LILIS ENERGY, INC. - FORM 10-Q

Attached files

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EXCEL - IDEA: XBRL DOCUMENT - LILIS ENERGY, INC.	Financial_Report.xls
EX-31.1 - CERTIFICATION OF THE CHIEF EXECUTIVE OFFICER PURSUANT TO SECTION 302 OF THE SARBANES OXLEY ACT OF 2002 - LILIS ENERGY, INC.	f10q0313ex31i_recovery.htm
EX-32.2 - CERTIFICATION OF THE CHIEF FINANCIAL OFFICER PURSUANT TO SECTION 906 OF THE SARBANES OXLEY ACT OF 2002 - LILIS ENERGY, INC.	f10q0313ex32ii_recovery.htm
EX-31.2 - CERTIFICATION OF THE CHIEF FINANCIAL OFFICER PURSUANT TO SECTION 302 OF THE SARBANES OXLEY ACT OF 2002 - LILIS ENERGY, INC.	f10q0313ex31ii_recovery.htm
EX-32.1 - CERTIFICATION OF THE CHIEF EXECUTIVE OFFICER PURSUANT TO SECTION 906 OF THE SARBANES OXLEY ACT OF 2002 - LILIS ENERGY, INC.	f10q0313ex32i_recovery.htm

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, 2013

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

For the transition period from ______to______.

333-152571

(Commission File No.)

RECOVERY 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 whether 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 preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No o

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 ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company filer. See the definitions of “accelerated filer” and “large accelerated filer” in Rule 12b-2 of the Exchange Act (Check one):

Large Accelerated Filer o

Accelerated Filer o

Non-Accelerated Filer o

Smaller Reporting Company x

Recovery Energy, Inc.

INDEX

PART I– FINANCIAL INFORMATION

Item 1.	Financial Statements (Unaudited)
	Consolidated Balance Sheets as of March 31, 2013 and December 31, 2012	1
	Consolidated Statements of Operations for the Three Months Ended March 31, 2013 and 2012	3
	Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2013 and 2012	4
	Notes to Consolidated Financial Statements	5
Item 2.	Management’s Discussion and Analysis of Financial Condition	16
Item 3.	Quantitative and Qualitative Disclosures About Market Risk
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	28
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.”. 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:

●	availability of capital on an economic basis, or at all, to fund our capital needs;
●	failure to meet requirements under our credit agreements or debentures, which could lead to foreclosure of significant assets;
●	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;
●	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 December 31, 2012 Form 10K and other SEC filings, available free of charge at the SEC’s website (www.sec.gov).

Part 1. FINANCIAL INFORMATION

Item 1. Financial Statements

RECOVERY ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

(UNAUDITED)

	March 31,			December 31,
	2013			2012
Assets
Current assets:
Cash	$	477,056		$	970,035
Restricted cash		759,436			671,382
Accounts receivable (net of allowance of $50,000 and $0 at March 31, 2013 and December 31, 2012, respectively)		626,750			934,591
Prepaid assets		80,289			13,458
Total current assets		1,943,531			2,589,466

Oil and gas properties (full cost method), at cost:
Developed properties		58,066,808			58,610,095
Undeveloped acreage, excluded from amortization		27,958,138			28,067,005
Wells in progress, excluded from amortization		202,177			193,515
Total oil and gas properties, at cost		86,227,123			86,870,615

Less accumulated depreciation, depletion , amortization, and impairment		(43,851,236	)		(43,187,962	)
Net oil and gas properties, at cost		42,375,887			43,682,653

Other assets:
Office equipment, net		106,399			90,630
Deferred financing costs, net		797,609			974,856
Restricted cash and deposits		215,541			215,435
Total other assets		1,119,549			1,280,921
Total Assets	$	45,438,967		$	47,553,040

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

RECOVERY ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

(UNAUDITED)

	March 31,			December 31,
	2013			2012
Liabilities and Shareholders' Equity
Current liabilities:
Accounts payable	$	1,166,723		$	1,831,590
Accrued expenses		1,396,987			1,411,016
Short term notes payable		641,150			388,351
Total current liabilities		3,204,860			3,630,957

Long term liabilities:
Asset retirement obligation		996,835			911,546
Term notes payable		18,517,789			18,947,963
Convertible notes payable, net of discount		10,863,932			10,300,361
Convertible notes conversion derivative liability		1,700,000			1,680,000
Total long-term liabilities		32,078,556			31,839,870

Total liabilities		35,283,416			35,470,827

Commitments and contingencies – Note 8 and 9

Shareholders’ equity:
Preferred stock, 10,000,000 authorized, none issued and outstanding		-			-
Common stock, $0.0001 par value: 100,000,000 shares authorized; 18,523,604 and 18,394,401 shares issued and outstanding as of March 31, 2013 and December 31, 2012, respectively		1,853			1,839
Additional paid in capital		118,817,543			118,296,679
Accumulated deficit		(108,663,845	)		(106,216,305	)
Total shareholders' equity		10,155,551			12,082,213
Total Liabilities and Shareholders’ Equity	$	43,438,967		$	47,553,040

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

RECOVERY ENERGY, INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

(UNAUDITED)

	Three Months Ended March 31,
	2013			2012
Revenue:
Oil sales	$	1,127,333		$	1,547,763
Gas sales		106,397			129,676
Operating fees		48,503			43,833
Realized gains (loss) on commodity price derivatives		19,890			(60,912	)
Unrealized loss on commodity price derivatives		-			(104,391	)
Total revenue		1,302,123			1,555,969

Costs and expenses:
Production costs		303,847			367,526
Production taxes		115,994			192,858
General and administrative		984,259			2,022,263
Depreciation, depletion and amortization		689,654			984,090
Impairment of developed properties		-			3,274,718
Total costs and expenses		2,093,754			6,841,455

Loss from operations		(791,631	)		(5,285,486	)

Other income		251			417
Convertible notes conversion derivative gain (loss)		(20,000	)		290,164
Interest expense		(1,636,159	)		(2,132,906	)
Net Loss	$	(2,447,539	)	$	(7,127,811	)
Net loss per common share
Basic and diluted	$	(0.13	)	$	(0.41	)
Weighted average shares outstanding:
Basic and diluted		18,438,905			17,517,242

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

RECOVERY ENERGY, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(UNAUDITED)

	Three months ended March 31,
	2013			2012
Cash flows from operating activities:
Net loss	$	(2,447,539	)	$	(7,127,811	)
Adjustments to reconcile net loss to net cash used in operating activities:
Impairment provision, developed leases		-			3,274,718
Common stock issued for convertible note interest		270,032			229,605
Common stock for services and compensation		250,846			673,228
Changes in the fair value of commodity price derivatives		-			104,391
Amortization of deferred financing costs		177,246			582,810
Change in fair value of convertible notes conversion derivative		20,000			(290,164	)
Accretion of debt discount		563,571			473,916
Depreciation, depletion, amortization and accretion of asset retirement obligation		689,654			984,090
Changes in operating assets and liabilities:
Accounts receivable		307,841			(512,900	)
Restricted cash		(88,054	)		(123,650	)
Other assets		(66,831	)		(91,651	)
Accounts payable and other accrued expenses		(580,466	)		(553,979	)
Net cash used in operating activities		(903,700	)		(2,377,397	)

Cash flows from investing activities:
Acquisition of undeveloped acreage		(7,061	)		-
Drilling capital expenditures		(21,462	)		(415,954	)
Sale of developed property		640,000			-
Sale of undeveloped acreage interests		-			1,443,852
Additions of office equipment		(23,276	)		(649	)
Additions to producing properties		-			(369,163	)
Investment in operating bonds		(105	)		(92	)
Net cash provided by investing activities		588,096			657,994

Cash flows from financing activities:
Proceeds from debt		-			750,000
Repayment of debt		(177,375	)		(569,832	)
Net cash provided by (used in) financing activities		(177,375	)		180,168

Change in cash and cash equivalents		(492,979	)		(1,539,235	)
Cash and cash equivalents at beginning of period		970,035			2,707,722
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	477,056		$	1,168,487

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

RECOVERY 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. (“Recovery”, “Recovery Energy”, “we”, “our”, and the “Company”). The Agreement was accounted for as a reverse acquisition with Coronado being treated as the acquirer for accounting purposes. Accordingly, the financial statements of Coronado have been adopted as the historical financial statements of Recovery.

The Company is an independent oil and gas exploration and production company focused on the Denver-Julesburg Basin (“DJ Basin”) where it holds 127,000 net acres. Recovery drills for, 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

We have a history of sustained losses and cash used by operating activities, including losses of $2.45 million in March 31, 2013 and $37.7 million in the year ended 2012, and cash used by operating activities of $0.90 million in March 2013 and $3.4 million for the year 2012. In addition, as of March 31, 2013 we had a net working capital deficit of $1.26 million. Commencing in late 2012, we implemented a number of cost reduction measures, including a substantial reduction in our staff. Both our Chief Executive Officer (CEO) and Chief Financial Officer (CFO) have also agreed, in their sole discretion and on a temporary basis, to defer their receipt of any cash salary at this time.

In the immediate term, the Company expects that additional capital will be required to fund its capital budget for the remainder of 2013, to help fund its ongoing overhead, provide for payment of minimum interest and principal payments required by term notes, and to provide additional capital to generally improve its working capital position. A portion of this additional capital will be provided by the new convertible debentures as described above. We anticipate that 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 our 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 2013 capital budget.

On a longer term basis, the Company will require capital to retire our term notes and our 8% Senior Secured Convertible Debentures when such debts mature in May 2014.

Pursuant to our credit agreements with Hexagon, a substantial portion of our monthly net revenues derived from our producing properties is required to be used for debt and interest payments. In addition, our debt instruments contain provisions that, absent consent of Hexagon, may restrict our ability to raise additional capital.

As discussed in “Note 12—Subsequent Events,” in April 2013, the Company entered into amendments to both our term loan agreements with Hexagon, LLC (“Hexagon”) and our 8% Senior Secured Convertible Debentures (the “Debentures”) to extend the maturity dates of these debts to May 16, 2014. In addition, the amendments to our term loans also provided for the reduction of the interest rate from 15% to 10% effective March 1, 2013; the payment of interest only for the months of March through June, 2013; a reduction in the minimum monthly payments of principal and interest thereafter from $0.33 million per month to either $0.23 million or $0.19 million, depending on our ability to consummate the sale of certain of our assets by July 1, 2013; and forbearance by the secured lender from exercising its rights under the term loan credit agreements for any breach that may have occurred prior to the amendment.

In consideration for the extended maturity date of both loans and the reduced interest rate and minimum loan payment under the secured term loans, the Company is required to provide to each of our secured lender and the holders of our debentures an additional security interest in 15,000 acres (or 30,000 acres in aggregate) of our undeveloped acreage. In addition, we are required under the amendment to use our reasonable best efforts to pursue certain transactions to improve our financial condition, including the aforementioned sale of certain of our assets, an equity offering or similar capital-raising transaction, one or more joint venture development agreements, and an engineering study of certain of our producing properties to ascertain possible operations to enhance production from those properties. Pursuant to the debenture amendment, the Company and the debenture holders have agreed to waive any breach under the debentures that may have occurred prior to the date of the amendment.

We currently have $19.16 million outstanding under our term loans and $13.40 million outstanding under our debentures.

On April 16, 2013, we entered into an agreement with one of our existing Debenture holders to issue up to an additional $5.0 million in additional debentures with substantially the same terms to the existing 8% Secured Convertible Debentures subject to final approval by our board of directors. Under the terms of this agreement, the holder has agreed to purchase up to $1.5 million of additional debentures on or before July 16, 2013. The funds associated with the initial issuance of debentures will be used by the Company for the drilling and development of certain properties, and for general corporate purposes (see Note 12). The combination of these measures coupled with the aforementioned debt modifications will provide substantial near term relief to our cash flow and liquidity.

NOTE 3 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

The accompanying financial statements were prepared by Recovery 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 2012 consolidated financial statements have been reclassified to conform to the March 31, 2013 consolidated financial statement presentation. Such reclassifications had no effect on net income.

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.

Oil and Gas Producing Activities

The Company follows the full cost method of accounting for oil and gas operations whereby all costs related to the exploration, 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 production equipment is computed using the units-of-production method based upon estimated proved oil and gas reserves. Costs included in the depletion base to be amortized include (a) all proved capitalized costs including capitalized asset retirement costs net of estimated salvage values, less accumulated depletion, (b) estimated future development cost to be incurred in developing proved reserves; and (c) estimated dismantlement and abandonment 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. The properties are reviewed quarterly for impairment. 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 revenues was computed by applying a twelve month average of the first day of the month price of oil and gas to 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, 2013 compared to an impairment of $3.27 million for the three months ended March 31, 2012.

Wells in Progress

Wells in progress represent 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.

Loss per Common Share

Earnings (losses) per share are computed based on the weighted average number of common shares outstanding during the period presented. Diluted earnings (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, 2013, a total of 5,738,900 and 3,152,941, respectively of shares underlying warrants and convertible debentures 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

The Company did not complete any major purchases of undeveloped or producing oil and gas properties during the three months ended March 31, 2013.

In February 2013, the Company completed the sale of certain developed properties for $0.64 million.

NOTE 5 – WELLS IN PROGRESS

During the three months ended March 31, 2013 the Company did not transfer any costs from wells in progress and their respected undeveloped acreage into the developed cost pool.

NOTE 6 - FINANCIAL INSTRUMENTS AND DERIVATIVES

The Company periodically enters into various commodity derivative financial instruments intended to hedge against exposure to market fluctuations of oil prices. As of March 31, 2013, the Company maintained no active financial instruments of this type.

The amounts of gains and losses recognized as a result of our derivative financial instruments were as follows:

	Three months ended March 31,
	2013		2012
Realized gain (loss) on commodity price derivatives	$	19,890	$	(60,912)
Unrealized gains (loss) on commodity price derivatives	$	-	$	(104,391)

Realized gains and losses occurs as individual swaps mature and settle. These gains and losses are recorded as income or expenses in the periods during which applicable contracts settle. Swaps which are unsettled as of a balance sheet date are carried at fair market value, either as an asset or liability (See Note 7 — “Fair Value of Financial Instruments”). Unrealized gains and losses result from mark-to-market changes in the fair value of these derivatives between balance sheet dates.

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 marketplace.

● 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 are measured using Level 1 inputs.

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 types of derivative instruments utilized by the Company included commodity swaps. 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.

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 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 Payable Conversion Feature

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. As of December 31, 2012, the Debentures are convertible at any time at the holders’ option into shares of our common stock at $4.25 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.

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

March 31, 2013

	Level 1		Level 2		Level 3			Total
Assets
Commodity derivative instruments	$	-	$	-	$	-		$	-
Total assets, at fair value	$	-	$	-	$	-		$	-
Liability
Convertible debentures conversion derivative liability	$	-	$	-	$	(1,700,000	)	$	(1,700,000	)
Total liability, at fair value	$	-	$	-	$	(1,700,000	)	$	(1,700,000	)

December 31, 2012

	Level 1		Level 2		Level 3			Total
Assets
Commodity derivative instruments	$	-	$	-	$	-		$	-
Total assets, at fair value	$	-	$	-	$	-		$	-
Liability
Convertible debentures conversion derivative liability	$	-	$	-	$	(1,680,000	)	$	(1,680,000	)
Total liability, at fair value	$	-	$	-	$	(1,680,000	)	$	(1,680,000	)

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, 2013:

Beginning balance, December 31, 2012	$	(1,680,000	)
Convertible debentures conversion derivative gain		-
Additions to derivative liability from Supplemental Debenture		(20,000	)
Ending balance, March 31, 2013	$	(1,700,000	)

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 ending March 31, 2013 or 2012.

NOTE 8 – LOAN AGREEMENTS

Term Loans

The Company entered into three separate loan agreements with Hexagon in January, March and April 2010, each with an original maturity date of December 1, 2010. All three loans originally bore annual interest of 15% (which has been reduced, as discussed below), currently mature on May 16, 2014, 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.

We entered into a loan modification agreement on May 28, 2010, which extended the maturity date of the loans to December 1, 2011. In consideration for extending the maturity of the loans, Hexagon received 250,000 warrants with an exercise price of $6.00 per share. The loan modification agreement also required the Company to issue 250,000 five year warrants to purchase common stock at $6.00 per share to Hexagon if the Company did not repay the loans in full by January 1, 2011. Since the loans were not paid in full by January 1, 2011, the Company issued 250,000 additional warrants with an exercise price of $6.00 per share to Hexagon, which were valued at approximately $1.60 million in the aggregate. This amount was recorded as a deferred financing cost and is being amortized over the remaining term of the loan.

In December 2010, Hexagon extended the maturity date of the loans to September 1, 2012. During the last six months of 2011, Hexagon agreed to temporarily suspend for five months the requirement to remit monthly net revenues in the total amount of approximately $2.00 million as payment on the loans. In November 2011, Hexagon extended the maturity to January 1, 2013. In November 2011, Hexagon also temporarily advanced the Company an additional amount of $0.31 million, which was repaid in full in February 2012. In March 2012, Hexagon extended the maturity of the loans to June 30, 2013, and in connection therewith, the Company agreed to make minimum monthly note payments of $0.33 million, effective immediately. In July 2012, Hexagon extended the maturity date to September 30, 2013. In November 2012, Hexagon extended the maturity date of the loans to December 31, 2013.

On December 27, 2012, in connection with the Company’s lease of deep rights on approximately 6,300 net acres to a third party for total consideration of $1.5 million, the Company paid Hexagon $0.75 million, which reduced the long-term debt principal amount.

In April 2013, Hexagon agreed to amend all three loan agreements to extended the maturity date to May 16, 2014, reduce the interest rate to 10% from 15% beginning retroactively with March 2013, decrease our minimum payment under the term loans to $0.23 or $0.19, depending on our ability to complete the sale of certain of our assets by July 1, 2013, and require 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 are required to provide Hexagon an additional security interest in 15,000 acres of our undeveloped acreage (see Note 12).

The Company is subject to certain non-financial covenants with respect to the Hexagon loan agreements. As of March 31, 2013, the Company was in compliance with all covenants under the facilities.

As of March 31, 2013, the total amount outstanding on the three loan agreements is $19.16 million, of which $.64 million is classified as current.

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 remaining interest through the 18 month anniversary of the original issue date of the Debentures, payable in common stock. T.R. Winston & Company LLC (“TR Winston”) acted as placement agent for the private placement and received $0.40 million of Debentures equal to 5% of the gross proceeds from the sale. The Company is amortizing the $0.40 million over the life of the loan as deferred financing costs. The Company amortized $0.02 million of deferred financing costs into interest expense during the three months ended March 31, 2013, and has $0.11 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 the three months ended March 31, 2012.

On March 19, 2012, the Company entered into agreements with some of its existing Debenture holders to issue up to an additional $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. Five of these wells resulted in commercial production, and one well 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.

The Company has estimated the total value of consideration paid to Supplemental Debenture holders in the form of the modified net profits interest and carried working interest to be approximately $1.16 million, and recorded this amount as a debt discount to be amortized over the remaining life of the Supplemental Debentures.

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, 2013, the Supplemental Debentures. This valuation resulted in an estimated derivative liability as of March 31, 2013 and December 31, 2012 of $1.70 million and $1.68 million, respectively. The portion of the derivative liability that is associated with the Supplemental Debentures, in the approximate amount of $0.70 million, has been recorded as a debt discount, and is being amortized over the remaining life of the Supplemental Debentures.

During the three months ended March 31, 2013 and 2012, the Company amortized $0.56 million and $0.43 million, respectively, of debt discounts.

On September 8, 2012, the Company issued 50,000 shares, valued at $0.23 million, to T.R. Winston & Company LLC 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 of deferred financing costs into interest expense during the three months ended March 31, 2013, and has $0.15 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. In consideration for the extended maturity date the Company is required to provide them an additional security interest in 15,000 acres of our undeveloped acreage (see Note 12).

On April 16, 2013, the Company entered into an agreement with one of its existing Debenture holders to issue up to an additional $5.0 million in additional debentures with substantially the same terms to the existing Debentures. Under the terms of this agreement, the holder has agreed to purchase up to $1.5 million of additional debentures on or before July 16, 2013. The funds associated with the initial issuance of debentures will be used by the Company for the drilling and development of certain properties, and for general corporate purposes (see Note 12).

As of March 31, 2013 and December 31, 2012, the convertible debt is recorded as follows:

	As of March 31, 2013			As of December 31, 2012
Convertible debentures	$	13,400,000		$	13,400,000
Debt discount		(2,536,068	)		(3,099,639	)
Total convertible debentures, net	$	10,863,932		$	10,300,361

Annual debt maturities as of March 31, 2013 are as follows:

Year 1	$	641,150
Year 2		31,917,790
Thereafter		-
Total	$	32,558,940

Failure to make periodic interest payments due under the Debentures (including the Supplemental Debentures) may result in acceleration of all principal and interest then outstanding under the Debentures, and may entitle the holders of the Debentures to exercise their rights to foreclose under the mortgages securing the Debentures. In addition, failure to make the required monthly payments under our term loans could result in immediate acceleration of both the term loans and the Debentures.

Interest Expense

For the three months ended March 31, 2013 and 2012, the Company incurred interest expense of approximately $1.64 million and $2.13 million, respectively, of which approximately $1.00 million and $1.29 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.

NOTE 9 - COMMITMENTS AND CONTINGENCIES

Environmental and Governmental Regulation

At March 31, 2013 and 2012, 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 pollution control, spacing of wells, the unitization and pooling of properties, reports concerning operations, 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, 2013 and 2012, 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 positions 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.

Other Contingencies

We could be liable for liquidated damages under registration rights agreements covering approximately 3.2 million shares of our common stock if we fail to maintain the effectiveness of a prior registration statement as required in the agreements. In such case, we would be required to pay monthly liquidated damages of up to $0.23 million. The maximum aggregate liquidated damages are capped at $1.37 million.

NOTE 10 - SHAREHOLDERS’ EQUITY

Common Stock

As of March 31, 2013, the Company had 100,000,000 shares of common stock and 10,000,000 shares of preferred stock authorized, of which 18,523,604 shares of common stock were issued and outstanding. No preferred shares were issued or outstanding.

During the three months ended March 31, 2013, the Company did not grant any shares of common stock as restricted stock grants to employees, board members, or consultants. The Company issued 129,202 shares for payment of quarterly interest expense on the convertible debentures valued at $0.27 million.

Warrants

A summary of warrant activity for the three months ended March 31, 2013 is presented below:

			Weighted-Average
	Warrants		Exercise Price
Outstanding at December 31, 2012		5,638,900	$	7.04
Granted		100,000		4.24
Exercised, forfeited, or expired		-		-
Outstanding at March 31, 2013		5,738,900	$	6.99

In January 2013, the Company entered into two separate consulting agreements, one with a financial advisory firm and one with a public relations company. Each agreement provided for the issuance by the Company of 200,000 warrants for a total of 400,000 warrants, with a grant price of $4.24 and a total valuation of $0.30 million. The shares vest 25% on March 31, 2013 and 25% for each quarter thereafter. The Company is valuing the warrants each quarter based on their vesting schedule and expensing the amount.

The aggregate intrinsic value of the warrants was approximately $0 for both March 31, 2013 and 2012, based on the Company’s closing common stock price of $1.73 and $3.58, respectively, and the weighted average remaining contract life as of March 31, 2013 was 2.31 years and 2.68 years, respectively.

NOTE 11 - SHARE BASED COMPENSATION

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, 2013, the Company granted no shares of restricted common stock to employees or directors.

A summary of restricted stock grant activity for the year ended December 31, 2012 is presented below:

	Shares
Balance outstanding at December 31, 2012		1,730,710
Granted		-
Vested		(39,553	)
Expired/ cancelled		-
Balance outstanding at March 31, 2013		1,691,157

Total unrecognized compensation cost related to unvested stock grants was approximately $0.60 million as of March 31, 2013. The cost at March 31, 2013 is expected to be recognized over a weighted-average service period of 3 years.

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, 2013.

NOTE 12—SUBSEQUENT EVENTS

In April 2013, we amended both our secured term loans and our Debentures to extend their maturity dates to May 16, 2014. In consideration for the extended maturity dates and the reduced interest rate and minimum loan payment under the secured term loans, the Company is required to provide both Hexagon and the holders of our Debentures an additional security interest in 15,000 acres (or 30,000 acres in aggregate) of our undeveloped acreage. Additionally, pursuant to the amendment to our secured term loans, Hexagon has agreed to (i) reduce our interest rate from 15% to 10% beginning retroactively with March 2013, (ii) permit us to make interest-only payments for March, April, May, and June, after which time the minimum secured term loan payment will be $0.23 million or $0.19 million, depending on our ability to consummate the sale of certain of our assets by July 1, 2013, and (iii) forbear from exercising its rights under the term loan credit agreements for any breach that may have occurred prior to the amendment. In addition, we are required under the term loan amendment to use our reasonable best efforts to pursue certain transactions to improve our financial condition, including the aforementioned sale of certain of our assets, an equity offering or similar capital-raising transaction, one or more joint venture development agreements, and an engineering study of certain of our producing properties to ascertain possible operations to enhance production from those properties. Pursuant to the debenture amendment, the Company and the debenture holders have agreed to waive any breach under the debentures that may have occurred prior to the date of the amendment.

On April 16, 2013, the Company entered into an agreement with one of its existing Debenture holders to issue up to an additional $5.0 million in additional Debentures with substantially the same terms as the existing Debentures. Under the terms of this agreement, the holder has agreed to purchase $1.5 million of additional debentures on or before July 16, 2013. The funds associated with the issuance of the additional Debentures will be used by the Company for the drilling and development of certain properties, and for general corporate purposes.

We currently have $19.16 million outstanding under our term loans and $13.40 million outstanding under our debentures.

On May 10, 2013, the Company entered into a one-year, non-exclusive investment banking agreement with TR Winston. The agreement provides for initial compensation to TR Winston in the amount of 100,000 common shares, and 250,000 common stock purchase warrants. In addition, the Company has agreed to issue an additional 650,000 common stock purchase warrants to TR Winston in the event the Company’s stockholders approve the expansion of the Company’s 2012 Equity Incentive Plan. All warrants will have a term of three years and a strike price of $4.25 per share. The investment banking agreement also provides for additional commissions and compensation in the event that TR Winston arranges a successful equity or debt financing during the term of the agreement.

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, 2012, as well as the unaudited condensed consolidated financial statements and notes thereto included in this Quarterly Report on Form 10-Q.

General

Recovery Energy, Inc. (“Recovery,” “Recovery Energy,” “we,” “our,” and the “Company”) 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-Julesberg (“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

Since our inception, we have incurred a cumulative net loss of approximately $108.66 million. As of March 31, 2013, we have negative working capital of $1.26 million and current liabilities of $3.20 million.

Information about our financial position is presented in the following table:

	March 31, 2013			December 31, 2012
Financial Position Summary
Cash and cash equivalents	$	477,056		$	970,035
Working capital	$	(1,261,329	)	$	(1,041,491	)
Balance outstanding on term loans and convertible debentures	$	32,558,940		$	32,736,341
Shareholders’ equity	$	10,155,551		$	12,082,212

During the three months ended March 31, 2013, our working capital decreased to negative $1.26 million compared to negative working capital of $1.04 million at December 31, 2012. This lower level of working capital is primarily the result of cash used in operations and investing activities that exceeded cash provided by financing activities. In view of the maturity of our secured indebtedness in 2014, we will be required to complete one or more capital-raising transactions, such as a sale of assets, an offering of our securities, or a refinancing transaction with terms more favorable to us, before our secured debt matures. If we default under our secured debt, our lenders will be entitled to exercise their rights to foreclose on the properties held as security for the term loans and the debentures, and may be entitled to collect any amounts remaining under the loans and debentures that is not satisfied through sale of such properties.

The majority of our leases on which we have identified reserves and production are subject to security interests held by the lenders under our secured term loans or our 8% Senior Secured Convertible Debentures (the “Debentures”). As discussed below, we have recently amended the terms of both the secured term loans and the Debentures to, among other things, extend the maturity dates under both the term loans and the Debentures, and reduce the interest rate and the level of minimum monthly payments under the term loans. We currently have $19.16 million outstanding under the term loans and $13.40 million outstanding under the Debentures. In addition, we currently have a working capital deficit of approximately $1.26 million, and approximately $3.20 million in current liabilities. As discussed below, we amended our secured term loans and Debentures in April 2013 to extend their maturity dates to May 16, 2014 and, with respect to the term loans, reduce the interest rate and the minimum monthly payment, among other things. We believe that these amendments provide us with significantly more flexibility in meeting our obligations. In the immediate term, the Company expects that additional capital will be required to fund its capital budget for 2013, to help fund its ongoing overhead, provide for payment of minimum interest and principal payments required by term notes, and provide additional capital to generally improve its working capital position. In addition, as discussed below, we have entered into an agreement with one of our existing debenture holders to invest at least $1.5 million in additional Debentures on substantially the same terms as our existing Debentures, with the possibility of an additional investment by our existing Debenture holders of up to $3.5 million. We are aggressively exploring a number of other capital raising transactions aimed at improving our liquidity position in the long and short term, including asset sales, joint ventures and similar industry partnerships, asset monetization transactions, possible equity transactions, and other potential refinancing transactions with terms more favorable to us than those under the term loans and debentures. Our ability to fund some of our ongoing overhead, to meet our minimum principal and interest obligations and to fund our 2013 capital program is contingent on successfully raising additional capital via one or more of the above described transactions.

On a longer term basis, the Company will require capital to retire our term notes and our Debentures when such debts mature in May 2014.

Pursuant to our credit agreements with Hexagon relating to the term notes, a substantial portion of our monthly net revenues derived from our producing properties is required to be used for debt and interest payments. In addition, our debt instruments contain provisions that, absent consent of Hexagon, may restrict our ability to raise additional capital.

Cash Flows

Cash used in operating activities during the three months ended Mach 31, 2013 was $0.90 million. This use of cash, coupled with the cash provided by investing activities, exceeded cash (used in) provided by financing activities by $0.49 million, and resulted in a corresponding decrease in cash. This net use of cash contributed to a $0.22 million decrease in working capital as of March 31, 2013, compared to working capital as of December 31, 2012.

The following table compares cash flow items during the three months ended March 31, 2013 to March 31, 2012:

	Three Months Ended March 31,
	2013				2012
Cash provided by (used in):
Operating activities		$	(903,700	)		$	(2,377,397	)
Investing activities			588,096				657,994
Financing activities			(177,375	)			180,168
Net change in cash		$	(492,979	)		$	(1,539,235	)

During the three months ended March 31, 2013, net cash used in operating activities was $0.90 million, compared to $2.38 million during the three months ended March 31, 2012, a decrease of $1.48 million or 62%. The primary changes in operating cash during the three months ended March 31, 2013 were $2.45 million of net loss, adjusted for non-cash charges of $0.69 million of depreciation, depletion, amortization and accretion expenses, $0.56 million of debt discount, $0.45 million of amortization of deferred financing costs and issuance of stock for convertible debentures interest, $0.25 million for issuance of stock for services and compensation, and a non-cash change in fair value of convertible debentures conversion option of $0.02 million, which was offset by $0.58 million of cash used for accounts payable and other accrued expenses and $0.29 million for cash used for other assets.

During the three months ended March 31, 2013, net cash provided by investing activities was $0.59 million, compared to net cash provided by investing activity of $0.66 million during the three months ended March 31, 2012, a decrease of $.07 million or 11%. The primary changes in investing cash during the three months ended March 31, 2013 were an increase in cash of $0.64 million related to our sale of developed properties which was offset by a decrease in cash of $0.02 additions to office equipment, $0.02 million of drilling expenditures, and $0.07 of acquisition of undeveloped acreage.

During the three months ended March 31, 2013, net cash used in financing activities was $0.18 million, compared to net cash provided by financing activities of $0.18 million during the three months ended March 31, 2012, a decrease of $0.36 million, or 200%. The changes in financing cash during the three months ended March 31, 2013 were primarily due to net repayments of debt of $0.18 million.

As of March 31, 2013 our balances outstanding on term loans and convertible debentures was $32.56 million, compared to $32.74 million as of December 31, 2012. The primary changes in the balances outstanding relate to principal payments of $0.18 million on our secured debts.

Under the terms of our term loan agreements, we are prohibited from incurring any additional debt from third parties without prior consent from Hexagon. Our ability to obtain additional working capital through bank lines of credit and project financing would likely be subject to the repayment of the approximately $19.16 million debt related to our primary credit facility. Consequently, there can be no assurance we will be able to obtain continued access to capital as and when needed or, if so, that the terms of any available financing will be subject to commercially reasonable terms. If we are unable to access additional capital in significant amounts as needed, we may not be able to develop our current prospects and properties, may have to forfeit our interest in certain prospects and may not otherwise be able to develop our business. In such an event, among other things, our stock price will be materially adversely affected.

Notable Financing Transactions

In February 2013, we completed the sale of certain developed properties, in which we agreed to sell all of our interest and an override royalty interest, for $0.64 million.

As discussed below, in April 2013 we amended both our Debentures, including the Supplemental Debentures, and our secured term loans.

Term Loans

We entered into three separate loan agreements with Hexagon in January, March and April 2010. The loans contain cross collateralization and cross default provisions and are collateralized by mortgages against a portion of our 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 interest rate to 10% from 15% beginning retroactively with March 2013, decrease our minimum payment under the term loans to $0.23 or $0.19, depending on our ability to complete the sale of certain of our assets by July 1, 2013, and require us to pay interest only for March, April, May, and June. In consideration for the extended maturity date, reduced interest rate, and reduced minimum loan payment, we are required to provide them an additional security interest in 15,000 acres of our undeveloped acreage (see Note 12).

We are subject to certain non-financial covenants with respect to the Hexagon loan agreements. As of March 31, 2013, we were in compliance with all covenants under the facilities.

As of March 31, 2013, the total amount outstanding on the three loan agreements is $19.16 million, of which $.64 million is classified as current.

For additional information regarding our secured term loans, see “Note 8 – Loan Agreements” in Item 1.

Convertible Debentures Payable

In February 2011, we completed a private placement of $8.40 million aggregate principal amount of Debentures, secured by mortgages on several of our properties.

On March 19, 2012, we entered into agreements with some of our existing Debenture holders to issue up to an additional $5.0 million in additional Debentures (the “Supplemental Debentures”).

During the three months ended March 31, 2013 and 2012, the Company amortized $0.56 million and $0.43 million, respectively, of debt discounts.

In April 2013, the holders of our Debentures agreed to extend their maturity date to May 16, 2014. In consideration for the extended maturity date the Company is required to provide them an additional security interest in 15,000 acres of our undeveloped acreage (see Note 12).

On April 16, 2013, the Company entered into an agreement with one of its existing Debenture holders to issue up to an additional $5.0 million in additional debentures with substantially the same terms to the existing 8% Secured Convertible Debentures. Under the terms of this agreement, the holder has agreed to purchase up to $1.5 million of additional debentures on or before July 16, 2013. The funds associated with the initial issuance of debentures will be used by the Company for the drilling and development of certain properties, and for general corporate purposes (see Note 12).

For additional information regarding the Debentures, see “Note 8 – Loan Agreements” in Item 1.

Interest Expense

Capital Resources

Our 2013 capital program is subject to securing sufficient capital, principally via the issuance of additional equity and debt both to fund our capital program and to refinance the Hexagon loans and Debentures which are due on May 16, 2014. We are aggressively exploring a number of capital raising transactions aimed at improving our liquidity position in the long and short term, including asset sales, joint ventures and similar industry partnerships, asset monetization transactions, possible equity transactions, and other potential refinancing transactions with terms more favorable to us than those under the term loans and debentures.

Currently, the majority of our cash flows from operations are applied to the payment of principal and interest of our loans. Due to the Company’s continuing operating losses and the large amounts of capital expenditures, during 2013 and 2012, our liquidity and working capital have deteriorated. We will seek additional capital to refinance our debts, partially fund our operations, and fund our 2013 capital budget. We will also require substantial additional capital in order to fully test, develop and evaluate our 127,000 net undeveloped acres. We expect to obtain this capital through a variety of sources, including, but not limited to, future debt and equity financings and potentially from future joint venture partners. Unless we are successful in competing a substantial debt and/or equity financing or other similar transaction in the near term, we may be required to sell certain assets in order to meet obligations as they arise. We cannot provide assurance that we will secure a major financing, nor can we predict the terms of any future potential financing transactions.

We cannot give assurances that our working capital on hand, our cash flow from operations or any available borrowings, equity offerings or other financings, or asset sales will be sufficient to fund our operations or our anticipated 2013 capital expenditures.

Results of Operations

Three months ended March 31, 2013 compared to three months ended March 31, 2012

The following table compares operating data for the three months ended March 31, 2013 to March 31, 2012:

	2013			2012
Revenue
Oil sales	$	1,127,333		$	1,547,763
Gas sales		106,397			129,676
Operating fees		48,503			43,833
Realized gains (loss) on commodity price derivatives		19,890			(60,912	)
Unrealized loss on commodity price derivatives		-			(104,391	)
Total revenue		1,302,123			1,555,969

Costs and expenses
Production costs		303,847			367,526
Production taxes		115,994			192,858
General and administrative		984,259			2,022,263
Depreciation, depletion and amortization		689,654			984,090
Impairment of developed properties		-			3,274,718
Total costs and expenses		2,093,754			6,841,455

Loss from operations		(791,631	)		(5,285,486	)

Other income		251			417
Convertible notes conversion derivative gain (loss)		(20,000	)		290,164
Interest expense		(1,636,159	)		(2,132,906	)

Net Loss	$	(2,447,539	)	$	(7,127,811	)

Total revenues

Total revenues were $1.30 million for the three months ended March 31, 2013, compared to $1.56 million for the three months ended December 31, 2012, a decrease of $0.26 million, or 17%. The decrease in revenues was due primarily to a decrease in production volumes. During March 2013 and 2012, production amounts were 18,215 and 24,227 BOE, respectively, a decrease of 6,012 BOE, or 25%. The revenue decrease was enhanced by a decrease in overall average price per BOE to $67.73 in 2013 from $69.24 in 2012, a decrease of $1.51 or 2%. The decrease in production and price was offset by an increase in realized gains on commodity derivatives of $0.08 million and an increase in unrealized gain (loss) on commodity price derivatives of $0.10 million for a total increase of $0.18 million or 12% of total revenue. Additionally, in 2013 we had increases in operating fees.

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

	For the Three Months Ended March 31,
	2013				2012
Product
Oil (Bbl.)			13,458				16,127
Oil (Bbls)-average price (1)		$	83.77			$	95.97

Natural Gas (MCF)-volume			23,350				18,986
Natural Gas Liquids (NGL) – BOE			865				4,936
Natural Gas (MCF)-average price (2)		$	4.39			$	5.42

Barrels of oil equivalent (BOE)			18,215				24,227
Average daily net production (BOE)			202				269
Average Price per BOE (1)			67.73			$	69.24

(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)		$	67.73			$	69.24

Production costs per BOE			16.68				15.17
Production taxes per BOE			6.37				7.96
Depreciation, depletion, and amortization per BOE			37.86				40.62
Total operating costs per BOE		$	60.91			$	63.75

Gross margin per BOE		$	6.82			$	5.49

Gross margin percentage			10.07	%			7.93	%

(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.

Commodity price derivative net realized gain was $0.02 million during the three months ended March 31, 2013, as compared to a realized loss of $0.06 million for the three months ended March 31, 2012, for an increase in realized gain of $0.08 million, or 133%. We also recorded no unrealized gain on commodity price derivatives for the three months ended March 31, 2013 compared to a loss of $0.10 million during the three months ended March 31, 2012, for an increase of $0.10 million, or 100%. The Company had no commodity price derivatives at March 31, 2013.

Production costs

Production costs were $0.30 million during the three months ended March 31, 2013, compared to $0.37 million for the three months ended March 31, 2012, a decrease of $0.07 million, or 19%. Decrease in production costs in 2013 was from a decrease of the number of work overs, property improvements, and onsite work on productive wells. Production costs per BOE increased to $16.68 for the three months ended March 31, 2013 from $15.17 in 2012, an increase of $1.51 per BOE, or 10%.

Production taxes

Production taxes were $0.12 million for the three months ended March 31, 2013, compared to $0.19 million for the three months ended March 31, 2012, a decrease of $0.05 million, or 26%. 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 10% based on the state and county which production is derived. Production taxes per BOE decreased to $6.37 during the three months ended March 31, 2013 from $7.96 in 2012, a decrease of $1.59 or 20%.

General and administrative

General and administrative expenses were $0.98 million during the three months ended March 31, 2013, compared to $2.02 million during the year ended March 31, 2012, a decrease of $1.04 million, or 51%. Non-cash general and administrative items for the three months ended March 31, 2013 were $0.36 million compared to $0.67 million during the three months ending March 31, 2012, a decrease of $0.31 million, or 46%. The decrease in non-cash general and administrative expenses was due to a decrease in non-cash consulting expense of $0.28 million and a decrease in non-cash compensation of $0.03 million. Cash general and administrative expense was $0.62 million during the three months ended March 31, 2013, compared to $1.35 million during the three months ended March 31, 2013, a decrease of $0.73 million, or 54%. The decrease in cash general and administrative expenses was a result of a reduction of employees and a decrease in professional service expenses.

The separation agreement with Mr. Parker, in November 2012, provided that Mr. Parker receive severance payments consisting of one year’s salary and health benefits for the year. In return, the Company received a general release and certain non-compete terms from Mr. Parker, and also entitled to receive no less than 10 hours per week of Mr. Parker’s time as a consultant to the Company. As of March 31, 2013, the Company owes Mr. Parker $0.18 million in severance salary and health insurance. The Company expensed the entire severance amount of $0.29 million during the year ended December 31, 2102.

Depreciation, depletion, and amortization

Depreciation, depletion, and amortization were $0.69 million during the three months ended March 31, 2013, compared to $0.98 million during the three months ended March 31, 2012, a decrease of $0.29 million, or 30%. Decrease in depreciation, depletion, and amortization was from (i) a decrease in production amounts in 2013 from 2012, (ii) a decrease in the depletion base for the depletion calculation, offset by (iii) an increase in the depletion rate. Production amounts decreased to 18,215 from 24,227 for the three months ended March 31, 2013 and 2012, respectively, a decrease of 6,012, or 25%. The decrease in depletion was based on a lower depletion base. The decrease in production and the oil and gas asset depletion base was offset by an increase in depletion rate of 4.20% during the three months ended March 31, 2013 compared to 2.91% for 2012, an increase of 1.29% or a change of 44%. Depreciation, depletion, and amortization per BOE decreased to $37.86 from $40.62, respectively, for the three months ended March 31, 2013 and 2012, a decrease of $2.76, or 7%.

Impairment of developed properties

There was no impairment of developed properties during the three months ended March 31, 2013, compared to $3.27 million during the three months ended March 31, 2012.

Interest Expense

Off-Balance Sheet Arrangements

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

2013 Capital Budget

Our entire 2013 Capital Budget is subject to financing. If adequate financing is obtained, our 2013 Capital Budget is Our entire 2013 capital budget is subject to financing availability. If adequate financing is obtained, our 2013 capital budget is currently projected to be approximately $15 million. We anticipate that approximately 50% of this budget will be allocated toward the development of two of our unconventional prospects located in the Wattenberg Field within the DJ Basin that will target horizontal drilling and development of the Niobrara shale and Codell formations. The remainder of our 2013 budget is anticipated to be directed principally toward the conventional development of certain lower risk offset wells to existing production. We also anticipate the allocation of approximately 10% of our 2013 capital budget toward higher risk exploration activities, including the procurement of seismic data and the drilling of one conventional exploratory well.

Our 2013 capital expenditure budget is also subject to various additional factors, including market conditions, availability of capital, oilfield services and equipment availability, commodity prices and drilling results. Results from the wells identified in the capital budget may lead to additional adjustments to the capital budget as the cash flow from the wells could provide additional capital which we may use to increase our capital budget. We do not anticipate any significant expansion of our current acreage position.

Other factors that could cause us to increase our level of activity and adjust our capital expenditure budget include a reduction in service and material costs, the formation of joint ventures with other exploration and production companies, the divestiture of non-strategic assets, a further improvement in commodity prices or well performance that exceeds our forecasts, any of which could positively impact our operating cash flow. Factors that could cause us to reduce level of activity and adjust our capital budget include, but are not limited to, increases in service and materials costs, reductions in commodity prices or under-performance of wells relative to our forecasts, any of which could negatively impact our operating cash flow.

Plan of Operations

Our plan of operations is to identify and develop oil and natural gas prospects from our existing inventory of undeveloped acreage. Subject to the securing of adequate financing, we anticipate the investment of substantial capital during the next few years to evaluate, assess and develop this inventory. Currently, our inventory of developed and undeveloped acreage includes approximately 21,800 net acres that are held by production, approximately 12,900 net acres that expire in 2013, and approximately 25,000 net acres, 59,000 net acres and 10,300 net acres that expire in the years 2014, 2015 and thereafter, respectively. Approximately 64% 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.

The business of oil and natural gas acquisition, exploration and development is capital intensive and the level of operations attainable by an 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. As explained under “Financial Condition and Liquidity”, based on our present working capital and current rate of cash flow from operations, we will need to raise additional capital to partially fund our overhead, and fund our exploration and development budget. We will seek additional capital through the sale of our securities, through debt and project financing, and through sale of assets. However, under the terms of our term loan agreements and debentures, we are prohibited from incurring any additional debt from third parties or selling any properties held as collateral under the term loans or debentures without prior consent from the lenders. Thus our ability to obtain additional capital through new debt instruments, project financing and sale of assets may be subject to the repayment of our term loans and/or our debentures.

We intend to use the services of independent consultants and contractors to perform various professional services, including land, legal, environmental, investor relations and tax services. We believe that by limiting our management and employee costs, we may be able to better control total costs and retain flexibility in terms of project management.

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
●	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, 2013 (in thousands):

	Payments due by period
Contractual obligations	Total		Within 1 year		1-3 years		4-5 years		More than 5 years
Secured debt	$	19,158	$	641	$	18,517	$	-	$	-
Interest on secured debt		2,154		1,915		239		-		-
Convertible debentures		13,400		-		13,400		-		-

Separation agreement with Roger Parker (2)		181		181		-		-		-
Interest on convertible debentures		1,206		1,072		134		-		-
Operating leases		67		67		-		-		-
Total contractual cash obligations (1)	$	36,166	$	3,876	$	32,290	$	-	$	-

(1)

We could be liable for liquidated damages under registration rights agreements covering approximately 3.2 million shares of our common stock if we fail to maintain the effectiveness of a prior registration statement as required in the agreements. In such case, we would be required to pay monthly liquidated damages of up to $228,050. The maximum aggregate liquidated damages are capped at $1,368,300.

(2)	Includes $160,500 salary, $10,672 employer taxes, $10,128 health, dental, and vision insurance, in accordance with Mr. Parker’s separation agreement dated November 15, 2012.

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 the 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 March 31, 2013, using the average, first-day-of-the-month price during the 12-month period ending March 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 March 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, their historical performance, 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 restricted stock grants, on the date of grant. 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 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

Our management, with the participation of our Chief Executive Officer and our Chief Financial Officer, evaluated the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of March 31, 2013, the end of the period covered by this report. Based on this evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that, as of March 31, 2013, our disclosure controls and procedures were effective to ensure that information required to be disclosed by us in reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified by the rules and forms of the SEC, and that information required to be disclosed by us in such reports is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.

Changes in Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting during the quarter-ended March 31, 2013 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II - OTHER INFORMATION

Item 1. Legal Proceedings.

Item 1A. Risk Factors.

There have been no material changes in our Risk Factors from those reported in Item 1A of Part I of our 2012 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.

None.

Item 3. Defaults Upon Senior Securities.

None.

Item 4. Mine Safety Disclosures.

Not Applicable

Item 5. Other Information.

On May 10, 2013, the Company entered into a one-year, non-exclusive investment banking agreement with T.R Winston. The agreement provides for initial compensation to TR Winston in the amount of 100,000 common shares, and 250,000 common stock purchase warrants. In addition, the Company has agreed to issue an additional 650,000 common stock purchase warrants to TR Winston in the event the Company’s stockholders approve the expansion of the Company’s 2012 Equity Incentive Plan. All warrants will have a term of three years and a strike price of $4.25 per share. The investment banking agreement also provides for additional commissions and compensation in the event that TR Winston arranges a successful equity or debt financing during the term of the agreement.

Item 6. Exhibits

Exhibit Number		Exhibit Description
31.1		Certification of the Chief Executive Officer pursuant to Section 302 of the Sarbanes Oxley Act of 2002
31.2		Certification of the 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 Chief Financial Officer pursuant to Section 906 of the Sarbanes Oxley Act of 2002

SIGNATURES

Pursuant to the requirements of the Securities and Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and the capacities and on the dates indicated.

Signature	Title	Date

/s/ W. Phillip Marcum	Chief Executive Officer and Chairman of the Board of Directors	May 14, 2013
W. Phillip Marcum	(Principal Executive Officer)

/s/ A. Bradley Gabbard	President, Chief Financial and Accounting Officer, Director	May 14, 2013
A. Bradley Gabbard	(Principal Financial Officer)

/s/ Eric Ulwelling	Principal Accounting Officer	May 14, 2013
Eric Ulwelling

/s/ Timothy N. Poster	Director	May 14, 2013
Timothy N. Poster

/s/ D. Kirk Edwards	Director	May 14, 2013
D. Kirk Edwards

/s/ Bruce B. White		Director		May 14, 2013
Bruce B. White

EXHIBIT INDEX

Exhibit Number		Exhibit Description
31.1		Certification of the Chief Executive Officer pursuant to Section 302 of the Sarbanes Oxley Act of 2002
31.2		Certification of the 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 Chief Financial Officer pursuant to Section 906 of the Sarbanes Oxley Act of 2002

LILIS ENERGY, INC. - FORM 10-Q - May 14, 2013

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LILIS ENERGY, INC. Reports