LILIS ENERGY, INC. - FORM 10-Q/A

Attached files

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EXCEL - IDEA: XBRL DOCUMENT - LILIS ENERGY, INC.	Financial_Report.xls
EX-32.2 - CERTIFICATION - LILIS ENERGY, INC.	f10q0913a1ex32ii_lilisenergy.htm
EX-32.1 - CERTIFICATION - LILIS ENERGY, INC.	f10q0913a1ex32i_lilisenergy.htm
EX-31.1 - CERTIFICATION - LILIS ENERGY, INC.	f10q0913a1ex31i_lilisenergy.htm
EX-31.2 - CERTIFICATION - LILIS ENERGY, INC.	f10q0913a1ex31ii_lilisenergy.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q/A

Amendment No. 1

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

For the quarterly period ended September 30, 2013

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

For the transition period from ______to______.

	001-35330
	(Commission File No.)

LILIS ENERGY, INC.

(Exact name of registrant as specified in Charter)

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

216 16th Street, Suite #1350

Denver, CO 80202

(Address of Principal Executive Offices)

(303) 951-7920

(Registrant’s telephone number, including area code)

Recovery Energy, Inc.

1900 Grant Street, Suite #720

Denver, CO 80203

(Former name, former address and former fiscal year,
if changed since last report)

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 ☐ No ☒

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

Yes ☒ No ☐

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 ☐

Accelerated Filer ☐

Non-Accelerated Filer ☐

Smaller Reporting Company ☒

Indicate by check mark whether the registrant is a shell company as defined in Rule 12b-2 of the Exchange Act.

Yes ☐ No ☒

State the number of shares outstanding of each of the registrant’s classes of common equity, as of November 8, 2013: 19,477,337 shares of Common Stock.

Lilis Energy, Inc.
(formerly Recovery Energy, Inc.)

INDEX

EXPLANATORY NOTE

FORWARD-LOOKING STATEMENTS

PART I– FINANCIAL INFORMATION

Item 1.	Financial Statements

	Balance Sheets as of September 30, 2013 and December 31, 2012 (Restated) (Unaudited)	1
	Statements of Operations for the Three and Nine Months Ended September 30, 2013 (Restated) and 2012 (Unaudited)	2
	Statements of Cash Flows for the Nine Months Ended September 30, 2013 (Restated) and 2012 (Unaudited)	3
	Notes to Consolidated Financial Statements	5

Item 2.	Management’s Discussion and Analysis of Financial Condition	15

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	28

Item 4.	Control and Procedures	29

PART II– OTHER INFORMATION

Item 1.	Legal Proceedings	31
Item 1A.	Risk Factors	31
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	31
Item 3.	Defaults Upon Senior Securities	31
Item 4.	Mine Safety Disclosures	31
Item 5.	Other Information	31
Item 6.	Exhibits	31

SIGNATURES		32

EXHIBIT INDEX		33

EXPLANATORY NOTE

Lilis Energy, Inc. (“Lilis”, “Lilis Energy”, “we”, “our”, and the “Company”) is filing this Amendment No. 1 on Form 10-Q/A (the “Amended Report”) to the Quarterly Report on Form 10-Q of Lilis Energy for the quarterly period ended September 30, 2013 (the “Original Report”), originally filed with the Securities and Exchange Commission on November 14, 2013. The purpose of the Amended Report is to correct certain errors related to the valuation of the Company’s convertible debenture conversion derivative liability contained in the financial statements and related disclosures contained in the Original Report, as described in Note 1 – Restatement.

In February 2015, the Company discovered an error in the valuation provided by its third-party valuation expert regarding the conversion derivative liability of the Company’s 8% Senior Secured Convertible Debentures (the “Debentures”) for the periods ended December 31, 2011, December 31, 2012, December 31, 2013, as well as March 31, 2014 and June 30, 2014 (together, the “Relevant Periods”). Specifically, the calculation of the conversion liability included in the Company’s financial statements for the Relevant Periods only included the value of the price protection (anti-dilution) feature, when it should have included both the conversion option and the price protection embedded in the Debentures. The changes in the value of the derivative resulted in non-cash charges to the financial statements.

The Company has evaluated the effect of the error on all Relevant Periods in accordance with Staff Accounting Bulletin (“SAB”) 99 and SAB 108 and determined that the impact of the error on its annual financial statements for the fiscal years ended December 31, 2011, December 31, 2012, and December 31, 2013 was not material. However, the Company has determined that the impact of these non-cash items in its quarterly financial statements for the fiscal quarters ended September 30, 2013, March 31, 2014 and June 30, 2014 was sufficiently material to warrant restatement of the Company’s Quarterly Reports on Form 10-Q for those periods. In addition, the Company will correct the amounts related to the error for the fiscal years ended December 31, 2011, December 31, 2012, and December 31, 2013 in its Annual Report on Form 10-K for the fiscal year ended December 31, 2014. The Company has also corrected the error in the fiscal year ended December 31, 2012 in this Quarterly Report on Form 10-Q/A.

The line items that have been amended and restated, including corrections to the error for the fiscal year ended December 31, 2012, are set forth below:

Balance Sheets

	September 30, 2013									December 31, 2012
	As Previously Reported			Adjustment			As Restated			As Previously Reported			Adjustment			As Restated
Convertible notes payable, net of debt discount		13,128,936			313,966			13,442,902			10,300,361			286,818			10,587,179
Convertible notes conversion derivative liability		1,150,000			(503,740	)		646,260			1,680,000			(985,664	)		694,336
Total liabilities		36,771,218			(189,774	)		36,581,444			35,470,827			(698,846	)		34,771,981
Accumulated deficit		(113,411,189	)		189,774			(113,221,415	)		(106,216,305	)		698,846			(105,517,459	)
Total shareholders' equity	$	7,426,874		$	189,774		$	7,616,648			12,082,213			698,846			12,781,059

Statements of Operations

	For the Three Months Ended September 30, 2013
	As Previously Reported			Adjustment			As Restated

Convertible notes conversion derivative gain (loss)		700,000			(907,251	)		(207,251	)
Interest expense		(1,485,022	)		(97,859	)		(1,582,881	)
Net loss		(1,901,146	)		(1,005,108	)		(2,906,254
Net loss per common share (basic and diluted)	$	(0.10	)	$	(0.05	)	$	(0.15	)

	For the Nine Months Ended September 30, 2013
	As Previously Reported			Adjustment			As Restated

Convertible notes conversion derivative gain (loss)		670,000			(576,149	)		93,851
Interest expense		(4,790,700	)		67,076			(4,723,624	)
Net loss		(7,194,884	)		(509,072	)		(7,703,956	)
Net loss per common share (basic and diluted)	$	(0.40	)	$	(0.01	)	$	(0.41	)

Statements of Cash Flows

	Nine months ended
	September 30, 2013
	As Previously Reported			Adjustment			As Restated

Cash flows from operating activities:
Net loss	$	(7,194,884	)	$	(509,072	)	$	(7,703,956	)
Change in fair value of convertible notes conversion derivative		(670,000	)		576,149			(93,851	)
Accretion of debt discount		1,809,175			(67,076	)	$	1,742,099
Net cash used in operating activities	$	(1,558,306	)	$	-		$	(1,558,306	)

No attempt has been made in this Amended Report to modify or update other disclosures presented in the Original Report, except as required to reflect the effects of the restatement. Information not affected by the restatement, including references to the Company as “Recovery Energy, Inc.”, “Recovery”, or “Recovery Energy”, is unchanged and reflects the disclosures made at the time of the filing of the Original Report on November 14, 2013. Accordingly, this Amended Report should be read in conjunction with our filings made with the Securities and Exchange Commission subsequent to the filing of the Original Report, including any amendments to those filings.

As a result of the restatement described above, the Company’s Chief Executive Officer and Chief Financial Officer, with the assistance of other members of management, re-evaluated the effectiveness of the Company’s internal controls over financial reporting as of September 30, 2013 using the criteria in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission, or COSO. Based on this re-evaluation, we have determined that an additional material weakness in internal controls over financial reporting existed as of September 30, 2013. (See Item 4 – Controls and Procedures).

Currently dated certifications from Lilis Energy’s Chief Executive Officer and Chief Financial Officer have also been included as exhibits to this Form 10-Q/A.

iii

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;
●	exploration, exploitation and development results;
●	estimated quantities and quality of oil and natural gas reserves;
●	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 10-K and other SEC filings, available free of charge at the SEC’s website (www.sec.gov).

Item 1. Financial Statements

LILIS ENERGY, INC.
(FORMERLY RECOVERY ENERGY, INC.)

BALANCE SHEETS

(UNAUDITED)

	September 30,			December 31
	2013			2012
	(Restated)			(Restated)

Assets
Current assets:
Cash	$	353,934		$	970,035
Restricted cash		584,746			671,382
Accounts receivable (net of allowance of $50,000 at September 30, 2013 and December 31, 2012, respectively)		482,115			934,591
Prepaid assets		351,542			13,458
Total current assets		1,772,337			2,589,466

Oil and gas properties (full cost method), at cost:
Developed properties		58,223,296			58,610,095
Undeveloped acreage, excluded from amortization		28,258,138			28,067,005
Wells in progress, excluded from amortization		180,153			193,515
Total oil and gas properties, at cost		86,661,587			86,870,615

Less accumulated depreciation, depletion, amortization, and impairment		(44,989,495	)		(43,187,962	)
Total oil and gas properties, net		41,672,092			43,682,653

Other assets:
Office equipment, net		95,006			90,630
Deferred financing costs, net		443,116			974,856
Restricted cash and deposits		215,541			215,435
Total other assets		753,663			1,280,921
Total assets	$	44,198,092		$	47,553,040

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

LILIS ENERGY, INC.
(FORMERLY RECOVERY ENERGY, INC.)

BALANCE SHEETS

(UNAUDITED)

	September 30,			December 31,
	2013			2012
	(Restated)			(Restated)

Liabilities and Shareholders' Equity
Current liabilities: (restated)
Accounts payable	$	771,275		$	1,831,590
Commodity price derivative liability		40,955			-
Accrued expenses		1,684,030			1,411,016
Short term loans payable		18,967,191			388,351
Convertible notes payable, net of discount (restated)		13,442,902			-
Convertible notes conversion derivative liability (restated)		646,260			-
Total current liabilities (restated)		35,552,613			3,630,957

Long term liabilities:
Asset retirement obligation		1,028,831			911,546
Term loans payable		-			18,947,963
Convertible notes payable, net of discount (restated)		-			10,587,179
Convertible notes conversion derivative liability (restated)		-			694,336
Total long-term liabilities (restated)		1,028,831			31,141,024

Total liabilities (restated)		36,581,444			34,771,981

Commitments and contingencies – Notes 3, 9 and 10

Shareholders’ equity:
Preferred stock, 10,000,000 authorized, none issued and outstanding		-			-
Common stock, $0.0001 par value:100,000,000 shares authorized; 19,477,337 and 18,394,401 shares issued and outstanding as of September 30, 2013 and December 31, 2012, respectively		1,948			1,839
Additional paid in capital		120,836,115			118,296,679
Accumulated deficit (restated)		(113,221,415	)		(105,517,459	)
Total shareholders' equity (restated)		7,616,648			12,781,059
Total liabilities and shareholders’ equity	$	44,198,092		$	47,553,040

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

LILIS ENERGY, INC.
(FORMERLY RECOVERY ENERGY, INC.)

STATEMENTS OF OPERATIONS

(UNAUDITED)

	Three months ended September 30,						Nine months ended September 30,
	2013			2012			2013			2012
	(Restated)						(Restated)
Revenues
Oil sales	$	1,003,745		$	1,775,383		$	3,320,083		$	4,685,713
Gas sales		82,651			168,897			227,853			397,298
Operating fees		28,331			42,853			118,853			132,362
Realized gain (loss) on commodity price derivatives		(43,551	)		37,341			(23,661	)		49,729
Unrealized gain (loss) on commodity price derivatives		(20,000	)		(130,000	)		(20,000	)		445,609
Total revenues		1,051,176			1,894,474			3,623,128			5,710,711

Costs and expenses
Production costs		318,322			397,793			877,623			1,033,635
Production taxes		102,919			198,781			380,958			561,278
General and administrative		1,207,123			1,515,868			3,559,358			5,099,932
Depreciation, depletion and amortization		539,079			1,069,068			1,879,908			2,897,156
Impairment of evaluated properties		-			-			-			3,274,718
Total costs and expenses		2,167,443			3,181,510			6,697,847			12,866,719

Loss from operations		(1,116,267	)		(1,287,036	)		(3,074,719	)		(7,156,008	)

Other income (expense)		145			333			536			(372	)
Convertible notes conversion derivative gain (loss) (restated)		(207,251)			600,000			93,851			700,000
Interest expense (restated)		(1,582,881	)		(2,149,931	)		(4,723,624	)		(6,320,919	)

Net loss (restated)	$	(2,906,254	)	$	(2,836,634	)	$	(7,703,956	)	$	(12,777,299	)
Net loss per common share Basic and diluted (restated)	$	(0.15	)	$	(0.16	)	$	(0.41	)	$	(0.72	)
Weighted average shares outstanding: Basic and diluted		19,254,329			17,833,466			18,786,598			17,732,304

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

LILIS ENERGY, INC.
(FORMERLY RECOVERY ENERGY, INC.)

STATEMENTS OF CASH FLOWS

(UNAUDITED)

	Nine months ended September 30,
	2013			2012
	(Restated)

Cash flows from operating activities:
Net loss (restated)	$	(7,703,956	)	$	(12,777,299	)
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		830,660			686,934
Common stock for services and compensation		1,293,315			1,773,658
Changes in the fair value of commodity price derivatives		20,000			(445,609	)
Amortization of deferred financing costs		531,739			1,504,751
Change in fair value of convertible notes conversion derivative (restated)		(93,851)			(700,000	)
Accretion of debt discount (restated)		1,742,099			1,651,772
Depreciation, depletion, amortization and accretion of asset retirement obligation		1,873,002			2,897,156
Changes in operating assets and liabilities:
Accounts receivable		452,476			(433,567	)
Restricted cash		86,636			(17,453	)
Other assets		77,486			(21,294	)
Accounts payable and other accrued expenses		(667,912	)		(140,846	)
Net cash used in operating activities		(1,558,306	)		(2,747,079	)

Cash flows from investing activities:
Sale of oil and gas properties		640,000			1,443,852
Additions to oil and gas properties		(303,814	)		(436,023	)
Drilling capital expenditures		(429,678	)		(4,278,785	)
Other investing activities		(25,081	)		(3,112	)
Net cash used in investing activities		(118,573	)		(3,274,068	)

Cash flows from financing activities:

Proceeds from issuance of debt		1,429,902			5,000,000
Repayment of debt		(369,123	)		(988,299	)
Net cash provided by financing activities		1,060,779			4,011,701

Change in cash and cash equivalents		(616,100	)		(2,009,446	)
Cash and cash equivalents at beginning of period		970,035			2,707,722

Cash and cash equivalents at end of period	$	353,934		$	698,276

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

LILIS ENERGY, INC.
(FORMERLY RECOVERY ENERGY, INC.)

NOTES TO CONDENSED FINANCIAL STATEMENTS

AS OF SEPTEMBER 30, 2013

(UNAUDITED)

NOTE 1 – RESTATEMENT

In February 2015, in the course of transitioning between independent public accounting firms, the Company discovered an error in the valuation provided by its third-party valuation expert regarding the conversion derivative liability of the Company’s 8% Senior Secured Convertible Debentures (the “Debentures”) for the periods ended December 31, 2011, December 31, 2012, December 31, 2013, as well as March 31, 2014 and June 30, 2014 (together, the “Relevant Periods”). Specifically, the calculation of the conversion liability included in the Company’s financial statements for the Relevant Periods only included the value of the price protection (anti-dilution) feature, when it should have included both the conversion option and the price protection embedded in the Debentures. The changes in the value of the derivative resulted in non-cash charges to the financial statements.

The Company has evaluated the effect of the error on all Relevant Periods in accordance with Staff Accounting Bulletin (“SAB”) 99 and SAB 108 and determined that the impact of the error on its annual financial statements for the fiscal years ended December 31, 2011, December 31, 2012, and December 31, 2013 was not material. However, the Company has determined that the impact of these non-cash items in its quarterly financial statements for the fiscal quarters ended September 30, 2013, March 31, 2014 and June 30, 2014 was sufficiently material to warrant restatement of the Company’s Quarterly Reports on Form 10-Q for those periods. In addition, the Company will correct of the amounts related to the error for the fiscal years ended December 31, 2011, December 31, 2012, and December 31, 2013 in its Annual Report on Form 10-K for the fiscal year ended December 31, 2014. The Company has also corrected the error in the fiscal year ended December 31, 2012 in this Quarterly Report on Form 10-Q/A.

The line items that have been amended and restated, including corrections to the fiscal year ended December 31, 2012, are set forth below:

Balance Sheets

	September 30, 2013									December 31, 2012
	As Previously Reported			Adjustment			As Restated			As Previously Reported			Adjustment			As Restated
Convertible notes payable, net of debt discount		13,128,936			313,966			13,442,902			10,300,361			286,818			10,587,179
Convertible notes conversion derivative liability		1,150,000			(503,740	)		646,260			1,680,000			(985,664	)		694,336
Total liabilities		36,771,218			(189,774	)		36,581,444			35,470,827			(698,846	)		34,771,981
Accumulated deficit		(113,411,189	)		189,774			(113,221,415	)		(106,216,305	)		698,846			(105,517,459	)
Total shareholders' equity	$	7,426,874		$	189,774		$	7,616,648		$	12,082,213		$	698,846		$	12,781,059

Statements of Operations

	For the Three Months Ended September 30, 2013
	As Previously Reported			Adjustment			As Restated

Convertible notes conversion derivative gain (loss)		700,000			(907,251	)		(207,251	)
Interest expense		(1,485,022	)		(97,859	)		(1,582,881	)
Net loss		(1,901,146	)		(1,005,108	)		(2,906,254
Net loss per common share (basic and diluted)	$	(0.10	)	$	(0.05	)	$	(0.15	)

	For the Nine Months Ended September 30, 2013
	As Previously Reported			Adjustment			As Restated

Convertible notes conversion derivative gain (loss)		670,000			(576,149	)		93,851
Interest expense		(4,790,700	)		67,076			(4,723,624	)
Net loss		(7,194,884	)		(509,072	)		(7,703,956	)
Net loss per common share (basic and diluted)	$	(0.40	)	$	(0.01	)	$	(0.41	)

Statements of Cash Flows

	Nine months ended September 30, 2013
	As Previously Reported			Adjustment			As Restated
Cash flows from operating activities:
Net loss	$	(7,194,884	)	$	(509,072	)	$	(7,703,956	)
Change in fair value of convertible notes conversion derivative		(670,000	)		576,149			(93,851	)
Accretion of debt discount		1,809,175			(67,076	)	$	1,742,099
Net cash used in operating activities	$	(1,558,306	)	$	-		$	(1,558,306	)

NOTE 2 – ORGANIZATION

Recovery Energy, Inc. (“Recovery”, “Recovery Energy”, “we”, “our”, and the “Company”) is an independent oil and gas exploration and production company focused on the Denver-Julesburg Basin (“DJ Basin”) where it holds 112,000 net acres. Recovery drills for, operates and produces oil and natural gas through the Company’s land holdings located in Wyoming, Colorado, and Nebraska. On November 13, 2013, the shareholders of the company approved a change in the Company’s name to Lilis Energy, Inc.

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

NOTE 3 – LIQUIDITY

We currently have $18.97 million outstanding under our term loans with Hexagon, LLC (“Hexagon”) and $13.44 million, net, outstanding under our 8% Senior Secured Convertible Debentures. Both the term loans and the convertible debentures are considered current on our balance sheet and mature May 16, 2014.

We have a history of sustained losses and cash used by operating activities, including losses of $7.70 million for the nine months ended September 30, 2013, $1.58 million for the three months ended September 30, 2013, and $37.74 million for the year ended December 31, 2012, and cash used by operating activities of $1.56 million for the nine months ended September 30, 2013 and $2.75 million for the nine months ended September 30, 2012. In addition, as of September 30, 2013 we had a net working capital deficit of $33.78 million, which includes the current classification effect of both our term loans and our convertible debentures, all of which mature on May 16, 2014.

In order to continue as a going concern beyond May 16, 2014, the Company will need to secure refinancing of these debts, sell assets to repay these debts, or otherwise negotiate terms with Hexagon and holders of its convertible debentures to extend the maturity of such indebtedness. Principally as a result of the current maturity date of these debts, the Company currently does not have enough working capital to cover its current liabilities.

In addition to the above, the Company will require additional capital to fund its capital budget plans, to help fund its ongoing overhead, to provide for payment of minimum interest and principal payments required by term loans, and to provide additional capital to generally improve its working capital position.

In April 2013, we received approval from our existing secured debt and convertible debenture holders to issue up to $5.00 million of additional convertible debentures with terms substantially identical to our existing convertible debentures. As of November 8, 2013 we have issued $2.2 million of such convertible debt. Two officers of the Company participated in the additional convertible debentures for a combined total of $0.43 million. Proceeds from the issuance of this convertible debt have been used toward the development of certain specific properties, and to a lesser extent, general corporate purposes. The recent commitments were subject to certain yield enhancements, including a 25% carried interest in certain properties scheduled to be developed with the proceeds.

The Company may, but is not obligated to, seek completion of the remainder of the $5.00 million offering of additional debt that was approved in April 2013. However, there is no assurance that the Company will be successful in securing additional convertible debenture funding.

The Company will require additional funding for those purposes described above. We anticipate that such additional funding will be provided by a combination of capital raising activities, including the selling of additional debt and/or equity securities, the selling of certain assets and by the development of certain of 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 capital budget. There is no assurance that any such funding will be available to the Company.

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 for our term loans. In addition, our debt instruments contain provisions that, absent consent of Hexagon, may restrict our ability to raise additional capital.

NOTE 4 - 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 September 30, 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. 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 nine months ended September 30, 2013 compared to an impairment of $3.27 million for the nine months ended September 30, 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.

In June 2013, the Company purchased a 50% interest in approximately 1,200 contiguous gross acres in Laramie County, Wyoming, in an area considered strategic by the Company. This tract included two existing wells, one of which has now been recompleted. The costs associated with the purchase and recompletion was transferred out of wells in progress in September 2013. The Company transferred $0.30 million into undeveloped acreage and $0.43 million into oil and gas properties. As of September 30, 2013, the Company has $0.18 million in wells in progress compared to $0.19 million in wells in progress as of December 31, 2012.

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 September 30, 2013, a total of 6,648,913 and 3,489,389, 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 5 – OIL AND GAS PROPERTIES

In June 2013, the Company purchased a 50% working interest in a section in Laramie County, Wyoming for $0.60 million with an additional $0.13 million as additions to the well equipment and intangible equipment. The purchase was classified as $0.30 million into undeveloped acreage and $0.43 million into oil and gas properties.

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

NOTE 6 – WELLS IN PROGRESS

As of September 30, 2013, the Company has $0.18 million in wells in progress compared to $0.19 million included in wells in progress as of December 31, 2012.

NOTE 7 - 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 September 30, 2013, the Company maintained an active commodity swap for 100 barrels of oil per day through January 31, 2014 at a price of $99.25 per barrel.

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

	Three months ended						Nine months ended
	September 30,						September 30,
	2013			2012			2013			2012
Realized gains (losses) on commodity price derivatives	$	(43,551	)	$	37,341		$	(23,661	)	$	49,729
Unrealized gains (losses) on commodity price derivatives	$	(20,000	)	$	(130,000	)	$	(20,000	)	$	445,609

Realized gains and losses are recorded as individual swaps mature and settle. These gains and losses are recorded as income or expenses in the periods during which applicable contracts settle. Swaps which are unsettled as of a balance sheet date are carried at fair 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 8 - 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, respectively, 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. Through September 30, 2013, the Company issued an additional $1.43 million of supplemental convertible debentures. As of September 30, 2013, 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 liability.

The following table provides a summary of the fair values of assets and liabilities measured at fair value (in thousands), adjusted for the correction discussed in Note 1 - Restatement:

September 30, 2013

	Level 1		Level 2			Level 3			Total
Liability
Commodity price derivative liability	$	-	$	(41	)	$	-		$	(41	)
Convertible notes conversion derivative liability	$	-	$	-		$	(646	)	$	(646	)
Total liability, at fair value	$	-	$	(41	)	$	(646	)	$	(687	)

December 31, 2012

	Level 1		Level 2		Level 3			Total
Liability
Convertible notes conversion derivative liability	$	-	$	-	$	(694	)	$	(694	)
Total liability, at fair value	$	-	$	-	$	(694	)	$	(694	)

The following table provides a summary of changes in fair value of the Company’s Level 3 financial assets and liabilities as of September 30, 2013 (in thousands):

Beginning balance, December 31, 2012	$	(694	)
Convertible notes conversion derivative gain/ loss		94
Additions to derivative liability due to issuance of additional debentures		(46	)
Ending balance, September 30, 2013	$	(646	)

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 nine months ending September 30, 2013 or 2012.

NOTE 9 – 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.

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

The Company is subject to certain non-financial covenants with respect to the Hexagon loan agreements. As of September 30, 2013, the Company was in compliance with all covenants under the facilities.

As of September 30, 2013, the total amount outstanding on the three loan agreements is $18.97 million, all of which 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 interest accruable through the 18 month anniversary of the original issue date of the Debenture less the amount of any interest paid on the portion of the Debenture being redeemed prior to the optional redemption date, payable in common stock. 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 $0.08 million of deferred financing costs into interest expense during the nine months ended September 30, 2013, and has $0.06 million of deferred financing cost to be amortized through May 2014.

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

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

Through July 2012, we received $3.04 million of proceeds from the issuance of Supplemental Debentures, which were used for the drilling and development of six new wells, resulting in a total investment of $3.69 million. 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. In conjunction with commitments to additional Debentures in June 2013 (see below), the commitment to provide a 10% carried interest and a 15% one year net profits interest related to the development of four future properties was modified to a 15% carried interest in such properties.

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 September 30, 2013, the Supplemental Debentures. This valuation resulted in an estimated derivative liability as of September 30, 2013 and December 31, 2012 of $0.64 million and $0.69 million, respectively. The portion of the derivative liability that is associated with the August 2012 Supplemental Debentures, in the approximate amount of $0.01 million has been recorded as a debt discount, and is being amortized over the remaining life of the Supplemental Debentures.

During the nine months ended September 30, 2013 and 2012, the Company amortized $1.39 million and $1.70 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 and $0.10 million of deferred financing costs into interest expense during the three and nine months ended September 30, 2013, and has $0.08 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 provided an additional security interest in 15,000 acres of our undeveloped acreage, as additional collateral for the Debentures.

In April 2013, we received approval from our existing secured debt and convertible debenture holders to issue up to $5.00 million of additional convertible debentures with terms substantially identical to our existing convertible debentures. As of November 8, 2013 we have issued $2.20 million of such convertible debt, inclusive of $1.43 million that had been issued as of September 30, 2013. Two officers of the Company participated in the additional convertible debentures for a combined total of $0.43 million. Proceeds from the issuance of this convertible debt have been used toward the development of certain specific properties, and to a lesser extent, general corporate purposes. The recent commitments were subject to certain yield enhancements, including a 25% carried interest in certain properties scheduled to be developed with the proceeds.

The Company may, but is not obligated to, seek completion of the remainder of the $5.00 million offering of additional debt that was approved in April 2013.

As of September 30, 2013, all of the outstanding Convertible Debentures are classified as current liabilities as a result of the May 14, 2014 due date. The additional debentures have increased the debt discount by $0.15 million which is amortized over the life of the debt. As of September 30, 2013, the Company amortized $0.04 million.

As of September 30, 2013 and December 31, 2012, the convertible debt is recorded as follows:

	As of September 30, 2013			As of December 31, 2012
Convertible debentures	$	14,829,902		$	13,400,000
Debt discount		(1,387,000	)		(2,812,821	)
Total convertible debentures, net	$	13,442,902		$	10,587,179

Annual debt maturities as of September 30, 2013 are as follows:

Year 1	$	33,797,093
Thereafter		-
Total	$	33,797,093

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

NOTE 10 - COMMITMENTS AND CONTINGENCIES

Environmental and Governmental Regulation

At September 30, 2013, 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 September 30, 2013 the Company had not been fined or cited for any violations of governmental regulations that would have a material adverse effect upon the financial condition of the Company.

Legal Proceedings

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

Parker v. Tracinda Corporation, Denver District Court, Case No. 2011CV561. In November 2012, the Company filed a motion to intervene in garnishment proceedings involving Roger Parker, the Company’s former Chief Executive Officer and Chairman. The Defendant has served various writs of garnishment on the Company to enforce a judgment against Mr. Parker seeking, among other things, shares of unvested, restricted stock. The Company has asserted rights to lawful set-offs and deductions in connection with certain tax consequences, which may be material to the Company. As a result of bankruptcy proceedings filed by Mr. Parker, the garnishment proceedings have been stayed with respect to the Denver District Court case. At this stage, we cannot express an opinion as to the probable outcome of this matter.

In re Roger A. Parker: Tracinda Corp. v. Recovery Energy, Inc. and Roger A. Parker, United States Bankruptcy Court for the District of Colorado, Case No. 13-10897-EEB. On June 10, 2013, Tracinda Corp. (“Tracinda”) filed a complaint (Adversary No. 13-011301 EEB) against the Company and Roger Parker in connection with the personal bankruptcy proceedings of Roger Parker, alleging that the Company improperly failed to remit to Tracinda certain property in connection with a writs of garnishment issued by the Denver District Court (discussed above). The Company filed an answer to this complaint on July 10, 2013.

NOTE 11 - SHAREHOLDERS’ EQUITY

Common Stock

As of September 30, 2013, the Company had 100,000,000 shares of common stock and 10,000,000 shares of preferred stock authorized, of which 19,477,337 shares of common stock were issued and outstanding. No preferred shares were issued or outstanding.

During the nine months ended September 30, 2013, the Company issued 1,082,936 shares of common stock, including 471,720 shares to pay interest on convertible debentures, and 611,216 shares of common stock as restricted stock grants to employees, board members, or consultants.

Investment Banking Agreement

In May 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 900,000 common stock purchase warrants. All warrants have a term of three years and a strike price of $4.25 per share. The investment banking agreement also 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. The 900,000 warrants are valued at $0.38 million and the 100,000 common shares are valued at $0.16 million. Both equity instruments are classified as a prepaid asset and amortized over the life of the agreement. During the three month and nine month periods ended September 30, 2013, $0.09 million and $0.10 million, respectively, were included in general and administrative expense as amortization of the value of these grants.

Convertible Debenture Interest

During the nine months ended September 30, 2013, the Company issued 471,720 shares for payment of quarterly interest expense on the convertible debentures valued at $0.83 million.

Warrants

A summary of warrant activity for the nine months ended September, 2013 is presented below:

				Weighted- Average
	Warrants			Exercise Price
Outstanding at December 31, 2012		5,638,900		$	7.04
Granted		1,118,750			4.25
Exercised, forfeited, or expired		(108,737	)		(6.00	)
Outstanding at September 30, 2013		6,648,913		$	6.59

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 an exercise of $4.25 and a total valuation of $0.30 million. The shares vested 25% on March 31, 2013 and will vest 25% for each quarter thereafter. The Company is valuing the warrants each quarter based on their vesting schedule, and including the amount associated with such vesting warrants as an expense in the period of vesting.

The aggregate intrinsic value associated with outstanding warrants as of September 30, 2013 and December 31, 2012 was $0, as the strike price of all warrants exceeded the market price for common stock, based on the Company’s closing common stock price of $2.08 and $1.99, respectively. The weighted average remaining contract life as of September 30, 2013 was 1.81 years, and 2.56 years as of December 31, 2012.

NOTE 12 - 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 nine months ended September 30, 2013, the Company granted 511,212 shares of restricted common stock to employees and directors, including 100,000 during the three months ended September 30, 2013. The Company also granted 3,200,000 stock options to employees and board members which are contingent on shareholder approval.

A summary of restricted stock grant activity for the nine months ended September 30, 2013 is presented below:

	Shares
Balance outstanding at December 31, 2012		1,730,710
Granted		511,212
Vested		(315,385	)
Expired/ cancelled		(8,333	)
Balance outstanding at September 30, 2013		1,918,204

Total unrecognized compensation cost related to unvested stock grants was approximately $0.33 million as of September 30, 2013. The cost at September 30, 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 $0.02 million for the nine months ended September 30, 2013.

Stock Options

A summary of stock options activity for the nine months ended September 30, 2013 is presented below:

	Stock Options
Outstanding at December 31, 2012		-
Granted		3,200,000
Exercised, forfeited, or expired		-
Outstanding at September 30, 2013		3,200,000

In June 2013, the Company entered into employment agreements with the CEO and the then President/CFO for non-cash compensation which consist of each individual receiving 300,000 stock options of which 100,000 vested immediately and 200,000 vests over the next 2 years, subject to approval by the Company’s shareholders. The options have a five year life and an exercise price of $1.60. The 600,000 stock options are valued of $0.52 million at date of grant and are contingent on shareholder approval. During the nine months ended September 30, 2013, the Company recognized $0.22 million as non-cash compensation expense and $0.30 million is to be amortized over the remaining vesting period.

These employment contracts also provide that some or all of the 2013 salaries of these individuals may be paid via the issuance of up to 93,750 shares of common stock in 2014 for each executive.

In September 2013, the Company hired and entered into an employment agreement with a new President of the Company. The employment agreement provides, among other things, for the grant of 100,000 shares of the Company’s common stock which vested immediately as an inducement for joining the Company. The employment agreement also provided for the grant of an option to purchase 600,000 shares of common stock of the Company, at a strike price of $2.45 per share, which will become exercisable upon the date the Company receives gross cash proceeds or drawing availability of at least $30,000,000, measured on a cumulative basis and including certain restructuring transactions. The employment agreement also provided an incentive bonus package and an additional stock option grant of 2 million options, which will become exercisable once certain conditions specified in the employment agreement are met. The Company recognized $.245 million of expense associated with the share grant. The Company also recognized $.02 million as non-cash compensation expense during the three months ended September 30, 2013 related to options.

NOTE 13- SUBSEQUENT EVENTS

Restatement

In February 2015, in the course of transitioning between independent public accounting firms, the Company discovered an error in the valuation provided by its third-party valuation expert regarding the conversion derivative liability of the Debentures for the periods ended December 31, 2011, December 31, 2012, December 31, 2013, as well as March 31, 2014 and June 30, 2014. While the Company determined that the impact of the error on its annual financial statements for the fiscal years ended December 31, 2011, December 31, 2012, and December 31, 2013 was not material, the Company determined that the impact of these non-cash items in its quarterly financial statements for the fiscal quarters ended September 30, 2013, March 31, 2014 and June 30, 2014 was sufficiently material to warrant restatement of the financial results contained in the Company’s Quarterly Reports on Form 10-Q for those periods. (See Note 1- Restatement).

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. This discussion contains forward-looking statements that involve risks and uncertainties. Our actual results could differ materially from those anticipated in these forward-looking statements as a result of various factors including those set forth under Item “1A. Risk Factors” in our Annual Report on Form 10-K for the year ended December 2012.

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-Julesburg (“DJ”) Basin. Our business strategy is designed to create shareholder value by developing our undeveloped acreage and leveraging the knowledge, expertise and experience of our management team.

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

Restatement

In February 2015, in the course of transitioning between independent public accounting firms, we discovered an error in the valuation provided by our third-party valuation expert regarding the conversion derivative liability of our 8% Senior Secured Convertible Debentures (the “Debentures”) for the periods ended December 31, 2011, December 31, 2012, December 31, 2013, as well as March 31, 2014 and June 30, 2014 (together, the “Relevant Periods”). Specifically, the calculation of the conversion liability included in our financial statements for the Relevant Periods only included the value of the price protection (anti-dilution) feature, when it should have included both the conversion option and the price protection embedded in the Debentures. The changes in the value of the derivative resulted in non-cash charges to the financial statements.

We have evaluated the effect of the error on all Relevant Periods in accordance with Staff Accounting Bulletin (“SAB”) 99 and SAB 108 and determined that the impact of the error on our annual financial statements for the fiscal years ended December 31, 2011, December 31, 2012, and December 31, 2013 was not material. However, we have determined that the impact of these non-cash items in our quarterly financial statements for the fiscal quarters ended September 30, 2013, March 31, 2014 and June 30, 2014 was sufficiently material to warrant restatement of our Quarterly Reports on Form 10-Q for those periods. In addition, we will correct the amounts related to the error for the fiscal years ended December 31, 2011, December 31, 2012, and December 31, 2013 in our Annual Report on Form 10-K for the fiscal year ended December 31, 2014. We have also corrected the error for the fiscal year ended December 31, 2012 in this Quarterly Report on Form 10-Q/A.

Financial Condition and Liquidity

Since our inception, we have incurred a cumulative net loss of approximately $113.12 million. As of September 30, 2013, we have negative working capital of $33.78 million and current liabilities of $35.45 million.

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

	September 30, 2013			December 31, 2012
	(Restated)			(Restated)
Financial Position Summary
Cash and cash equivalents	$	353,934		$	970,035
Working capital	$	(33,780,276	)	$	(1,041,491	)
Balance outstanding on term loans and convertible debentures	$	32,943,256		$	32,736,341
Shareholders’ equity	$	7,616,648		$	12,781,059

During the nine months ended September 30, 2013, our working capital decreased to negative $33.78 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 two factors: (i) the classification of the term loans and the convertible debentures as current liabilities due to their maturity dates of May 16, 2014; and (ii) cash used in operations and investing activities that exceeded cash provided by financing activities. In view of the maturity of our secured indebtedness in May 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 and our convertible debentures matures. If we default under any of these instruments, 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 are not satisfied through sale of such properties. Principally as a result of the current maturity date of these debts, we currently do not have enough working capital to cover our current liabilities.

We currently have $18.97 million outstanding under our term loans with Hexagon, LLC (“Hexagon”) and $14.83 million outstanding under our 8% Senior Secured Convertible Debentures. Both the term loans and the convertible debentures are considered current on our balance sheet and mature May 16, 2014.

In addition to the above, the Company will require additional capital to fund its capital spending plans, to help fund its ongoing overhead, to provide for payment of minimum interest and principal payments required by term loans, and to provide additional capital to generally improve its working capital position.

In April 2013, we received approval from our existing secured debt and convertible debenture holders to issue up to $5.00 million of additional convertible debentures with terms substantially identical to our existing convertible debentures. As of November 8, 2013 we have issued $2.20 million of such convertible debt. Two officers of the Company participated in the additional convertible debentures for a combined total of $0.43 million. Proceeds from the issuance of this convertible debt have been used toward the development of certain specific properties, and to a lesser extent, general corporate purposes. The recent commitments were subject to certain yield enhancements, including a 25% carried interest in certain properties scheduled to be developed with the proceeds.

The Company may, but is not obligated to, seek completion of the remainder of the $5.00 million offering (“Offering”) of additional debt that was approved in April 2013. However, there is no assurance that the Company will be successful in securing additional convertible debenture funding.

In April 2013, we entered into amendments to both our term loan agreements with Hexagon and our convertible 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 $0.23 million 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, we provided to each of 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. 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 possible sales 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, we and the debenture holders have agreed to waive any breach under the debentures that may have occurred prior to the date of the amendment.

Cash Flows

Cash used in operating activities during the nine months ended September 30, 2013 was $1.56 million. This use of cash, coupled with the cash used in investing activities, exceeded cash provided by financing activities by $0.62 million, and resulted in a corresponding decrease in cash. This net use of cash coupled with both the term loans and convertible debentures becoming current contributed to a $32.93 million decrease in working capital as of September 30, 2013, compared to working capital as of December 31, 2012.

The following table compares cash flow items during the nine months ended September 30, 2013 to September 30, 2012:

	Nine Months Ended September 30,
	2013			2012
	(Restated)
Cash provided by (used in):
Operating activities	$	(1,558,306	)	$	(2,747,079	)
Investing activities		(118,573	)		(3,274,068	)
Financing activities		1,060,779			4,011,701
Net change in cash	$	(616,100	)	$	(2,009,446	)

During the nine months ended September 30, 2013, net cash used in operating activities was $1.56 million, compared to $2.75 million during the nine months ended September 30, 2012, a decrease of cash used in operating activities of $1.19 million or 43%. The primary changes in operating cash during the nine months ended September 30, 2013 were $7.70 million of net loss, adjusted for non-cash charges of $1.87 million of depreciation, depletion, amortization and accretion expenses, $1.74 million of debt discount accretion, $0.53 million of amortization of deferred financing costs, $0.83 million issuance of stock for convertible debentures interest, $1.29 million for issuance of stock for services and compensation, a non-cash change in fair value of convertible debentures conversion option of $0.93 million, and $0.45 million in accounts receivable, which was offset by $0.67 million of cash provided for accounts payable and other accrued expenses and $0.16 million for cash provided for other assets.

During the nine months ended September 30, 2013, net cash used in investing activities was $0.12 million, compared to net cash used in investing activity of $3.27 million during the nine months ended September 30, 2012, a decrease of cash used in investing activities of $3.15 million or 96%. The primary changes in investing cash during the nine months ended September 30, 2013 were an increase in cash of $0.64 million related to our sale of oil and gas properties which was offset by a decrease in cash of $0.42 million of drilling expenditures, and $0.30 million additions to oil and gas properties.

During the nine months ended September 30, 2013, net cash provided in financing activities was $1.06 million, compared to net cash provided by financing activities of $4.01 million during the nine months ended September 30, 2012, a decrease of $2.95 million, or 74%. The changes in financing cash during the nine months ended September 30, 2013 were primarily due to proceeds from debt issuance of $1.43 million which was offset by net repayments of debt of $0.04 million.

Capital Resources

Funding any additional development of our properties in 2013, and refinancing the Hexagon loans and Debentures prior to their maturity in May 2014, are subject to securing sufficient capital. 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. We cannot offer assurances that any of these activities will be successful.

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 capital expenditures, our liquidity and working capital have deteriorated. We will seek additional capital to refinance our debts, partially fund our operations, and fund our capital budget. We will also require substantial additional capital in order to fully test, develop and evaluate our 112,000 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, or in restructuring our existing indebtedness, in the near term, we will 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, refinance our debts or finance any additional 2013 capital expenditures.

Results of Operations

Three months ended September 30, 2013 compared to three months ended September 30, 2012

The following table compares operating data for the three months ended September 30, 2013 to September 30, 2012:

	2013			2012
Revenue	(Restated)
Oil sales	$	1,003,745		$	1,775,383
Gas sales		82,651			168,897
Operating fees		28,331			42,853
Realized gain (loss) on commodity price derivatives		(43,551	)		37,341
Unrealized gain (loss) on commodity price derivatives		(20,000	)		(130,000	)
Total revenues		1,051,176			1,894,474

Costs and expenses
Production costs		318,322			397,793
Production taxes		102,919			198,781
General and administrative		1,207,123			1,515,868
Depreciation, depletion and amortization		539,079			1,069,068
Total costs and expenses		2,167,443			3,181,510

Loss from operations		(1,116,267	)		(1,287,036	)

Other income (expense)		145			333
Conversion note derivative (loss) gain (restated)		(207,251	)		600,000
Interest expense (restated)		(1,582,881	)		(2,149,931	)

Net Loss (restated)	$	(2,906,254	)	$	(2,836,634	)

Total revenues

Total revenues were $1.05 million for the three months ended September 30, 2013, compared to $1.89 million for the three months ended September 30 2012, a decrease of $0.84 million, or 44%. The decrease in revenues was due primarily to a decrease in production volumes. During the three months ended September 2013 and 2012, production amounts were 13,822 and 26,067 BOE, respectively, a decrease of 12,075 BOE, or 46%. Declines in production are primarily attributable to natural production declines related to mature producing properties, but also affected by the temporary reduction in production from three of the Company’s properties that were experiencing production difficulties during the quarter. The effect of this production decrease was partially offset by an increase in the overall average price per BOE to $78.60 in 2013 from $74.59 in 2012, an increase of $4.01 or 5%.

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

	For the Three Months Ended September 30,
	2013			2012
Product
Oil (Bbl.)		11,389			21,151
Oil (Bbls)-average price (1)	$	88.13		$	83.94

Natural Gas (MCF)-volume		14,595			29,498
Natural Gas (MCF)-average price (2)	$	5.66		$	5.73

Barrels of oil equivalent (BOE)		13,822			26,067
Average daily net production (BOE)		150			283
Average Price per BOE (1)	$	78.60		$	74.59

(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)	$	78.60		$	74.59

Production costs per BOE		23.03			15.26
Production taxes per BOE		7.45			7.63
Depreciation, depletion, and amortization per BOE		39.00			41.01
Total operating costs per BOE	$	69.48		$	63.90

Gross margin per BOE	$	9.12		$	10.69

Gross margin percentage		11.60	%		14.33	%

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

Commodity Price Derivative Activities

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

As of September 30, 2013, the Company maintained an active commodity swap for 100 barrels of oil per day through January 31, 2014 at a price of $99.25 per barrel.

Commodity price derivative realized losses were $0.04 million for the three months ended September 30, 2013, compared to a realized gain of $0.04 million during the three months ended September 30, 2012, a decrease in realized gains/losses of $0.08 million or 266%. Commodity price derivative unrealized losses were $0.02 million for the three months ended September 30, 2013, compared to an unrealized losses of $0.13 million during the three months ended September 30, 2012, a decrease in unrealized losses of $0.11 million or 85%.

Production costs

Production costs were $0.32 million during the three months ended September 30, 2013, compared to $0.40 million for the three months ended September 30, 2012, a decrease of $0.08 million, or 20%. 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 $23.03 for the three months ended September 30, 2013 from $15.26 in 2012, an increase of $7.77 per BOE, or 51%, primarily as a result of reduced volumes of BOE in 2013.

Production taxes

Production taxes were $0.10 million for the three months ended September 30, 2013, compared to $0.20 million for the three months ended September 30, 2012, a decrease of $0.10 million, or 50%. Decrease in production taxes was from a decrease in production and product mix per state. Currently, ad valorem, severance and conservation taxes range from 1% to 13% based on the state and county which production is derived. Production taxes per BOE decreased to $7.45 during the three months ended September 30, 2013 from $7.63 in 2012, a decrease of $0.18 or 2%.

General and administrative

General and administrative expenses were $1.21 million during the three months ended September 30, 2013, compared to $1.52 million during the three months ended September 30, 2012, a decrease of $0.31 million, or 20%. Non-cash general and administrative items for the three months ended September 30, 2013 were $0.72 million compared to $0.58 million during the three months ending September 30, 2012, an increase of $0.14 million, or 24%. The increase in non-cash general and administrative expenses was due to an increase in non-cash compensation of $0.05 million and an increase in non-cash executive salary expense of $0.11 million which was offset by a decrease in non-cash consulting expense of $0.02 million. Cash general and administrative expenses were $0.49 million during the three months ended September 30, 2013, compared to $0.94 million during the three months ended September 30, 2012, a decrease of $0.45 million, or 48%. The decrease in cash general and administrative expenses was a result of reductions in staffing and other expenses, but partially offset by additional legal expenses and other professional service expenses.

Depreciation, depletion, and amortization

Depreciation, depletion, and amortization were $0.54 million during the three months ended September 30, 2013, compared to $1.07 million during the three months ended September 30, 2012, a decrease of $0.53 million, or 49%. 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 13,992 from 26,067 for the three months ended September 30, 2013 and 2012, respectively, a decrease of 12,075, or 46%. The decrease in depletion was based on a lower depletion base. Depreciation, depletion, and amortization per BOE decreased to $39.00 from $41.01, respectively, for the three months ended September 30, 2013 and 2012, a decrease of $2.01, or 5%.

Impairment of developed properties

There was no impairment of developed properties during the three months ended September 30, 2013 and September 30, 2012.

Interest Expense

For the three months ended September 30, 2013 and 2012, the Company incurred interest expense of approximately $1.58 million and $2.15 million, respectively, of which approximately $1.51 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. The decrease in interest expense was primarily attributable to a decrease in the interest rate on the Company’s term loans from 15% to 10% that occurred effective April 1, 2013, but partially offset by an increase in the Company’s convertible debentures.

Change in derivative liability of convertible debentures

For the three months ended September 30, 2013 and 2012, the Company incurred a change in the fair value of the derivative liability related to the convertible debentures of approximately $0.21 million and $0.60 million respectively due to the change in fair value of the derivative liability.

Results of Operations

Nine months ended September 30, 2013 compared to nine months ended September 30, 2012

The following table compares operating data for the nine months ended September 30, 2013 to September 30, 2012:

	2013			2012
	(Restated)
Revenue
Oil sales	$	3,320,083		$	4,685,713
Gas sales		227,853			397,298
Operating fees		118,853			132,362
Realized gain (loss) on commodity price derivatives		(23,661	)		49,729
Unrealized gain (loss) on commodity price derivatives		(20,000	)		445,609
Total revenues		3,623,128			5,710,711

Costs and expenses
Production costs		877,623			1,033,635
Production taxes		380,958			561,278
General and administrative		3,559,358			5,099,932
Depreciation, depletion and amortization		1,879,908			2,897,156
Impairment of developed properties		-			3,274,718
Total costs and expenses		6,697,847			12,866,719

Loss from operations		(3,074,719	)		(7,156,008	)

Other income		536			(372	)
Conversion note derivative gain		93,851			700,000
Interest expense		(4,723,624	)		(6,320,919	)

Net Loss	$	(7,703,956	)	$	(12,777,299	)

Total revenues

Total revenues were $3.62 million for the nine months ended September 30, 2013, compared to $5.71 million for the nine months ended September 30 2012, a decrease of $2.09 million, or 37%. The decrease in revenues was due primarily to a decrease in production volumes and a decrease in realized and unrealized gains on commodity price derivatives. During the nine months ended September 30, 2013 and 2012, production amounts were 46,904 and 64,366 BOE, respectively, a decrease of 17,462 BOE, or 27%. The revenue overall average price decreased per BOE to $75.64 in 2013 from $78.97 in 2012, an increase of $3.33 or 4%. The decrease in realized gains on commodity derivatives of $0.07 million and a decrease in unrealized gain on commodity price derivatives of $0.46 million for a total decrease of $0.53 million. Declines in production are primarily attributable to natural production declines related to mature producing properties, and also three of the Company’s gas and oil properties that were experiencing production difficulties during the period.

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

	For the Nine Months Ended September 30,
	2013		2012
Product
Oil (Bbl.)		38,464		55,519
Oil (Bbls)-average price (1)	$	86.32	$	84.39

Natural Gas (MCF)-volume		50,642		53,084
Natural Gas (MCF)-average price (2)	$	4.49	$	7.48

Barrels of oil equivalent (BOE)		46,904		64,366
Average daily net production (BOE)		172		236
Average Price per BOE (1)	$	75.64	$	78.97

(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)	$	75.64		$	78.97

Production costs per BOE		18.71			16.06
Production taxes per BOE		8.12			8.72
Depreciation, depletion, and amortization per BOE		40.08			45.01
Total operating costs per BOE	$	66.91		$	69.79

Gross margin per BOE	$	8.73		$	9.18

Gross margin percentage		11.50	%		11.62	%

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

Commodity Price Derivative Activities

As of September 30, 2013, the Company maintained an active commodity swap for 100 barrels of oil per day through January 31, 2014 at a price of $99.25 per barrel.

Commodity price derivative realized losses were $0.02 million for the nine months ended September 30, 2013, compared to a realized gain of $0.05 million during the nine months ended September 30, 2012, a decrease in realized gains/losses of $0.07 million or 140%. Commodity price derivative unrealized losses were $0.02 million for the nine months ended September 30, 2013, compared to an unrealized gains of $0.45 million during the nine months ended September 30, 2012, a decrease in unrealized losses of $0.47 million or 104%.

Production costs

Production costs were $0.88 million during the nine months ended September 30, 2013, compared to $1.03 million for the nine months ended September 30, 2012, a decrease of $0.15 million, or 15%. Decrease in production costs in 2013 was from a decrease of the number of workovers, property improvements, and onsite work on productive wells. Production costs per BOE increased to $18.71 for the nine months ended September 30, 2013 from $16.06 in 2012, an increase of $2.65 per BOE, or 17%.

Production taxes

Production taxes were $0.38 million for the nine months ended September 30, 2013, compared to $0.56 million for the nine months ended September 30, 2012, a decrease of $0.18 million, or 32%. Decrease in production taxes was from a decrease in production and product mix per state. Currently, ad valorem, severance and conservation taxes range from 1% to 13% based on the state and county which production is derived. Production taxes per BOE decreased to $8.12 during the nine months ended September 30, 2013 from $8.72 in 2012, a decrease of $0.60 or 7%.

General and administrative

General and administrative expenses were $3.56 million during the nine months ended September 30, 2013, compared to $5.10 million during the nine months ended September 30, 2012, a decrease of $1.54 million, or 30%. Non-cash general and administrative items for the nine months ended September 30, 2013 were $1.73 million compared to $1.77 million during the nine months ending September 30, 2012, a decrease of $0.04 million, or 2%. The decrease in non-cash general and administrative expenses was due to a decrease in non-cash consulting expense of $0.40 million which was offset by an increase in non-cash executive salary of $0.30 million and an increase in non-cash employee and board compensation expense of $0.06 million. Cash general and administrative expenses were $1.83 million during the nine months ended September 30, 2013, compared to $3.33 million during the nine months ended September 30, 2012, a decrease of $1.50 million, or 45%. The decrease in cash general and administrative expenses was primarily a result of a reduction of employee count.

Depreciation, depletion, and amortization

Depreciation, depletion, and amortization were $1.88 million during the nine months ended September 30, 2013, compared to $2.90 million during the nine months ended September 30, 2012, a decrease of $1.02 million, or 35%. 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 46,904 from 64,366 for the nine months ended September 30, 2013 and 2012, respectively, a decrease of 17,462, or 27%. The decrease in depletion was based on a lower depletion base. Depreciation, depletion, and amortization per BOE decreased to $40.08 from $45.01, respectively, for the nine months ended September 30, 2013 and 2012, an increase of $4.93, or 11%.

Impairment of developed properties

During the nine months ended September 30, 2013, the Company did not have an impairment of developed properties. The Company recognized $3.27 million of impairment during the nine months ended September 30, 2012.

Interest Expense

For the nine months ended September 30, 2013 and 2012, the Company incurred interest expense of approximately $4.72 million and $6.32 million, respectively, of which approximately $3.42 million and $3.80 million, respectively, were non-cash interest expense and amortization of the deferred financing costs, accretion of the convertible debentures payable discount, and convertible debentures interest paid in common stock. The decrease in interest expense was primarily attributable to a decrease in the interest rate on the Company’s term loans from 15% to 10% that occurred effective April 1, 2013, but partially offset by an increase in the Company’s convertible debentures.

Change in derivative liability of convertible debentures

For the nine months ended September 30, 2013 and 2012, the Company incurred a change in the fair value of the derivative liability related to the convertible debentures of approximately $0.09 million and $0.70 million respectively due to the change in fair value of the derivative liability.

Off-Balance Sheet Arrangements

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

Capital Budget

We anticipate an approximate $50 million capital budget for the period that runs through the end of 2014. This entire capital budget is subject to the securing of adequate financing. It also assumes that we will be successful in negotiating a restructuring or recapitalization transaction with our senior lender and the holders of our convertible debentures. We anticipate that approximately $30 million 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 capital 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 capital budget toward higher risk exploration activities, including the procurement of seismic data.

Our capital budget is subject to various factors, including availability of capital, market conditions, 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 DJ Basin acreage position.

Other factors that could cause us to further 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 our 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.

Overview of Our Business and Strategy, and Plan of Operations

We have developed and acquired an oil and natural gas base of proved reserves, as well as a portfolio of exploration and development prospects with conventional and non-conventional reservoir opportunities, with an emphasis on multiple producing horizons, in particular the Muddy “J” conventional reservoirs and the Niobrara shale and Codell resource plays. We believe these prospects offer the possibility of repeatable success allowing for meaningful production and reserve growth. Our acquisition, development and exploration pursuits are principally directed at oil and natural gas properties in the DJ Basin in Colorado, Nebraska, and Wyoming. Since early 2010, we have acquired and/or developed 29 producing wells. As of August 29, 2013 we owned interests in approximately 125,000 gross (112,000 net) leasehold acres, of which 113,000 gross (100,000 net) acres are classified as undeveloped acreage and all of which are located in Colorado, Wyoming and Nebraska within the DJ Basin. Our management team has undertaken an in-depth process to re-evaluate our operations, production and drilling prospects. We are focused on conventional development in our Silo East, Hanson and Wilke/Lukassen well areas. We believe that our Wattenberg North and South Prospects include attractive unconventional drilling opportunities in mature development areas with low risk Niobrara and Codell formation productive potential. We expect to pursue an aggressive multi-well program, including with a portion of the proceeds of this Offering. However, even upon the completion of this Offering, we will need to raise significant additional capital to fund many of these opportunities and to address the upcoming maturity of our senior secured debt and our outstanding convertible debentures.

Our intermediate goal is to create significant value via the investment of up to $50 million in our inventory of low and controlled risk conventional and unconventional properties, while maintaining a low cost structure. To achieve this, our business strategy includes the following elements:

Pursuing the initial development of certain of our key Wattenberg unconventional properties. We currently have two key unconventional properties located in the Greater Wattenberg field that are expected to be drilled within the course of the next 12 months. Drilling activities on both properties will target the Niobrara and Codell formations, and drilling activities on one of the properties have already commenced. We expect to participate in up to 18 wells in these two prospects, with an expected investment that exceeds $30 million.

Extending the development of certain conventional prospects within our inventory of DJ Basin properties. We anticipate the expenditure of up to an additional $15 million in drilling and development costs on three of our DJ Basin prospects where initial wells have shown promise. Additional drilling activities will be conducted on each property in an effort to fully develop each property and define field productivity and economic limits.

Engaging in certain exploration activities, including geologic and geophysics projects, to define additional prospects within our inventory of DJ Basin properties that may have significant development upside. We anticipate the expenditure of $3-5 million [in 2014] to pursue seismic acquisition projects in at least three target areas to identify both conventional and unconventional drilling opportunities.

Controlling

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

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

Currently, our inventory of developed and undeveloped acreage includes approximately 12,000 net acres that are held by production, approximately 25,000 net acres, 61,000, and 14,000 net acres that expire in the years 2014, 2015 and thereafter, respectively. Approximately 75% 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 refinance our secured and convertible debenture debts that mature May 2014, 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, joint venture agreements with industry partners, 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 September 30, 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	$	18,967	$	18,967	$	-	$	-	$	-
Interest on secured debt		1,201		1,201		-		-		-
Convertible debentures		14,829		14,829		-		-		-
Interest on convertible debentures		751		751		-		-		-
Operating leases & Other		59		59		-		-		-
Total contractual cash obligations	$	35,807	$	35,807	$	-	$	-	$	-

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 June 30, 2013, using the average, first-day-of-the-month price during the 12-month period ending June 30, 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 June 30 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 3. Quantitative and Qualitative Disclosures About Market Risk.

Not Applicable

Item 4. Controls and Procedures.

Evaluation of Disclosure Controls and Procedures

The Company’s Chief Executive Officer and Chief Financial Officer have evaluated the effectiveness of the Company’s disclosure controls and procedures (as such term is defined in Rules 13a-15(e) under the Securities Exchange Act of 1934, as amended, the Exchange Act) as of September 30, 2013 Disclosure controls and procedures are controls and other procedures designed to ensure that information required to be disclosed by the Company in its reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms and include, without limitation, controls and procedures designed to ensure that information that the Company is required to disclose in such reports is accumulated and communicated to management, including our Chief Executive Officer and our Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosures. Based upon that evaluation, our Chief Executive Officer and our Chief Financial Officer concluded that, as of September 30, 2013, the Company’s disclosure controls and procedures were not effective, due to the material weakness in internal controls over financial reporting described below.

Internal Controls over Financial Reporting

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

Based on the evaluation and the identification of the material weakness in internal control over financial reporting described below, our Chief Executive Officer and our Chief Financial Officer have concluded that, as of September 30, 2013, the Company’s disclosure controls and procedures which we previously reported as being effective were actually not effective.

A material weakness is a control deficiency, or combination of control deficiencies, that results in more than a remote likelihood that a material misstatement of the annual or interim financial statements will not be prevented or detected.

As discussed above in the Explanatory Note and Note 1-Restatement in this Amended Report, in February 2015, the Company discovered an error in the valuation of the conversion derivative liability of the Company’s Debentures for the Relevant Periods. Specifically, the calculation of the conversion liability included in the Company’s financial statements for the Relevant Periods only included the value of the price protection (anti-dilution) feature, when it should have included both the conversion option and the price protection embedded in the Debentures. The changes in the value of the derivative resulted in changes to the Company’s financial statements, which warranted restatement of the Company’s Quarterly Reports on Form 10-Q for the fiscal quarters ended September 30, 2013, March 31, 2014 and June 30, 2014.

As a result of the restatement described in this restated Quarterly Report on Form 10-Q/A, the Company’s Chief Executive Officer and Chief Financial Officer, with the assistance of other members of management and expert internal control consultants, re-evaluated the effectiveness of the Company’s internal controls over financial reporting as of September 30, 2013 in accordance with the assessment and testing procedures described above. Based on this re-evaluation, and because the impact of the errors on the Company’s quarterly financial statements for the fiscal quarters ended September 30, 2013, March 31, 2014 and June 30, 2014, described in the Explanatory Note to this Amended Report and Note 1 – Restatement, was sufficiently material to warrant restatement of the Company’s Quarterly Reports on Form 10-Q for those periods, we have determined that the following additional material weakness in internal controls over financial reporting existed as of September 30, 2013:

●

We did not maintain effective controls to provide reasonable assurance that our convertible debenture conversion derivative liability was being valued correctly during the fiscal years ended December 31, 2011, December 31, 2012 and December 31, 2013 and the quarters ended March 31, 2014 and June 30, 2014. This material weakness resulted in errors in our financial statements and related disclosures, including inaccuracies in previously reported fair value of convertible debt notes derivative, convertible notes debenture discount, net gain/loss and total shareholders’ equity.

Because of the material weakness described above, management has concluded that we did not maintain effective internal control over financial reporting as of September 30, 2013, based on the Internal Control—Integrated Framework issued by COSO (1992).

Remediation Efforts

We plan to make necessary changes and improvements to the overall design of our control environment to address the material weaknesses in internal control over financial reporting described above. In particular, we expect to hire additional staff to assist with complex accounting issues such as convertible debentures.

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

Changes in Internal Control over Financial Reporting

Other than those described above, management has determined that there were no changes in the Company’s internal controls over financial reporting during the fiscal quarter ended September 30, 2013 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

PART II - OTHER INFORMATION

Item 1. Legal Proceedings.

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 in Denver District Court have been stayed. At this stage, we cannot express an opinion as to the probable outcome of this matter.

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.

None.

Item 6. Exhibits.

Exhibit Number		Exhibit Description
10.1*		Employment Agreement between the Company and Avi Mirman (incorporated herein by reference to Exhibit 10.1 to the Company’s current report on Form 8-K dated September 16, 2013)
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

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

* Filed previously

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/ Abraham Mirman	Chief Executive Officer	February 18, 2013
Abraham Mirman	(Principal Executive Officer)

/s/ Eric Ulwelling	Chief Financial Officer	February 18, 2013
Eric Ulwelling	(Principal Financial Officer)

EXHIBIT INDEX

Exhibit Number		Exhibit Description
10.1*		Employment Agreement between the Company and Avi Mirman (incorporated herein by reference to Exhibit 10.1 to the Company’s current report on Form 8-K dated September 16, 2013)
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

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

* Filed previously

LILIS ENERGY, INC. - FORM 10-Q/A - February 18, 2015

Attached files

LILIS ENERGY, INC. Reports