,000 shares of common stock and a cash incentive bonus of up to $1,000,000, both subject to Mr. Bell’s continued employment. In addition, Mr. Bell’s incentive bonuses are subject to the Company’s achievement of certain pre-defined production thresholds set forth in the Bell Agreement.

Separation Agreement

In April 2014, the Company entered into a separation agreement (the “Marcum Agreement”) with W. Phillip Marcum in connection with his resignation from his positions with the Company. The Marcum Agreement provides, among other things, that, consistent with his resignation for good reason under his Employment Agreement, the Company will pay him 12 months of severance through payroll continuation, in the gross amount of $220,000, less all applicable withholdings and taxes, that all stock options held by Mr. Marcum as of the time of his termination will immediately vest, and that Mr. Marcum will remain eligible to receive any performance bonus granted by the Company to its senior executives with respect to Company and/or executive performance in 2013. In addition, the Marcum Agreement provides that the Company will pay Mr. Marcum $150,000 in accrued base salary for his service in 2013, less all applicable withholdings and taxes, in exchange for Mr. Marcum’s forfeiture of the 93,750 shares of unvested restricted common stock of the Company that was issued to Marcum in June 2013 in lieu of such base salary. Mr. Marcum may elect to apply amounts payable under the Marcum Agreement against his commitment to invest $125,000 in the Company’s previously disclosed private offering, upon shareholder approval of the participation of the Company’s officers and directors in that offering. The Marcum Agreement also contains certain mutual non-disparagement covenants, as well as certain mutual confidentiality, non-solicitation and non-compete covenants. In addition, Mr. Marcum and the Company each mutually released and discharged all known and unknown claims against the other and their respective representatives that they had or presently may have, including claims relating to Mr. Marcum’s employment. The Marcum Agreement effectively terminated the previously disclosed Employment Agreement entered into between Mr. Marcum and the Company, dated as of June 25, 2013.

Hexagon Settlement

On May 19, 2014, the Company received an extension from Hexagon of the maturity date under our term loans, from May 16, 2014 to August 15, 2014. As of May 16, 2014, there was an aggregate of $18.77 million outstanding under the term loans, which are collateralized by mortgages against a portion of the Company’s developed and undeveloped leasehold acreage.

In connection with the extension, Hexagon and the Company agreed in principal to the settlement of all amounts outstanding under the term loans, pursuant to which (1) the Company will make a cash payment of $5.0 million no later than May 30, 2014 (the “First Cash Payment”), (2) the Company will make a cash payment of $5.0 million no later than June 30, 2014 (the “Second Cash Payment” and together with the First Cash Payment, the “Cash Payments”), (3) the Company will issue to Hexagon a two-year $6 million unsecured note (the “Hexagon Replacement Note”), bearing interest at an annual rate of 8%, requiring principal and interest payments of $90,000 per month, and (4) the Company will issue to Hexagon 943,208 shares of unregistered common stock. The parties have also agreed that if either of the Cash Payments is not made on time, an additional $1.0 million in principal will be added to the Hexagon Replacement Note, and if the Hexagon Replacement Note is not retired by December 31, 2014, the Company will issue an additional 1.0 million shares of its common stock to Hexagon. Finally, Hexagon will not, until the earlier of June 30, 2014 or the date the Company achieves sustained average trading volume in excess of 100,000 shares per day for at least ten consecutive trading days, sell or otherwise transfer for value any shares of the Company’s common stock or any securities convertible into the Company’s common stock, and that thereafter until December 31, 2014, Hexagon will not sell or otherwise transfer for value more than 10,000 shares per week of the Company’s common stock or any securities convertible into the Company’s common stock.

Debentures Extension

On May 19, 2014, holders of the remaining Debentures agreed to extend the maturity date under the Debentures from May 16, 2014 to August 15, 2014, and to waive their right to declare an event of default in connection with the May 16, 2014 maturity date under the Debentures. On June 6, 2014, the holders of the remaining Debentures agreed to further extend the maturity date under the Debentures from August 15, 2014 to January 15, 2015.

May Private Placement

On May 30, 2014 the Company entered into and consummated a private placement (the “May Private Placement”) of its 8% Convertible Preferred Stock (“Preferred Stock”) with accredited investors, pursuant to which the company sold $7.50 million of Preferred Stock. The Preferred Stock provides for a dividend of 8% per annum, payable quarterly in arrears, which can be paid in cash or in shares of Common Stock if certain conditions are met. Each investor in the Preferred Stock was also granted a three-year warrant to purchase common stock equal to 50% of the number of shares that would be issuable upon full conversion of the Preferred Stock at the initial conversion price. The Company has the right to convert the Preferred Stock to common stock if the common stock is traded at $7.50 for ten consecutive trading days and the underlying shares of common stock are registered for resale. TR Winston was the placement agent for the transaction and will be paid a fee equal to 8% of the proceeds plus an additional 1% of the proceeds plus $25,000 in expenses. The Company used $5.00 million of the proceeds of the private placement to make the first cash payment in connection with the Hexagon settlement (discussed above), and intends to use the remaining proceeds to fund its oil and gas development projects and for general administrative expenses. On June 6, 2014, TR Winston executed a commitment to purchase or effect the purchase by third parties of an additional $15 million in Preferred Stock, which transaction is to be consummated within ninety (90) days.

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, 2013, 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, 2013.

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, 2014, the Company had $18.57 million outstanding under its term loans with Hexagon, LLC (“Hexagon”) and $6.73 million outstanding under its 8% Senior Secured Convertible Debentures (the “Debentures”). Both the term loans and the Debentures were to mature on May 16, 2014.

In the first three months of 2014, the Company consummated the following transactions: (i) on January 22, 2014, the Company closed a $7.50 million private placement of units consisting of one share of Common Stock and one three-year warrant to purchase one share of Common Stock for aggregate gross proceeds of $5,918,250, plus an additional $1,425,000 in proceeds committed by certain officers and directors of the Company, which we expect to be funded upon our receipt of the required shareholder approval; (ii) on January 31, 2014, the Company entered into a Debenture Conversion Agreement, under which $9.0 million in Debentures was immediately converted to Common Stock at a price of $2.00 per common share. In addition, (i) on May 19, 2014, the Company received extensions from both Hexagon and the remaining Debenture holders of the maturity dates under the Company’s term loans and Debentures, respectively, from May 16, 2014 to August 15, 2014; (ii) on May 30, 2014, the Company and Hexagon entered into an agreement providing for the settlement of all amounts outstanding under the term loans, in exchange for two cash payments of $5.0 million each to be made by the Company to Hexagon on May 30,2014 and June 30, 2014; as well as the issuance to Hexagon of a two-year $6.0 million unsecured 8% note and 943,208 shares of unregistered Common Stock; (iii) on May 30, 2014 the Company consummated a private placement to accredited investors of 8% Convertible Preferred Stock and three-year warrants to purchase Common Stock equal to 50% of the number of shares issuable upon full conversion of the Preferred Stock for gross proceeds of $7.50 million; (iv) on June 6, 2014, the holders of the remaining Debentures agreed to further extend the maturity date under the Debentures from August 15, 2014 to January 15, 2015; and (v) on June 6, 2014, TR Winston executed a commitment to purchase or effect the purchase by third parties of an additional $15 million in Preferred Stock, which transaction is to be consummated within ninety (90) days. The consummation of these transactions has been partially reflected in the Company’s balance sheet via the classification of certain portions of the Hexagon term loans and Debentures as long-term debt.

The closing of these transactions provided the Company with working capital for general corporate purposes, as well as a portion of the initial capital requirements to initiate further development activities on two of its Wattenberg prospects. However, the Company will require additional capital to satisfy its obligations to Hexagon under the settlement agreement, to fund its current drilling commitments and capital budget plans, to help fund its ongoing overhead, and to provide additional capital to generally improve its working capital position. We anticipate that such additional funding will be provided by a combination of capital raising activities, including the selling of additional debt and/or equity securities, the selling of certain assets and by the development of certain of the Company’s undeveloped properties via arrangements with joint venture partners. If we are not successful in obtaining sufficient cash sources to fund the aforementioned capital requirements, we may be required to curtail our expenditures, restructure our operations, sell assets on terms which may not be deemed favorable and/or curtail other aspects of our operations, including deferring portions of capital budget. There is no assurance that any such funding will be available to the Company.

Cash Flows

Cash used in operating activities during the three months ended March 31, 2014 was $1.95 million. Cash used in operating activities offset by the cash used in investing activities and cash used in financing activities by $2.69 million, and resulted in a corresponding increase in cash.

The following table compares cash flow items during the three months ended March 31, 2014 and 2013 (in thousands):

	Three months ended March 31,
	2014			2013
Cash provided by (used in):
Operating activities	$	(1,952	)	$	(904	)
Investing activities		(369	)		588
Financing activities		5,012			(177	)
Net change in cash	$	2,691		$	(493	)

During the three months ended March 31, 2014, net used in operating activities was $1.95 million, compared to cash used in operating activities of $0.90 million during the three months ended March 31, 2014, an increase of cash used in operating activities of $1.05 million. The primary changes in operating cash during the three months ended March 31, 2014 were $10.05 million of net loss, $0.43 million increase in cash for other assets, increase in cash for accounts payable and other accrued expenses of $4.74 million, and an increase of cash of $0.09 million for accounts receivable, and offset by a decrease of $0.01 million for restricted cash. The cash flows from operating activities were adjusted for non-cash charges of $0.39 million of depreciation, depletion, amortization and accretion expenses, $ 0.66 million of debt discount accretion, $0.19 million of amortization of deferred financing costs, common stock issued for financing costs for both the private placement of issuance of common stock and convertible debentures of $0.69 million, common stock issued for interest of $0.15 million, $6.61 million issuance of a warrant to purchase common stock recorded as a debt inducement for the conversion of convertible debentures, $0.44 million for issuance of stock for services and compensation, and offset by a decrease in cash for non-cash change in fair value of convertible debentures conversion option of $1.15 million. Operating cash was increased by $0.09 million of cash provided by a decrease in accounts receivable, cash provided by other assets of $0.43 million, which was offset by cash used in restricted cash and accounts payable and other accrued expenses of $0.01 million and $0.46 million, respectively.

During the three month ended March 31, 2014, net cash used in investing activities was $0.37 million, compared to net cash provided by investing activity of $0.59 million during the three months ended March 31, 2013, a decrease of cash used in investing activities of $0.22 million. The primary changes in investing cash during the three months ended March 31, 2014 were a decrease in cash of $0.32 million of drilling expenditures, $0.05 million in expenditures related to additions to oil and gas properties, and $0.01 million in expenditures related to office equipment.

During the three months ended March 31, 2014, net cash provided by financing activities was $5.01 million, compared to net cash used in financing activities of $0.18 million during the three months ended March 31, 2013, an increase of $5.19 million. The changes in financing cash during the three months ended March 31, 2014 were primarily due to proceeds from the January 2014 Private Placement of $7.5 million which was offset by $1.43 million from participating management and directors which are subject to receipt of shareholder approval as required by NASDAQ’s continued listing requirements. The $7.5 million was further reduced by fees associated with financing paid which resulted in proceeds of $5.33 million from the January 2014 Private Placement. The proceeds from the January 2014 Private Placement were partially offset by net repayments of debt of $0.31 million.

Capital Resources

The Company will require additional capital to fund its current capital obligations, capital budget plans, to help fund its ongoing G&A and to provide additional capital to generally improve its working capital position. We anticipate that such additional funding will be provided by a combination of capital raising activities, including the selling of additional debt and/or equity securities, the selling of certain un-evaluated and evaluated properties and by the development of certain undeveloped properties via arrangements with joint venture partners. If we are not successful in obtaining sufficient cash resources to fund the aforementioned capital requirements, we may be required to curtail our expenditures, restructure our operations, sell assets on terms which may not be deemed favorable and/or curtail other aspects of our operations, decrease our working interest in planned drilling areas, including deferring certain capital expenditures in key development areas. There is no assurance that any such funding will be available to the Company.

During the year ended December 31, 2014, the Company was provided three JV authorizations for expenditures cash calls totaling $5.05 million by the operator of three horizontal wells in the North Wattenberg field. Per the terms of the JOA, if the Company does not generate enough capital from equity or debt raises, and then the Company may be placed in non-pay status with the operator per a Notice of Default. Should this occur, after thirty days without cure, the operator may forward the Company a Notice of Non-Consent and will be imposed up to a 300% penalty to buy-back working interest in the new drill wells.

Results of Operations

Three months ended March 31, 2014 compared to three months ended March 31, 2013

The following table compares operating data for the three months ended March 31, 2014 to March 31, 2013:

	Three months ended March 31,
	2014			2013
Revenues:
Oil sales	$	700,087		$	1,127,333
Gas sales		87,667			106,397
Operating fees		34,727			48,503
Realized gain on commodity price derivatives		11,143			19,890
Total revenues		833,624			1,302,123

Costs and expenses:
Production costs		416,323			303,847
Production taxes		93,680			115,994
General and administrative		2,958,416			984,259
Depreciation, depletion and amortization		388,635			689,654
Total costs and expenses		3,857,054			2,093,754

Loss from operations		(3,023,429	)		(791,631	)

Other Income (expenses):
Other income		53			251
Inducement expense		(6,661,275	)		-
Convertible notes conversion derivative gain (loss)		1,150,000			(20,000	)
Interest expense		(1,516,331	)		(1,636,159	)
Total other expenses		(7,027,553	)		(1,655,908	)

Net loss	$	(10,050,982	)	$	(2,447,539	)

Total revenues

Total revenues were $0.83 million for the three months ended March 31, 2014, compared to $1.30 million for the three months ended March 31, 2013, a decrease of $0.47 million, or 36%. The decrease in revenues was due primarily to a decrease in production volumes. During the three months ended March 2014 and 2013, production amounts were 10,288 and 18,215 BOE, respectively, a decrease of 7,927 BOE, or 44%. Declines in production are primarily attributable to natural production declines related to mature producing properties, but were also affected by the temporary reduction in production from five of the Company’s properties that experienced production difficulties during the quarter. Producing wells that went off-line were idle for longer periods of time than expected due to the lack of availability of workover/production rigs in the area. The effect of this production decrease was partially offset by an increase in the overall average price per BOE to $76.58 in 2014 from $67.73 in 2013, an increase of $8.85 or 13%.

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

	For the Three Months Ended March 31,
	2014				2013
Product
Oil (Bbl.)			8,455				13,458
Oil (Bbls)-average price (1)		$	82.80			$	83.77

Natural Gas (MCF)-volume			10,997				24,215
Natural Gas (MCF)-average price (2)		$	7.97			$	4.39

Barrels of oil equivalent (BOE)			10,288				18,215
Average daily net production (BOE)			114				202
Average Price per BOE (1)		$	76.58			$	67.73

(1) Does not include the realized price effects of hedges
(2) Includes proceeds from the sale of NGL's

Oil and gas production costs, production taxes, depreciation, depletion, and amortization

Average Price per BOE(1)		$	76.58			$	67.73

Production costs per BOE			40.47				16.68
Production taxes per BOE			9.11				6.37
Depreciation, depletion, and amortization per BOE			37.78				37.86
Total operating costs per BOE		$	87.36			$	60.91

Gross margin per BOE		$	(10.78	)		$	6.82

Gross margin percentage			-14	%			10.07	%

(1) Does not include the realized price effects of hedges

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, 2014, the Company did not maintain any active commodity swaps. The commodity swap ended in January 31, 2014 for 100 barrels of oil per day at a price of $99.25 per barrel.

Commodity price derivative realized gains were $0.01 million for the three months ended March 31, 2014, compared to realize gains of $0.02 million during the three months ended March 31, 2013, a decrease in realized gains/losses of $0.01 million or 50%.

Production costs

Production costs were $0.42 million during the three months ended March 31, 2014, compared to $0.30 million for the three months ended March 31, 2013, an increase of $0.12 million, or 40%. Increase in production costs in 2014 was from an increase of the number of required well work, property improvements, and maintenance of productive wells. Production costs per BOE increased to $40.47 for the three months ended March 31, 2014 from $16.68 in 2013, an increase of $23.79 per BOE, or 143%, primarily as a result of reduced volumes of BOE in 2013 and high well work frequency. During the three months ended March 31, 2014, work-over rigs had limited availability due to high Industry activity within the operating area of the Company. As a result, idled wells for routine well maintenance or other repairs were off-line longer than anticipated, which substantially decreased our production.

Production taxes

Production taxes were $0.09 million for the three months ended March 31, 2014, compared to $0.12 million for the three months ended March 31, 2013, a decrease of $0.03 million, or 25%. Decrease in production taxes was from a decrease in production and product mix per state. Currently, ad valorem, severance and conservation taxes range from 1% to 13% based on the state and county which production is derived. Production taxes per BOE increased to $9.11 during the three months ended March 31, 2014 from $6.37 in 2013, an increase of $2.74 or 43%. During the three months ended March 31, 2014, work-over rigs were in high demand within the operating area of the Company with a small supply of work-over rigs. As a result, our wells which went down for normal well maintenance or other repairs did not operate for an extended period of time which substantially decreased our BOE.

General and administrative

General and administrative expenses were $2.96 million during the three months ended March 31, 2014, compared to $0.98 million during the three months ended March 31, 2013, an increase of $1.98 million, or 202%. Non-cash general and administrative items for the three months ended March 31, 2014 were $1.69 million compared to $0.36 million during the three months ending March 31, 2013, an increase of $1.33 million, or 369%. The increase in non-cash general and administrative expenses was due to additional financing costs of $0.69 million; increase in non-cash compensation of $0.44 million; $0.69 million fees associated with completing the January Private Placement; and non-cash compensation to a third party is $0.4 million. Cash general and administrative expenses were $1.27 million during the three months ended March 31 2014, compared to $0.62 million during the three months ended March 31, 2013, an increase of $0.65 million, or 104%. The increase in cash general and administrative expenses was largely due to $0.18 million of due diligence cost incurred in connection with a potential acquisition, as well as additional legal and other contract professional services expenses, increase of staffing and partially offset of and other expenses.

Depreciation, depletion, and amortization

Depreciation, depletion, and amortization were $0.39 million during the three months ended March 31, 2014, compared to $0.70 million during the three months ended March 31, 2013, a decrease of $0.31 million, or 44%. Decrease in depreciation, depletion, and amortization was from (i) a decrease in production amounts in 2014 from 2013, (ii) an increase in the depletion base for the depletion calculation, and (iii) a decrease in the depletion rate. Production amounts decreased to 10,288 from 18,215 for the three months ended March 31, 2014 and 2013, respectively, a decrease of 7,927, or 44%. The decrease in depletion was based on a lower depletion base. Depreciation, depletion, and amortization per BOE decreased to $37.78 from $37.86, respectively, for the three months ended March 31, 2014 and 2013, a decrease of $0.08, or 1%. During the three months ended March 31, 2014, work-over rigs were in high demand within the operating area of the Company with a small supply of work-over rigs. As a result, our wells which went down for normal well maintenance or other repairs did not operate for an extended period of time which substantially decreased our BOE.

Inducement expense

Inducement expenses were $6.66million during the three months ended March 31, 2014, compared to $0 during the three months ended March 31, 2013. 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 Lattice model to value the warrants, utilizing a volatility of 65%, and a life of 3 years, which arrived at a fair value of $6.61 million for the Warrants.

Interest Expense

For the three months ended March 31, 2014 and 2013, the Company incurred interest expense of approximately $1.52 million and $1.64 million, respectively, of which approximately $1.05 million and $1.00 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. The decrease in interest expense was primarily attributable to a decrease in the interest rate on the Company’s term loans from 15% to 10% that occurred effective April 1, 2013, but partially offset by an increase in the Company’s convertible debentures.

Off-Balance Sheet Arrangements

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

Capital Budget

We anticipate a working capital budget of up to $28.0 million for the remainder of 2014. The budget is allocated toward the exploitation of two unconventional reservoirs located in the Wattenberg field within the DJ Basin that will apply horizontal drilling in the Niobrara shale and Codell formations. This entire capital budget is subject to the securing of adequate capital through drilling, equity, and debt instruments. Although we secured approximately $5.0 million, from the January Private Placement, $15.0 million, commitment to purchase or effect the purchase with Preferred Stock from TR. Winston, and an additional $7.50 million, from the May Private Placement, some of the proceeds from these transactions were applied to the payment and servicing of our term debt.

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, the divestiture of non-strategic assets,. We do not anticipate any significant expansion of our current DJ Basin acreage position in the near term; however, we are targeting attractive Wattenberg acquisitions.

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 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. Since early 2010, we have acquired and/or developed 25 producing wells. As of December 31, 2013 we owned interests in approximately 123,000 gross (107,000 net) leasehold acres, of which 111,000 gross (88,000 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 currently have two key unconventional reservoir properties located in the Greater Wattenberg field. We participated in the drilling of one non-operated horizontal well in our North Wattenberg asset during the fourth quarter of 2013, which was completed in the first quarter of 2014 and is now on post-frac production. We are also participating in three additional non-operated horizontal wells on this property that were drilled in the first quarter, 2014. We also plan to operate the drilling of two horizontal wells on our South Wattenberg property during the third quarter of 2014 in which we have a 50% working interest and a 25% working interest in two wells. Drilling activities on both properties will target the prolific and well established Niobrara and Codell formations. Subject to the securing of additional capital, we expect to participate in up to 18 wells in these two assets, with an expected investment that exceeds up to $26.0 million. As of June 1, 2014, the Company has participated in the following in the Watttenberg Field: 1) one horizontal well that is currently on-line, and 2) 3 horizontal wells that are drilled and commencing completion operations in 2 nd Quarter 2014.

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 $25.0 million in drilling and development costs on three of our DJ Basin assets where initial exploitation 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.

Engaging in certain exploration activities, including geologic and geophysics projects, to define additional prospects within our inventory of DJ Basin properties that may have significant development upside . Subject to the securing of additional capital, we anticipate an expenditure of $2.0 to $5.0 million in 2014 to acquire seismic data on at least three key DJ Basin target areas to identify both conventional and unconventional drilling opportunities.

Controlling Costs . We seek to maximize our returns on capital employed by minimizing our production costs via prudent engineering and field management, and by closely monitoring general and administrative expenses. We also minimize initial capital expenditures on geological and geophysical overhead, seismic data, hardware and software by partnering with cost efficient operators that have already invested capital in such. We also outsource some of our technical functions in order to help reduce general and administrative and capital requirements.

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. From time to time, 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.

Currently, our inventory of developed and undeveloped acreage includes approximately 12,000 net acres that are held by production, approximately 25,000 net acres, 60,000, 4,000, 4,000 and 2,000 net acres that expire in the years 2014, 2015, 2016, 2017, and thereafter, respectively. Approximately 82% of our inventory of undeveloped acreage provides for extension of lease terms from two to five years, at the option of the Company, via payment of varying, but typically nominal, extension amounts. However, due to our current liquidity issues, we may enter into one or more transactions to sell a significant number of leases, both developed and undeveloped, to enable us to pay down our outstanding debt or satisfy other financial obligations.

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 gas company 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 to balance our existing organic cash flow. We will need to raise additional capital to fund our exploration and development budget. We will 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.

We intend 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:

	●	changes in global supply and demand for oil and natural gas;
	●	the actions of the Organization of Petroleum Exporting Countries, or OPEC;
	●	the price and quantity of imports of foreign oil and natural gas;
	●	acts of war or terrorism;
	●	political conditions and events, including embargoes, affecting oil-producing activity;
	●	the level of global oil and natural gas exploration and production activity;
	●	the level of global oil and natural gas inventories;
	●	weather conditions;
	●	technological advances affecting energy consumption; and
	●	transportation options from trucking, rail, and pipeline
	●	the price and availability of alternative fuels.

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:

	●	our production and/or sales of natural gas are less than expected;
	●	payments owed under derivative hedging contracts come due prior to receipt of the hedged month’s production revenue; or
	●	the counter party to the hedging contract defaults on its contract obligations.

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.

Obligations and Commitments

We have the following contractual obligations and commitments as of March 31, 2014 (in thousands):

	Payments due by period
Contractual obligations	Total		Within 1 Year		1-3 years		4-5 years		More than 5 years
Secured debt	$	18,566	$	10,483	$	8,083	$	-	$	-
Interest on secured debt		1,392		1,392		-		-		-
Convertible debentures		6,728		6,728		-		-		-
Interest on convertible debentures		403		403		-		-		-
Operating leases & Other		44		44		-		-		-
Total contractual cash obligations	$	27,133	$	19,050	$	8,083	$	-	$	-

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, 2013, using the average, first-day-of-the-month price during the 12-month period ending December 31, 2013.

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.

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.

Share Based Compensation

The Company accounts for share-based compensation by estimating the fair value of share-based payment awards made to employees and directors, including stock options restricted stock grants, and employees stock purchases related to employee stock purchase plans, on the date of grant using an option-pricing model. The value of the portion of the award that is ultimately expected to vest is recognized as an expense ratably over the requisite service periods.

Derivative Instruments

Periodically, the Company entered into swaps to reduce the effect of price changes on a portion of our future oil production. We reflect the fair market value of our derivative instruments on our balance sheet. Our estimates of fair value are determined by obtaining independent market quotes as well as utilizing a valuation model that is based upon underlying forward curve data and risk free interest rates. Changes in commodity prices will result in substantially similar changes in the fair value of our commodity derivative agreements. We do not apply hedge accounting to any of our derivative contracts, therefore we recognize mark-to-market gains and losses in earnings currently.

Item 3. Quantitative and Qualitative Disclosures about Market Risk.

Not Applicable

Item 4. Controls and Procedures.

Evaluation of Disclosure Controls and Procedures

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.

Management has conducted, with the participation of our Chief Executive Officer, Chief Financial Officer, and our Interim Chief Financial Officer, an assessment, including testing of the effectiveness of our internal control over financial reporting as of March 31, 2014. Management’s assessment of internal control over financial reporting was conducted using the criteria in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission, or COSO.

Based on the evaluation and the identification of the material weaknesses in internal control over financial reporting described below, our Chief Executive Officer, Chief Financial Officer, and our Interim Chief Financial Officer have concluded that, as of March 31, 2014, the Company’s disclosure 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, we identified the following material weaknesses in our internal control over financial reporting as of March 31, 2014:

·	As a result of the resignation of our Chief Financial Officer as previously disclosed by way of current reports on Form 8-K, we did not maintain effective monitoring controls and related segregation of duties over automated and manual journal entry transaction processes.

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, 2014, based on the Internal Control—Integrated Framework issued by COSO.

Remediation Efforts

We plan to make necessary changes and improvements to the overall design of our control environment to address the material weakness in internal control over financial reporting described above. In particular, we expect to hire a financial consulting firm to assist with journal entry processing. Additionally, we will perform an analysis of all automated and manual procedures to strengthen the effectiveness of our segregation of duties.

Management believes through the implementation of the foregoing initiative, we 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

We have previously disclosed by way of current reports on Form 8-K filed with the SEC that on May 16, 2014, A. Bradley Gabbard, the Company’s Chief Financial Officer, announced his decision to resign from his positions as an officer and a director of the Company in order to pursue other interests. Mr. Gabbard’s resignation was not due to any disagreement with the Company, the Board of Directors or the Company’s management.

Also on May 16, 2014, the Board of Directors of the Company appointed Eric Ulwelling, who was the Company’s Chief Accounting Officer and Controller, to the position of Interim Chief Financial Officer. This event has caused a change in our internal control over financial reporting during the quarter-ended March 31, 2014.

PART II - OTHER INFORMATION

Item 1. Legal Proceedings.

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.

There are no other material pending legal proceedings to which we or our properties are subject.

Item 1A. Risk Factors.

There has been no material changes in our Risk Factors from those reported in Item 1A of Part I of our 2013 Annual Report on Form 10-K filed with the Securities and Exchange Commission, which we incorporate by reference herein. No additional risk factors are noted.

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

We have previously disclosed by way of current reports on Form 8-K filed with the SEC all sales by us of our unregistered securities during the first three months of 2014.

Item 3. Defaults upon Senior Securities.

None.

Item 4. Mine Safety Disclosures.

Not Applicable

Item 5. Other Information.

The Company filed an Amended Certificate of Designations, Preferences and Rights of Series A 8% Convertible Preferred Stock (the “Certificate of Designations”) on June 12, 2014 with the Secretary of State of the State of Nevada, which was effective upon filing. A copy of the Certificate of Designations is attached hereto as Exhibit 3.1 and incorporated herein by reference.

Item 6. Exhibits.

Exhibit Number		Exhibit Description
3.1		Amendment to Certificate of Designations dated June 12, 2014.
4.1		Five Year Warrant to Market Development Consulting Group dated January 17, 2014.
4.2		Five Year Warrant (Anniversary Warrant) to Market Development Consulting Group dated January 17, 2014.
10.1		Letter Agreement dated May 19, 2014 with holders of the 8% Senior Secured Convertible Debentures.
10.2		Amendment to Debentures dated June 6, 2014.
10.3		Separation Agreement with W. Phillip Marcum dated April 24, 2014.
10.4		Employment Agreement with Robert A. Bell dated May 1, 2014.
10.5		Termination of Investment Banking Agreement with T.R. Winston dated as of March 19, 2013.
10.6		Transaction Fee Agreement with T.R. Winston dated as of March 28, 2014.
10.7		Amendment to Transaction Fee Agreement with T.R. Winston dated as of April 29, 2014.
10.8		Engagement Agreement for Financial Advisory Services with MLV & Co. LLC dated as of February 21, 2014.
10.9		Letter Agreement with T.R. Winston dated as of June 6, 2014.
31.1		Certification of the Chief Executive Officer pursuant to Section 302 of the Sarbanes Oxley Act of 2002
31.2		Certification of the Acting Chief Financial Officer pursuant to Section 302 of the Sarbanes Oxley Act of 2002
32.1		Certification of the Chief Executive Officer pursuant to Section 906 of the Sarbanes Oxley Act of 2002
32.2		Certification of the Acting Chief Financial Officer pursuant to Section 906 of the Sarbanes Oxley Act of 2002

101.INS		XBRL Instance Document
101.SCH		XBRL Taxonomy Schema
101.CAL		XBRL Taxonomy Calculation Linkbase
101.DEF		XBRL Taxonomy Definition Linkbase
101.LAB		XBRL Taxonomy Label Linkbase
101.PRE		XBRL Taxonomy Presentation Linkbase

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

Signature	Title	Date

/s/ Abraham Mirman	Chief Executive Officer	June 16, 2014
Abraham Mirman	(Principal Executive Officer)

/s/ Eric Ulwelling	Acting Chief Financial Officer and Chief Accounting Officer	June 16, 2014
Eric Ulwelling	(Principal Financial Officer)

EXHIBIT INDEX

Exhibit Number		Exhibit Description
3.1		Amendment to Certificate of Designations dated June 12, 2014.
4.1		Five Year Warrant to Market Development Consulting Group dated January 17, 2014.
4.2		Five Year Warrant (Anniversary Warrant) to Market Development Consulting Group dated January 17, 2014.
10.1		Letter Agreement dated May 19, 2014 with holders of the 8% Senior Secured Convertible Debentures.
10.2		Amendment to Debentures dated June 6, 2014.
10.3		Separation Agreement with W. Phillip Marcum dated April 24, 2014.
10.4		Employment Agreement with Robert A. Bell dated May 1, 2014.
10.5		Termination of Investment Banking Agreement with T.R. Winston dated as of March 19, 2013.
10.6		Transaction Fee Agreement with T.R. Winston dated as of March 28, 2014.
10.7		Amendment to Transaction Fee Agreement with T.R. Winston dated as of April 29, 2014.
10.8		Engagement Agreement for Financial Advisory Services with MLV & Co. LLC dated as of February 21, 2014.
10.9		Letter Agreement with T.R. Winston dated as of June 6, 2014.
31.1		Certification of the Chief Executive Officer pursuant to Section 302 of the Sarbanes Oxley Act of 2002
31.2		Certification of the Acting Chief Financial Officer pursuant to Section 302 of the Sarbanes Oxley Act of 2002
32.1		Certification of the Chief Executive Officer pursuant to Section 906 of the Sarbanes Oxley Act of 2002
32.2		Certification of the Acting Chief Financial Officer pursuant to Section 906 of the Sarbanes Oxley Act of 2002

101.INS		XBRL Instance Document
101.SCH		XBRL Taxonomy Schema
101.CAL		XBRL Taxonomy Calculation Linkbase
101.DEF		XBRL Taxonomy Definition Linkbase
101.LAB		XBRL Taxonomy Label Linkbase
101.PRE		XBRL Taxonomy Presentation Linkbase

	HOLDERS:



	By:
	Name:
	Title:

	LILIS ENERGY, INC.

	By:	/s/ A. Bradley Gabbard
		A. Bradley Gabbard, Chief Financial Officer

	LILIS ENERGY, INC.

	By:	/s/ A. Bradley Gabbard
		A. Bradley Gabbard, Chief Financial Officer

	Very truly yours,

	EZ Colony Partners, LLC, a Delaware limited liability company

		/s/ Bryan Ezralow
	Name:	Bryan Ezralow as Trustee of the Bryan
		Ezralow 1994 Trust
	Title:	Managing General Partner

	Jonathan & Nancy Glaser Family Trust DTD 12/16/1998 Jonathan M. Glaser and Nancy E. Glaser TTEES

		/s/ Jonathan Glaser
	Name:	Jonathan Glaser
	Title:	Trustee

	COMPANY

	Lilis Energy, Inc.

	By:	/s/ Abraham Mirman
	Name:	Abraham Mirman
	Title:	Chief Executive Officer

	Wallington Investment Holdings, Ltd.

		/s/ Michael Khoury
	Name:	Michael Khoury
	Title:	Director

	Steven B. Dunn and Laura Dunn Revocable Trust DTD 10/28/10, Steven B. Dunn & Laura Dunn TTEES

		/s/ Steven B. Dunn
	Name:	Steven B. Dunn
	Title:	Trustee

	G. Tyler Runnels and Jasmine N. Runnels TTEES The Runnels Family Trust DTD 1-11-2000

		/s/ G. Tyler Runnels
	Name:	G. Tyler Runnels
	Title:	Trustee

	EMSE, LLC, a Delaware limited liability company

		/s/ Marc Ezralow
	Name:	Marc Ezralow
	Title:	Manager

	LILIS ENERGY, INC.

	By:
		Abraham Mirman
	Its:	Chief Executive Officer

	HOLDERS

	EZ Colony Partners, LLC, a Delaware limited liability company

		/s/ Bryan Ezralow
	Name:	Bryan Ezralow as Trustee of the Bryan
		Ezralow 1994 Trust
	Title:	Managing General Partner

	LILIS:

	Lilis Energy, Inc., a Nevada corporation

	By:	A. Bradley Gabbard
	Its:	Chief Financial Officer
	Name:	A. Bradley Gabbard

If to Executive, addressed to:	Mr. Robert A. (Bob) Bell
	2767 Avenida de Autlan
	Camarillo, CA 93010
	(661) 829-9434
	rbell@peakoperator.com

If to the Company, addressed to:	Lilis Energy, Inc.
	1900 Grant Street, Suite #720
	Denver, CO 80203
	Attention: Chief Executive Officer

With a copy to:	Davis Graham & Stubbs LLP
	1550 17 th Street, Suite 500
	Denver, CO 80202
	Attention: Ronald R. Levine II, Esq.


Executive’s Printed Name		Company Representative


Executive’s Signature		Company’s Execution Date

	Sincerely,

	LILIS ENERGY, INC.

	By:	/s/ A. Bradley Gabbard
	Name:	A. Bradley Gabbard
	Title:	Chief Financial Officer and Chief Operating Officer

	T.R. WINSTON & COMPANY, LLC

	By:	/s/ G. Tyler Runnels
	Name:	G. Tyler Runnels
	Title:	Chairman & CEO

MLV & Co. LLC

By:	/s/ Dean Colucci
Name:	Dean Colucci
Title:	President

Lilis Energy, Inc.

By:	/s/ Avi Mirman
Name:	Avi Mirman
Title:	President

	Very truly yours

	LILIS ENERGY, INC.

	By:	/s/ Abraham Mirman
		Abraham Mirman
	Its:	Chief Executive Officer

	T.R. Winston & Company

		/s/ G. Tyler Runnels
	Name:	G. Tyler Runnels
	Title:	Chairman & CEO

1.	I have reviewed this report on Form 10-Q of Lilis Energy, Inc. ("Registrant");

2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the Registrant as of, and for, the periods presented in this report;

4.	The Registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the Registrant and have:

	a.	designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the Registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

	b.	designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

	c.	evaluated the effectiveness of the Registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

	d.	disclosed in this report any change in the Registrant's internal control over financial reporting that occurred during the Registrant's most recent fiscal quarter (the Registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the Registrant's internal control over financial reporting; and

5.	The Registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the Registrant's auditors and the audit committee of Registrant's board of directors (or persons performing the equivalent functions):

	a.	all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the Registrant's ability to record, process, summarize and report financial information; and

	b.	any fraud, whether or not material, that involves management or other employees who have a significant role in the Registrant's internal control over financial reporting.

/s/ Eric Ulwelling
Eric Ulwelling
Acting Chief Financial Officer