Lilis Energy 10Q 2014 Q2 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

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

For the quarterly period ended June 30, 2014

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

For the transition period from ______to______.

001-35330

(Commission File No.)

LILIS ENERGY, INC.

(Exact name of registrant as specified in charter)

NEVADA

74-3231613

(State or other jurisdiction of

incorporation or organization)

(IRS Employee

Identification No.)

1900 Grant Street, Suite #720

Denver, CO 80203

(Address of Principal Executive Offices)

(303) 951-7920

(Registrant’s telephone number, including area code)

Indicate by check mark if the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the past 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yeso Nox

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). Yesx Noo

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

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

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

As of November 21, 2014, 27,676,067 shares of the registrant’s common stock were issued and outstanding.

Lilis Energy, Inc.

INDEX

PART I–FINANCIAL INFORMATION

Item 1.	Financial Statements (Unaudited)	1
	Consolidated Balance Sheets as of June 30, 2014 and December 31, 2013	1
	Consolidated Statements of Operations for the Three and Six Months Ended June 30, 2014 and 2013	3
	Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2014 and 2013	4
	Notes to Consolidated Financial Statements	5

Item 2.	Management’s Discussion and Analysis of Financial Condition	19

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	31

Item 4.	Control and Procedures	32

PART II–OTHER INFORMATION

Item 1.	Legal Proceedings	33
Item 1A.	Risk Factors	33
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	33
Item 3.	Defaults Upon Senior Securities	34
Item 4.	Mine Safety Disclosures	34
Item 5.	Other Information	34
Item 6.	Exhibits	34

SIGNATURES		35

EXHIBIT INDEX		36

FORWARD-LOOKING STATEMENTS

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

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

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

	●	the risk factors discussed in Part I, Item 1A of our 2013 Annual Report on Form 10-K for the year ended December 31, 2013;
	●	availability of capital on an economic basis, or at all, to fund our capital needs;
	●	failure to meet requirements under our debt instruments, which could lead to foreclosure of significant assets;
	●	failure to fund our authorization for expenditures from other operators for key projects which will reduce/eliminate our interest in the wells/area;
	●	inability to address our negative working capital position;
	●	the inability of management to effectively implement our strategies and business plans;
	●	potential default under our secured obligations or material debt agreements;
	●	estimated quantities and quality of oil and natural gas reserves;
	●	exploration, exploitation and development results;
	●	fluctuations in the price of oil and natural gas, including reductions in prices that would adversely affect our revenue, cash flow, liquidity and access to capital;
	●	availability of, or delays related to, drilling, completion and production, personnel, supplies and equipment;
	●	the timing and amount of future production of oil and gas;
	●	the completion, timing and success of our drilling activity;
	●	lower oil and natural gas prices or an increase in our price deferential, from our first purchaser due to the excess of supply in the area, which negatively affect our ability to borrow or raise capital, or enter into joint venture arrangements;
	●	declines in the values of our natural gas and oil properties resulting in write-downs;
	●	inability to hire or retain sufficient qualified operating field personnel;
	●	our ability to successfully identify and consummate acquisition transactions;
	●	our ability to successfully integrate acquired assets or dispose of non-core assets;
	●	increases in interest rates or our cost of borrowing;
	●	deterioration in general or regional (especially Rocky Mountain) economic conditions;
	●	the strength and financial resources of our competitors;
	●	the occurrence of natural disasters, unforeseen weather conditions, or other events or circumstances that could impact our operations or could impact the operations of companies or contractors we depend upon in our operations;
	●	inability to acquire or maintain mineral leases at a favorable economic value that will allow us to expand our development efforts;
	●	inability to successfully develop the acreage we currently hold;
	●	transportation capacity constraints or interruptions, curtailment of production, natural disasters, adverse weather conditions, or other issues affecting the DJ Basin;
	●	technique risks inherent in drilling in existing or emerging unconventional shale plays using horizontal drilling and completion techniques;
	●	delays, denials or other problems relating to our receipt of operational consents and approvals from governmental entities and other parties;
	●	unanticipated recovery or production problems, including cratering, explosions, fires and uncontrollable flows of oil, gas or well fluids;
	●	environmental liabilities;
	●	operating hazards and uninsured risks;
	●	loss of senior management or technical personnel;
	●	adverse state or federal legislation or regulation that increases the costs of compliance, or adverse findings by a regulator with respect to existing operations, including those related to climate change and hydraulic fracturing;
	●	changes in U.S. GAAP or in the legal, regulatory and legislative environments in the markets in which we operate; and
	●	other factors, many of which are beyond our control.

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

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

Part 1. FINANCIAL INFORMATION

Item 1. Financial Statements

LILIS ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

(UNAUDITED)

	June 30,			December 31,
	2014			2013
Assets
Current assets:
Cash	$	1,449,152		$	165,365
Restricted cash		409,163			504,623
Accounts receivable (net of allowance of $50,000 at June 30, 2014 and December 31, 2013, respectively)		614,504			467,337
Prepaid assets		180,283			195,716
Preferred stock subscriptions receivable		1,853,000			-
Commodity price derivative receivable		-			6,679
Total current assets		4,506,102			1,339,720

Oil and gas properties (full cost method), at cost:
Evaluated properties		68,797,806			68,213,467
Unevaluated acreage, excluded from amortization		18,957,997			18,663,569
Wells in progress, excluded from amortization		5,903,307			1,145,794
Total oil and gas properties, at cost		93,659,110			88,022,830

Less accumulated depreciation, depletion, amortization, and impairment		(46,388,956	)		(45,457,637	)
Total oil and gas properties, net		47,270,154			42,565,193

Other assets:
Office equipment, net		78,386			91,161
Deferred financing costs, net		160,301			294,699
Restricted cash and deposits		215,541			215,541
Total other assets		454,228			601,401
Total assets	$	52,230,484		$	44,506,314

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

LILIS ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

(UNAUDITED)

	June 30,			December 31,
	2014			2013
Liabilities and Shareholders' Equity
Current liabilities:
Accounts payable	$	6,705,112		$	1,932,618
Accrued expenses		1,929,950			1,439,956
Short term loans payable		-			10,662,904
Convertible notes payable, net of discount		6,930,118			-
Total current liabilities		15,565,180			14,035,478

Long term liabilities:
Asset retirement obligation		1,149,216			1,104,952
Term loans payable		14,800,175			8,111,436
Convertible notes payable, net of discount		-			14,586,618
Convertible notes conversion derivative liability		-			1,150,000
Total long-term liabilities		15,949,391			24,953,006

Total liabilities		31,514,571			38,988,484

Commitments and contingencies – Notes 2, 9, 10, 12, 13, and 14

Shareholders’ equity:
Preferred stock, $.0001 par value; stated rate $1,000:10,000,000 authorized, 7,500 and none issued and outstanding as of June 30, 2014 and December 31, 2014, respectively, liquidation preferences of $7,540,681 at June 30, 2014		7,500,000			-
Common stock, $0.0001 par value:100,000,000 shares authorized; 27,513,566 and 19,671,901 shares issued and outstanding as of June 30, 2014 and December 31, 2013, respectively		2,751			1,967
Additional paid in capital		147,472,098			121,451,232
Accumulated deficit		(134,258,968	)		(115,935,369	)
Total shareholders' equity		20,715,913			5,517,830
Total liabilities and shareholders’ equity	$	52,230,484		$	44,506,314

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

LILIS ENERGY, INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

(UNAUDITED)

	Six months ended June 30,						Three months ended June 30,
	2014			2013			2014			2013
Revenues:
Oil sales	$	1,679,609		$	2,316,338		$	979,523		$	1,189,005
Gas sales		189,990			145,202			102,324			38,805
Operating fees		76,881			90,522			42,152			42,019
Realized gain on commodity price derivatives		11,143			19,890			-			-
Total revenues		1,957,623			2,571,952			1,123,999			1,269,829

Costs and expenses:
Production costs		637,583			559,301			221,260			255,454
Production taxes		194,910			278,039			101,230			162,045
General and administrative		5,601,478			2,352,235			2,643,063			1,367,976
Depreciation, depletion and amortization		959,039			1,340,829			570,403			651,175
Total costs and expenses		7,393,010			4,530,404			3,535,956			2,436,650

Loss from operations		(5,435,387	)		(1,958,452	)		(2,411,957	)		(1,166,821	)

Other Income (expenses):
Other income		97			392			44			141
Inducement expense		(6,661,275	)		-			-			-
Convertible notes conversion derivative gain (loss)		850,000			(30,000	)		(300,000	)		(10,000	)
Interest expense		(3,469,458	)		(3,305,678	)		(1,953,127	)		(1,669,519	)
Total other expenses		(9,280,636	)		(3,333,206	)		(2,253,083	)		(1,679,378	)

Net loss		(14,716,023	)		(5,293,738	)		(4,665,040	)		(2,846,199	)
Accretion of Series A Convertible Preferred Stock		(3,566,895	)		-			(3,566,895	)		-
Accrued dividends for Series A Convertible Preferred Stock		(40,681	)					(40,681	)
Net loss attributable to common shareholders		(18,323,599	)		(5,293,738	)		(8,272,616	)		(2,846,199	)
Loss per common share:
Net loss per common share (basic and diluted)		(0.70	)		(0.29	)		(0.30	)		(0.15	)
Weighted average shares outstanding (basic and diluted)		26,292,183			18,551,301			27,498,284			18,668,080

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

LILIS ENERGY, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(UNAUDITED)

	Six months ended
	June 30,
	2014			2013
Cash flows from operating activities:
Net loss	$	(14,716,023	)	$	(5,293,738	)
Adjustments to reconcile net loss to net cash used in operating activities:
Inducement of conversion of convertible debentures		6,661,275			-
Common stock issued for convertible note interest		148,129			270,032
Common stock issued for financing cost		686,273			-
Common stock for services and compensation		1,177,039			799,567
Amortization of deferred financing costs		134,398			354,493
Change in fair value of convertible notes conversion derivative		(850,000	)		30,000
Accretion of debt discount		895,369			1,128,442
Depreciation, depletion, amortization and accretion of asset retirement obligation		989,126			1,333,922
Changes in operating assets and liabilities:
Accounts receivable		(147,166	)		362,380
Restricted cash		95,460			86,512
Other assets		431,003			(43,084	)
Accounts payable and other accrued expenses		30,293			(288,384	)
Net cash used in operating activities		(4,464,824	)		(1,256,858	)

Cash flows from investing activities:
Acquisition of undeveloped acreage		(305,000	)		-
Drilling capital expenditures		(109,057	)		(85,371	)
Sale of oil and gas properties		-			640,000
Additions to oil and gas properties		(24,030	)		(732,061	)
Additions to office equipment		(768	)		(23,276	)
Investments in operating bonds		-			(106	)
Net cash used in investing activities		(438,855	)		(200,814	)

Cash flows from financing activities:
Proceeds from issuance of common stock		5,327,687			1,161,912
Debt issuances		1,000,000			-
Proceeds from issuance of Series A Convertible Preferred Stock		4,940,992			-
Repayment of debt		(5,081,213	)		(44,368	)
Net cash provided by financing activities		6,187,466			1,117,544

Change in cash and cash equivalents		1,283,787			(340,128	)
Cash and cash equivalents at beginning of period		165,365			970,035

Cash and cash equivalents at end of period	$	1,449,152		$	629,907

Non-cash transactions:
Additions to drilling capital expenditures from an increase in accounts payable and other accrued expenses	$	5,198,193		$	-
Stock issued for payment on Convertible Debentures	$	8,744,836		$	-
Preferred stock subscription receivable	$	1,853,000		$	-

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

LILIS ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

AS OF JUNE 30, 2014

(UNAUDITED)

NOTE 1 – ORGANIZATION

Lilis Energy, Inc. (“Lilis”, “Lilis 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 84,000 net acres. Lilis drills, operates and produces oil and natural gas wells through the Company’s land holdings located in Wyoming, Colorado, and Nebraska.

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

NOTE 2 – LIQUIDITY

As of June 30, 2014, the Company had $14.80 million outstanding under its term loans with Hexagon, LLC (“Hexagon”) and $6.93 million outstanding under its 8% Senior Secured Convertible Debentures (the “Debentures”). Both the term loans and the Debentures were to mature on May 16, 2014. In June 2014, the maturity date under the Debentures was extended to January 15, 2015. In May 2014, Hexagon extended the maturity of the Company’s term loan to August 15, 2014, and in September 2014, the Company entered into a settlement agreement with Hexagon whereby the total principal and interest outstanding under the term loans was settled. (See Note 14- Subsequent Events for a more detailed discussion of the transactions consummated with respect to the Hexagon term loans.) While the settlement of the Hexagon term loans eliminated a significant debt burden to the Company, it also resulted in the assignment of several producing properties, which will affect the Company’s operating revenue.

Since March 31, 2014, the Company has consummated the following other transactions related to its liquidity: (i) on May 30, 2014 the Company consummated a private placement to accredited investors of its Series A 8% Convertible Preferred Stock (the “Series A Preferred”) and three-year warrants to purchase Common Stock equal to 50% of the number of shares issuable upon full conversion of the Series A Preferred for gross proceeds of $7.50 million; (ii) on June 6, 2014, the holders of the remaining Debentures agreed to further extend the maturity date under the Debentures from August 15, 2014 to January 15, 2015; (iii) on June 6, 2014, T.R. Winston & Company, LLC (“T.R. Winston”) executed an agreement that they or a designee will purchase an additional $15.0 million of preferred stock under the same terms of the Series A Preferred Stock within 90 days; furthermore, on November 25, 2014, T.R. Winston has reaffirmed and extended their commitment for 90 days or until February 22, 2015. In November 2014, a controlling member of T.R. Winston was elected to the Company’s board of directors. T.R. Winston has informed the Company that there is a possible conflict between being the Company’s investment banker and board member, and as a result will refrain from acting as the Company’s investment banker; and (iv) on October 6, 2014, the Debenture holders agreed to waive any event of default under the Debentures that may have occurred prior to the date of the waiver (including, without limitation, any default relating to the Company’s indebtedness to Hexagon), and to rescind and annul any acceleration or right to acceleration that may have been triggered thereby. (See Note 14 – Subsequent Events.)

As of November 24, 2014, the Company has $1.00 million in cash on hand and is currently producing approximately 70 BOE a day from eight economically producing wells. Furthermore, as of the date of this report, the Company has a negative working capital of approximately $8.25 million, including $6.93 million in convertible debentures due as of January 15, 2015, and $0.50 million within the accrued liabilities for convertible debenture interest. The Company is negotiating with the holders of the convertible debentures to pay the interest currently due with restricted shares of common stock, and extension of the maturity date of the debentures.

The Company will require additional capital to satisfy its obligations, including repayment of the Debentures in January 2015; to fund its current drilling commitments and acquisition and capital budget plans; to help fund its ongoing overhead; and to provide additional capital to generally improve its working capital position. We anticipate that such additional funding will be provided by a combination of capital raising activities, including borrowing transactions, the sale of additional debt and/or equity securities, the sale of certain assets and by the development of certain of the Company’s undeveloped properties via arrangements with joint venture partners. If we are not successful in obtaining sufficient cash to fund the aforementioned capital requirements, we would be required to curtail our expenditures, and may be required to restructure our operations, sell assets on terms which may not be deemed favorable and/or curtail other aspects of our operations, including deferring all or portions of our capital budget. There is no assurance that any such funding will be available to the Company on acceptable terms, if at all.

NOTE 3 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

The accompanying financial statements were prepared by Lilis in accordance with generally accepted accounting principles (“GAAP”) in the United States. The financial statements reflect all normal recurring adjustments which are, in the opinion of management, necessary to provide a fair statement of the results of operations and financial position.

Use of Estimates

The preparation of financial statements in conformity with US GAAP requires us to make a number of estimates and assumptions relating to the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ significantly from those estimates. Management evaluates estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic and commodity price environment.

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 undeveloped properties, as well as valuation of common stock used in various issuances, options and warrants, and estimated derivative liabilities.

Net Loss per Common Share

Earnings (losses) per common share are computed based on the weighted average number of common shares outstanding during the period presented. Diluted earnings (losses) per share are computed using the weighted-average number of common shares outstanding plus the number of common shares that would be issued assuming exercise or conversion of all potentially dilutive common shares. Potentially dilutive securities, such as conversion derivatives and stock purchase warrants, are excluded from the calculation when their effect would be anti-dilutive. As of June 30, 2014, a total of 16,080,139 and 3,364,016 shares underlying warrants and convertible debentures, respectively, have been excluded from the diluted share calculations as they were anti-dilutive as a result of net losses incurred. Accordingly, basic shares equal diluted shares for all periods presented.

Recent Accounting Pronouncements

In April 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update No. 2014-08: Presentation of Financial Statements (“Topic 205”) and Property, Plant, and Equipment (“Topic 360”): Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity (“ASU 2014-08”). ASU 2014-08 changes the criteria for reporting discontinued operations while enhancing disclosures in this area and is effective for annual and interim periods beginning after December 15, 2014. Early adoption is permitted for disposals or for assets classified as held for sale that have not been reported in previously issued financial statements. We elected to early adopt ASU 2014-08 on a prospective basis, and the adoption did not have any impact on our financial statements.

In May 2014, the FASB issued Accounting Standards Update No. 2014-09 (“ASU 2014-09”), which creates Topic 606, Revenue from Contracts with Customers, and supersedes the revenue recognition requirements in Topic 605, Revenue Recognition, including most industry-specific revenue recognition guidance throughout the Industry Topics of the Codification. In addition, ASU 2014-09 supersedes the cost guidance in Subtopic 605-35, Revenue Recognition—Construction-Type and Production-Type Contracts, and creates new Subtopic 340-40, Other Assets and Deferred Costs— Contracts with Customers. In summary, the core principle of Topic 606 is that an entity recognizes revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. Additionally, ASU 2014-09 requires enhanced financial statement disclosures over revenue recognition as part of the new accounting guidance. The amendments in ASU 2014-09 are effective for annual reporting periods beginning after December 15, 2016, including interim periods within that reporting period, and early application is not permitted. We are currently evaluating the provisions of ASU 2014-09 and assessing the impact, if any, it may have on our financial position and results of operations.

NOTE 4 – PREFERRED STOCK SUBSCRIPTION RECEIVABLE

In May 2014, the Company consummated a private placement to accredited investors of its Series A 8% Convertible Preferred Stock (the “Series A Preferred”) and three-year warrants to purchase Common Stock equal to 50% of the number of shares issuable upon full conversion of the Series A Preferred, for gross proceeds of $7.50 million (the “May 2014 Private Placement”). As of June 30, 2014, $1.85 million of subscriptions were not funded. However, as of September 2014, the full $7.50 million had been received. (See Note 12- Preferred Stock.)

NOTE 5 – OIL AND GAS PROPERTIES

In April 2014, the Company transferred $0.47 million from wells-in-progress to oil and gas properties for one of its wells in Northern Wattenberg within Weld County, Colorado.

The Company has accrued expenses related to development of certain wells in the Northern Wattenberg field with a joint venture partner which is currently being disputed. Upon resolution of that dispute, the Company may lose all or a portion of the value of its ownership interests in the wells in question. Once the status of the wells is finally determined, the Company will transfer the wells and the applicable reserves to the full cost pool.

On September 2, 2014, the Company assigned to Hexagon all of the collateral securing the Company’s term loans (the “Hexagon Collateral”), which consisted of 30,000 net acres and several economic wells which secured several Proved Development Producing reserves and several Proved Undeveloped reserves following the assignment of collateral to Hexagon, the Company retained 84,000 net acres in the DJ Basin and various producing wells. (see Note-14 Subsequent Events).

NOTE 6 – WELLS IN PROGRESS

As of June 30, 2014, the Company had $5.90 million in wells in progress compared to $1.15 million as of December 31, 2013. The June 30, 2014 amount relates to accrued but unfunded accrued expenses on certain wells in the Northern Wattenberg field with a joint venture partner, which is currently being disputed. Upon resolution of that dispute, the Company may lose all or a portion of its ownership interests in the wells, and the value of the associated reserves in question. Once the status of the wells is finally determined, the Company will transfer the wells and the applicable reserves to the full cost pool.

In April 2014, the Company transferred $0.47 million from wells in progress to oil and gas properties from another property in Northern Wattenberg. The well is producing.

The Company has accrued $0.50 million of costs from wells in progress due to a dispute between two royalty interest owners unrelated to the Company. Once the dispute is resolved, the Company expects to retain its original working interest.

NOTE 7 - DERIVATIVES

We are exposed to fluctuations in crude oil prices, natural gas liquids, and natural gas prices for all of our production. In order to mitigate the effect of commodity price volatility with our crude oil and enhance the predictability of cash flows relating to the marketing of our crude oil, we may enter into crude oil price hedging arrangements with respect to a portion of our expected production.

As of June 30, 2014, the Company did not maintain any commodity derivatives.

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

	For the				For the
	Six Months Ended				Three Months Ended
	June 30,				June 30,
	2014		2013		2014		2013
Realized gain on oil price hedges	$	11	$	20	$	-	$	-

Realized gains and losses are recorded as income or expenses in the periods during which applicable contracts mature and settle. (See Note 8 - Fair Value of Financial Instruments.)

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 market place.

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

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

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

Convertible Debentures Conversion Derivative Liability

In February 2011, the Company issued in a private placement $8.40 million aggregate principal amount of three year Debentures to 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 in Debentures outstanding as of December 31, 2012. During the year ended December 31, 2013, the Company issued an additional $2.20 million of Debentures, for a total Debenture amount of $15.58 million. On January 31, 2014, the Company entered into a Debenture Conversion Agreement (the "Conversion Agreement") with all of the holders of the Debentures. Pursuant to the terms of the Agreement, $9.00 million in Debentures was converted at a price of $2.00 per share of the Company’s common stock, par value $0.0001 (“Common Stock”). In addition, the Company issued warrants to the Debenture holders to purchase one share of Common Stock at an exercise price equal to $2.50 per share, equal to the number of shares of Common Stock issued in connection with conversion of the Debentures. The Company’s Chief Executive Officer (“CEO”) is an indirect owner of a group which converted approximately $0.22 million of Debentures.

As of June 30, 2014, the Company had $6.93 million in remaining Debentures which are convertible at any time at the holders’ option into shares of Common Stock at $2.00 per share, subject to certain 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 (see Note 9-Loan Agreements).

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

June 30, 2014:

	Level 1		Level 2		Level 3			Total
Liabilities
Executive employment agreements compensation	$	-	$	-	$	(325	)	$	(325	)
Convertible debentures conversion derivative liability	$	-	$	-	$	(300	)	$	(300	)
Total liability, at fair value	$	-	$	-	$	(625	)	$	(625	)

December 31, 2013:

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

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

The following table provides a summary of changes in fair value of the Company’s Level 3 financial assets and liabilities for the six months ended June 30, 2014 (in thousands):

Beginning balance, December 31, 2013	$	(1,295	)
Executive compensation liability		(180	)
Convertible debentures conversion derivative gain		850
Ending balance, June 30, 2014	$	(625	)

The Company did not have any transfers of assets or liabilities between Level 1, Level 2 or Level 3 of the fair value measurement hierarchy during the three and six months ended June 30, 2014 or 2013.

NOTE 9 – LOAN AGREEMENTS

Our total outstanding debt as of June 30, 2014 consisted of the following:

(thousands, except percentages)	June 30, 2014						December 31, 2013
	Debt			Interest Rate			Debt			Interest Rate
10% Term Notes, maturity August 15, 2014 (2)(3)	$	14,800			10	%	$	18,774			10	%
8% Convertible Debentures, maturity January 15, 2015 (1)(4)(5)		6,728			8	%		15,580			8	%
Total		21,528						34,354
Unamortized discount		(98	)					(993	)
Total debt, net of discount		21,430						33,361
Less: amount due within one year		(6,630	)					(10,663	)
Long-term debt due after one year	$	14,800					$	22,698

(1) The Debentures contain cross collateralization and cross default provisions and are collateralized by mortgages against the majority of the Company’s developed and undeveloped leasehold acreage. In accordance with the cross-default provision under the Debentures, as of August 15, 2014 the Company was in default due to its default under the Hexagon term loans. In October 2014, the Debenture holders waived their right to declare a default on that basis. The Debentures mature in January 2015. (See Note 14 - Subsequent Events.)

(2) The Hexagon loan agreements contained certain non-financial covenants, with which the Company was in substantial compliance as of June 30, 2014.

(3) Amount represents three separate loan agreements with Hexagon in January, March and April 2010, each of which contained a cross-default provision and which together were secured by a significant amount of the Company’s developed and undeveloped leasehold acreage. On September 2, 2014, the Company entered into the Final Settlement Agreement, pursuant to which the Company assigned the Hexagon Collateral to Hexagon and issued to Hexagon an additional $2 million in 6% Redeemable Preferred. As a result, the Hexagon loan obligations were deemed satisfied, and Hexagon released the related mortgages. Therefore, the loan obligations are classified as a long-term liability for the period ended June 30, 2014. (See Note 14 -Subsequent Events.)

(4) Debentures are convertible at any time at the holders' option into shares of Common Stock at $2.00 per share. The balance of the Debentures may be converted to Common Stock on the terms provided in the Conversion Agreement (including the terms related to the warrants); subject to receipt of shareholder approval as required by NASDAQ continued listing requirements.

(5) Interest payments have historically been paid in Common Stock; interest is calculated at an annualized rate of 8% and is payable quarterly on each May 15, August 15, November 15 and February 15 in cash or, at the Company's option (subject to certain conditions), 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.

Term Loans

As of June 30, 2014, the Company had three term loans with Hexagon, its senior lender, with an aggregate outstanding principal amount of approximately $14.80 million. The loans required the Company to make monthly payments of $0.23 consisting of interest and principal. On May 19, 2014, the Company received an extension from Hexagon of the maturity date under its term loans, from May 16, 2014 to August 15, 2014.In connection with the extension, the Company paid a forbearance fee of $0.25 million which was recorded as deferred financing cost and amortized over the extension period of the term loans. The Company amortized $0.12 million of deferred financing costs into interest expense during the three and six months ended June 30, 2014.

On May 30, 2014, the Company entered into the First Settlement Agreement with Hexagon, which provided for the settlement of all amounts outstanding under the term loans. In connection with the execution of the First Settlement Agreement, the Company made initial cash payment of $5.0 million. The First Settlement Agreement required the Company to make an additional cash payment of $5.0 million (the “Second Cash Payment”) by August 15, 2014, and at that time issue to Hexagon (i) a two-year $6.0 million unsecured note (the “Replacement Note”), bearing interest at an annual rate of 8%, requiring principal and interest payments of $90,000 per month, and (ii) 943,208 shares of unregistered Common Stock (the “Shares”). The parties also agreed that if the Second Cash Payment was not made by June 30, 2014, an additional $1.0 million in principal would be added to the Replacement Note, and if the Replacement Note was not retired by December 31, 2014, the Company would issue an additional 1.0 million shares of Common Stock to Hexagon.

The Company did not make the Second Cash Payment by August 15, 2014.

On September 2, 2014, the Company entered into the Final Settlement Agreement which replaced the First Settlement Agreement, pursuant to which, in exchange for full extinguishment of all amounts payable under the term loans (approximately $14.03 million in principal and interest as of the settlement date), the Company assigned Hexagon the Hexagon Collateral, which consisted of 30,000 net acres including several economic wells which secured properties with Proved Development Producing reserves and Proved Undeveloped reserves, and issued to Hexagon the Redeemable Preferred. (See Note 14 - Subsequent Events.)

Convertible Debentures Payable

In separate private placement transactions between February 2011 and October 2013, the Company issued an aggregate of approximately $15.6 million of Debentures, secured by mortgages on several of its properties. The Debentures are currently convertible at the holders' option into shares of Common Stock at $2.00 per share, subject to certain adjustments, and bear interest at an annualized rate of 8%, payable quarterly on each May 15, August 15, November 15 and February 15 in cash or, at the Company's option subject to certain conditions, in shares of Common Stock.

On January 31, 2014, the Company entered into a "Conversion Agreement" with all of the holders of the Debentures. Pursuant to the terms of the Conversion Agreement, $9.00 million in Debentures was converted by the holders to common stock at a conversion price of $2.00 per share of common stock. In addition, the Company issued warrants to the Debenture holders to purchase one share of Common Stock for each share issued in connection with conversion of the Debentures, at an exercise price equal to $2.50 per share. The Company’s CEO is an indirect owner of a group which converted approximately $0.22 million of Debentures pursuant to the Conversion Agreement. As of June 30, 2014, the Company had $6.93 million remaining Debentures which are convertible at any time at the holders’ option into shares of Common Stock at $2.00 per share, subject to certain adjustments, including the requirement to reset the conversion price based upon any subsequent equity offering at a lower price per share amount.

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

We periodically engage a third party valuation firm to complete a valuation of the conversion feature associated with the Debentures. This valuation resulted in an estimated derivative liability as of June 30, 2014 and December 31, 2013 of $0.30 million and $1.15 million, respectively (See Note 8 - Fair Value of Financial Instruments).

The Company’s failure to meet its obligations under the First Settlement Agreement with Hexagon constituted a default under the term loans, which in turn triggered an event of default under the Debentures. However, the holders of the Debentures have waived their right to declare a default in respect of that matter.

Interest Expense

For the three months ended June 30, 2014 and 2013, the Company incurred interest expense of approximately $1.95 million and $1.67 million, respectively, of which approximately $1.47 million and $1.04 million is classified as non-cash interest expense, respectively. The details of the non-cash interest expense are as follows: (i) amortization of the deferred financing costs of $0.07 million, (ii) accretion of the convertible debentures payable discount of $0.23 million, (iii) accrued interest for term note loan fees of $1.00 million and (iv)amortization of forbearance fees of $0.12 million. Cash interest is comprised of, term loan cash expense payment. The increase in interest expense was primarily attributable to fees for not paying a designated amount to the term note holder. Other cash interest increased due to $0.25 million forbearance fees paid to Hexagon, which is being amortized over the life of the extension.

NOTE 10 - COMMITMENTS AND CONTINGENCIES

Environmental and Governmental Regulation

At June 30, 2014, there were no known environmental or regulatory matters which are reasonably expected to result in a material liability to the Company. Many aspects of the oil and gas industry are extensively regulated by federal, state, and local governments in all areas in which the Company has operations. Regulations govern such things as drilling permits, environmental protection and air emissions/pollution control, spacing of wells, the unitization and pooling of properties, reports concerning operations, land use, royalty rates and various other matters, including taxation. Oil and gas industry legislation and administrative regulations are periodically changed for a variety of political, economic, and other reasons. As of June 30, 2014 the Company had not been fined or cited for any violations of governmental regulations that would have a material adverse effect upon the financial condition of the Company.

Legal Proceedings

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

Parker v. Tracinda Corporation, Denver District Court, Case No. 2011CV561. In November 2012, the Company filed a motion to intervene in garnishment proceedings involving Roger Parker, the Company’s former Chief Executive Officer and Chairman. The Defendant has served various writs of garnishment on the Company to enforce a judgment against Mr. Parker seeking, among other things, shares of unvested restricted stock. The Company has asserted rights to lawful set-offs and deductions in connection with certain tax consequences, which may be material to the Company. As a result of bankruptcy proceedings filed by Mr. Parker, the garnishment proceedings were stayed by Court Order dated January 30, 2013. Judgment was entered by the trial court in favor of defendant Tracinda Corp. (“Tracinda”) on Tracinda’s counterclaim for breach of a promissory note before Mr. Parker’s bankruptcy. Although the trial court found that Tracinda had breached its pledge agreement with Mr. Parker, the court ruled Tracinda was not liable on Mr. Parker’s breach of contract claim based on several defenses. Mr. Parker appealed the judgment to the Colorado Court of Appeals (Case No. 2012CA2096) and the appellate proceedings were also stayed by Order of the Colorado Court of Appeals dated April 1, 2013. Stay of the state court proceedings was lifted by Bankruptcy Court Order dated April 12, 2013. On October 17, 2013, the Colorado Court of Appeals affirmed in part, reversed in part (reversing judgment on Mr. Parker’s contract claim) and remanded the case to the trial court with directions to determine damages. At this stage, we cannot express an opinion as to the probable outcome of this matter, although a determination of the issues relating to rights in the unvested stock is expected to be made in the Adversary Proceeding currently pending in the United States Bankruptcy Court for the District of Colorado (described below).

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 in an Adversary Proceeding (Adversary No. 13-01301 EEB) against the Company and Roger Parker in connection with the personal bankruptcy proceedings of Roger Parker, alleging that the Company improperly failed to remit to Tracinda certain property in connection with various writs of garnishment issued by the Denver District Court (discussed above). Tracinda seeks, among other things, a declaratory judgment stating that Tracinda is entitled to such property allegedly subject to such writs. The Company filed an answer to this complaint on July 10, 2013. The Bankruptcy Court entered an Order dated August 12, 2014, holding the case in abeyance pending resolution of the state-court appeal of the Denver District Court lawsuit. On October 2, 2014, the Bankruptcy Court entered a Minute Order declaring that it would issue an order in due course continuing the abeyance or ruling on pending motions for summary judgment. A trial date has not been set.

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

NOTE 11 - SHAREHOLDERS’ EQUITY

Common Stock

As of June 30, 2014, the Company had 100,000,000 shares of Common Stock and 10,000,000 shares of preferred stock authorized, of which 27,513,566 shares of Common Stock and 7,500 preferred shares were issued and outstanding.

During the six months ended June 30, 2014, the Company issued 7,863,166 shares of Common Stock, including 4,500,000 shares in connection with the Debenture Conversion Agreement, 250,000 for finance expense to complete the conversion of convertible debentures, 3,037,500 for the stock issued for the January 2014 Private Placement, 229,150 shares as restricted stock grants to employees, board members, or consultants (see Note 13 – Share Based and Other Compensation) and 7,500 shares of Series A Preferred (see Note 12 - Preferred Stock).

Convertible Debenture Interest

During the six months ended June 30, 2014, the Company did not issue any shares as interest in connection with the Debentures, other than the shares issued in connection with the Debenture Conversion Agreement. As of June 30, 2014, the Company accrued $0.34 million of non-cash interest for the Debenture interest, which the Company anticipates paying with shares upon conversion of the Debentures.

Debenture Conversion Agreement

On January 31, 2014, the Company entered into a Debenture Conversion Agreement pursuant to which $9.00 million in Debentures were converted into Common Stock. T.R. Winston & Company, LLC (“T.R. Winston”) acted as the investment banker for the Conversion Agreement and received compensation of $0.45 million, which represented 5% of the $9.0 million. (See Note 9 – Loan Agreements.)

May 2014 Private Placement

On May 30, 2014, the Company completed a private placement of 7,500 shares of Series A Preferred, along with detachable warrants to purchase up to 1,167,013 shares of Common Stock at an exercise price of $2.89 for aggregate proceeds of $7.5 million (See Note 12 - Preferred Stock)

Consulting Agreement

In January 2014, the Company entered into a consulting agreement with a public relations company. The agreement provided for the issuance by the Company of 350,000 warrants and 90,000 shares of restricted stock. Using a Black Scholes lattice model, the warrants, valued at $0.28 million in the aggregate on the date of grant, vested immediately, and the restricted stock, using the price at issuance, vested on a monthly basis until August 1, 2014, when the agreement was terminated. During the six months ended June 30, 2014, the Company recognized a total expense of $0.41 million for the restricted stock issued pursuant to the consulting agreement.

Warrants

A summary of warrant activity for the six months ended June 30, 2014 is presented below:

	Warrants		Weighted- Average Exercise Price
Outstanding at December 31, 2013		6,773,913	$	4.40
Granted-January 2014 private placement		3,012,500		2.50
Granted-debenture conversion agreement		4,500,011		2.50
Granted –May 2014 preferred private placement		1,556,017		2.89
Granted-other		663,840		2.88
Exercised, forfeited, or expired		-		-
Outstanding at June 30, 2014		16,506,281	$	3.33

The weighted average remaining contract value life as of June 30, 2014 was 2.16 years, and 1.56 years as of December 31, 2013.

NOTE 12 –PREFERRED STOCK

Series A 8% Convertible Preferred Stock

On May 30, 2014, the Company consummated a private placement of 7,500 shares of our Series A Preferred, along with detachable warrants to purchase up to 1,167,013 shares of Common Stock at an exercise price of $2.89, for aggregate proceeds of $7.5 million. The Series A Preferred has a par value of $0.0001 per share, a stated value of $1,000 per share and a conversion price of $2.41, subject to adjustment under certain circumstances. Except as otherwise required by law, holders of Series A Preferred shall not be entitled to voting rights. The holders of the Series A Preferred are entitled to receive a dividend payable, at the election of the Company (subject to certain conditions as set forth in the Certificate of Designations), in cash or shares of Common Stock, at a rate of 8% per annum. The Series A Preferred is convertible at any time at the option of the holders, or at the Company’s discretion when Common Stock trades above $7.50 for ten consecutive days with a daily dollar trading volume above $300,000. In addition, the Company has the right to redeem the shares of Series A Preferred, along with any accrued and unpaid dividends, at any time, subject to certain conditions as set forth in the Certificate of Designations. In addition, holders of the Series A Preferred can require the Company to redeem the Series A Preferred upon the occurrence of certain triggering events, including (i) failure to timely deliver shares of Common Stock after valid delivery of a notice of conversion by the holder; (ii) failure to have available a sufficient number of authorized and unreserved shares of Common Stock to issue upon conversion; (iii) the occurrence of certain change of control transactions; (iv) the occurrence of certain events of insolvency; and (v) the ineligibility of the Company to electronically transfer its shares via the Depository Trust Company or another established clearing corporation.

As of June 30, 2014, the Company had received gross proceeds of $5.65 million from the May 2014 Private Placement, for which the Company paid $0.71 million in fees for net proceeds of $4.94 million. As of June 30, 2014, the Company immediately recognized, since the preferred shares are convertible at any time after the date of issuance, an accretion expense of $3.57 million and a private preferred subscription receivable of $1.85 million. The subscription receivable was fully funded in September 2014. As of June 30, 2014, the Company has accrued a cumulative dividend for $.04 million which is payable as of July 1, 2014 and funded August 2014.

The table below summarizes the primary characteristics of the Series A Preferred as of June 30, 2014:

Total shares outstanding as of June 30, 2014		7,500
Conversion price	$	2.41
Shares of Common Stock issuable upon conversion		3,112,033
Warrants issued		1,556,017
Fees paid to placement agent	$	706,000
Aggregate value of warrants issued (1)	$	1,321,526
Beneficial conversion feature (2)	$	1,539,369

(1) The intrinsic value of the warrant was calculated at $1.60 million utilizing the Black Scholes Lattice Model. The gross proceeds of $7,500,000 were allocated to the preferred stock and the warrants on a relative fair value basis, resulting in an allocation to the warrants of $1,321,526.

(2) The Company considered the beneficial ownership features of the Series A Preferred shares and determined that since the conversion price is $2.41 along with a detachable warrant, the Company recorded a beneficial conversion feature of $1.54 million, after considering the discount resulting from the proceeds allocated to the warrants

NOTE 13 - SHARE BASED AND OTHER COMPENSATION

Share-Based Compensation

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

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 six months ended June 30, 2014, the Company granted 229,150 shares of restricted common stock to employees, directors and consultants, and 400,000 shares of restricted common stock and stock options that had previously been granted under the EIP were forfeited in connection with the termination of certain employees, directors and consultants.

The Company recognized a stock compensation expense, for the six months ended June 30, 2014, of approximately $0.20 million and a credit to expense of $0.11 million for cancelled shares for the six months ended June 30, 2014.

Stock Options

A summary of stock options activity for the six months ended June 30, 2014 is presented below:

	Stock Options
Outstanding at December 31, 2013		3,800,000
Granted		1,500,000
Exercised, forfeited, or expired		(400,000	)
Outstanding at June 30, 2014		5,100,000

In June 2013, the Company entered into employment agreements with W. Phillip Marcum and A. Bradley Gabbard for non-cash compensation which consisted of each individual receiving 300,000 stock options of which 100,000 vested immediately and 200,000 were scheduled to vest over the following 2 years. The options had a five-year life and an exercise price of $1.60. The 600,000 stock options were valued at $0.52 million on date of grant. During the year ended December 31, 2013, the Company recognized $0.27 million as non-cash compensation expense and $0.25 million to be amortized over the remaining vesting period. In April 2014, Mr. Marcum resigned from his role as CEO, entering into a severance agreement pursuant to which, among other things, the 200,000 options that had been unvested at the time of his termination became immediately vested. The Company reversed the 200,000 unvested options valued at $0.07 million, and reissued fully vested options, which it valued utilizing the Black Scholes Lattice model at $0.41 million.

In May 2014, in connection with his resignation as Chief Financial Officer (“CFO”), A. Bradley Gabbard forfeited 200,000 options that were unvested at the time of his termination. The Company recorded a reversal of $0.08 million. Both Mr. Marcum and Mr. Gabbard forfeited their respective 68,750 shares of unvested restricted stock, for which the Company recorded a reversal of $0.10 million.

Employment Agreements

Executive Compensation for Abraham Mirman

The Company is party to an employment agreement with its CEO, Abraham Mirman (the “Mirman Agreement”). The Mirman Agreement, as amended, provides for an incentive bonus package that, depending upon the relative performance of the Company’s Common Stock compared to the performance of stocks of certain peer group companies as measured from Mr. Mirman’s initial date of employment through December 31, 2015, may result in a cash bonus payment to Mr. Mirman of up to 3.0 times his base salary. In addition, in connection with the Mirman Agreement, Mr. Mirman was granted options to purchase up to 2,000,000 shares of Common Stock, subject to vesting when the value of the Common Stock reaches certain thresholds. The incentive bonus is recorded as a liability and will be valued every quarter. The Company engaged a third party to complete a valuation of this conversion liability. The Company recorded an expense of $0.03 million for the six months ended June 30, 2014, which resulted in a total liability of $0.03 million. We valued the option bonus and stock option grant utilizing a third party valuation expert and valued the option bonus and stock option grant for $0.65 million, to be amortized over the term of the employment contract. During the three months and six months ended June 30, 2014, the Company amortized $0.13 million and $0.25 million, respectively. (See Note 12-Share Based and Other Compensation.) As of October 7, 2014, Mr. Mirman reached the $30.0 million recapitalization provision within his employment contract which immediately triggered the vesting of 600,000 options.

Board of Directors

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

In June 2013, each director also agreed to receive 31,250 shares of restricted Common Stock in lieu of a portion of his cash compensation, to vest on April 15, 2014. During the three and six months ended June 30, 2014, the Company recognized $0.05 million and $0.11 million, respectively, in compensation expense related to this issuance.

Robert A. Bell

In April 2014, in connection with the appointment of Robert A. Bell as our President and Chief Operating Officer, the Company entered an employment agreement with Mr. Bell, which provided for the issuance of 100,000 shares of Common Stock, of which 1/3 vested immediately and the balance was scheduled to vest over three years, subject to certain conditions. In addition, the employment agreement provided that Mr. Bell would receive an equity incentive bonus consisting of a non-statutory stock option to purchase up to 1,500,000 shares of Common Stock subject to Mr. Bell’s continued employment and the Company’s achievement of certain pre-defined production thresholds. The Company received independent valuations of the i) option bonus to purchase 1,500,000 shares of Common Stock; and ii) the incentive bonus. The option to purchase 1,500,000 shares was valued at $1.29 million to be amortized over the life of the employment agreement. During the three months ended June 30, 2014, the Company recorded an expense for the incentive bonus of $0.07 million, and recorded a liability for the incentive bonus of $0.30 million. On August 1, 2014, in connection with the termination of Mr. Bell’s employment, the Company entered into a separation agreement with Mr. Bell. (See Note 14 - Subsequent Events.)

Separation Agreements

W. Phillip Marcum

In April 2014, the Company entered into a separation agreement (the “Marcum Agreement”) with W. Phillip Marcum in connection with his resignation from his positions with the Company.

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

A summary of restricted stock grant activity for the six months ended June 30, 2014 is presented below:

	Shares
Balance outstanding at December 31, 2013		2,024,375
Granted		212,750
Vested		(150,459	)
Expired/ cancelled		(174,585	)
Balance outstanding at June 30, 2014		1,912,081

As of June 30, 2014, total unrecognized compensation cost related to unvested stock grants was approximately $0.58 million, which is expected to be recognized over a weighted-average remaining service period of 3 years.

Other Compensation

We sponsor a 401(k) savings plan. All regular full-time employees are eligible to participate. We make contributions to match employee contributions up to 5% of compensation deferred into the plan. The Company made cash contributions of $0.01 million and $0.02, respectively, for the three and six months ended June 30, 2014.

NOTE 14- SUBSEQUENT EVENTS

Separation from Employment of Robert A. Bell

On August 1, 2014, the Company entered into a separation agreement with Robert A. Bell, its former president and chief operating officer (the “Bell Agreement”). Pursuant to the Bell Agreement, the Company paid to Mr. Bell a lump-sum payment of $100,000 in cash and issued to Mr. Bell 66,667 shares of Common Stock, in addition to satisfying the Company’s outstanding obligation to pay Mr. Bell $0.10 million in cash and issue to Mr. Bell 33,333 shares of Common Stock. The Bell Agreement also contains certain mutual covenants, and reaffirms the survival of certain confidentiality provisions contained in Mr. Bell’s employment agreement dated as of May 1, 2014 between the Company and Mr. Bell. In addition, Mr. Bell and the Company each mutually released and discharged all known and unknown claims against the other and their respective representatives that they had or presently may have, including claims relating to Mr. Bell’s employment.

Final Settlement of Hexagon Debt

Until September 2014, the Company was party to three separate credit agreements with Hexagon, LLC (“Hexagon”): (i) a Credit Agreement, dated as of January 29, 2010, providing for a secured term loan in the original principal amount of $4.5 million (as amended, modified, supplemented, substituted or replaced, “Credit Agreement No. 1”); (ii) a Credit Agreement, dated as of March 25, 2010, providing for a secured term loan in the original principal amount of $6.0 million (as amended, modified, supplemented, substituted or replaced, “Credit Agreement No. 2”); and (iii) a Credit Agreement, dated as of April 14, 2010, providing for a term loan in the original principal amount of $15.0 million (as amended, modified, supplemented, substituted or replaced, “Credit Agreement No. 3” and, together with Credit Agreement No. 1 and Credit Agreement No. 2, the “Credit Agreements”).

The Credit Agreements were scheduled to mature on May 16, 2014. On May 19, 2014, the Company received extensions from Hexagon of the maturity dates under the Credit Agreements to August 15, 2014, and on May 30, 2014, the Company and Hexagon entered into an agreement providing for the settlement of all amounts outstanding under the term loans, in exchange for the issuance to Hexagon of a two-year $6.0 million unsecured 8% note and 943,208 shares of the Company’s unregistered common stock and two cash payments of $5.0 million each, the first of which was paid concurrently with execution and the second of which was to be made by August 15, 2014 (the “First Settlement Agreement”).

The Company did not make the second $5.0 million payment on August 15, 2014, and on September 2, 2014, the Company entered into the Final Settlement Agreement with Hexagon to settle all amounts payable by the Company pursuant to the Credit Agreements. Pursuant to the Final Settlement Agreement, in exchange for full extinguishment of all amounts payable, approximately $14.8 million in principal and interest, as of June 30, 2014 pursuant to the Credit Agreements and related promissory notes, the Company assigned to Hexagon all of the Hexagon Collateral which consisted of 30,000 net acres and several economical wells which secured several Proved Development Producing reserves and several Proved Undeveloped reserves, and issued to Hexagon $2.0 million in Redeemable Preferred. The Redeemable Preferred bears a 6% dividend per annum, payable quarterly, and is redeemable at face value (plus any accrued and unpaid dividends) at any time at the Company’s option, or at Hexagon’s option upon the Company’s achievement of certain production and reserves thresholds. The Redeemable Preferred is not convertible into Common Stock or any other securities of the Company. Except as otherwise required by law, holders of the Redeemable Preferred shall not be entitled to voting rights. The Final Settlement Agreement also prohibits Hexagon from selling or otherwise disposing of any shares of Common Stock held by Hexagon until February 29, 2016. In addition, pursuant to the Final Settlement Agreement, Hexagon and the Company each mutually released and discharged all known and unknown claims against the other and their respective representatives that they had or presently may have, including claims relating to the Credit Agreements.

Consulting Agreement with Bristol Capital

On September 2, 2014, the Company entered into a Consulting Agreement (the “Consulting Agreement”) with Bristol Capital, LLC (“Bristol”). Pursuant to the Consulting Agreement, Bristol will assist the Company in general corporate activities including but not limited to strategic planning; management and business operations; introductions to further its business goals; provide advice and services related to the Company’s growth initiatives; and any other consulting or advisory services the Company reasonably requests that Bristol provide to the Company. The Consulting Agreement has a term of three years. In connection with the Consulting Agreement and as compensation for the services to be provided by Bristol thereunder, the Company has issued to Bristol a warrant to purchase up to 1,000,000 shares of Common Stock at an exercise price of $2.00 per share (the “Bristol Warrant”). In addition, the Company has issued to Bristol an option to purchase up to 1,000,000 shares of Common Stock at an exercise price of $2.00 per share (the “Bristol Option”). The Bristol Option is intended as an alternative to the Bristol Warrant, and will automatically terminate upon and to the extent the Bristol Warrant is exercised. Likewise, if and to the extent the Bristol Option is exercised, the Bristol Warrant will terminate. If the Company has not registered the Common Stock underlying the Bristol Warrants within six months following the execution of the Consulting Agreement, Bristol may elect to terminate the Bristol Warrant and retain the Bristol Option, or to terminate the Bristol Option and retain the Bristol Warrant, but in either case may only retain either the Warrant or the Option. In no event will Bristol have the right to exercise, in whole or in part, the Bristol Warrant and/or Bristol Option for a number of shares in excess of 1,000,000. Each of the Bristol Warrant and the Bristol Option (whichever ultimately remains outstanding) has a term of five years. The Consulting Agreement did not include any cash payment.

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

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” contained in our Annual Report on Form 10-K for the year ended December 31, 2013, as well as the unaudited condensed consolidated financial statements and notes thereto included in this Quarterly Report on Form 10-Q. This discussion contains forward-looking statements that involve risks and uncertainties. Our actual results could differ materially from those anticipated in these forward-looking statements as a result of various factors including those set forth under Item “1A. Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2013.

General

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.

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

Financial Condition and Liquidity

Since March 31, 2014, the Company has consummated the following other transactions related to its liquidity: (i) on May 30, 2014 the Company consummated a private placement to accredited investors (the “May 2014 Private Placement”) of its Series A 8% Convertible Preferred Stock (the “Series A Preferred”) and three-year warrants to purchase Common Stock equal to 50% of the number of shares issuable upon full conversion of the Series A Preferred for gross proceeds of $7.50 million; (ii) on June 6, 2014, T.R. Winston & Company, LLC (“T.R. Winston”) executed an agreement that they or a designee will purchase an additional $15.0 million of preferred stock under the same terms of the Series A Preferred Stock within 90 days; furthermore, on November 25, 2014, T.R. Winston has reaffirmed and extended their commitment for 90 days or until February 22, 2015. In November 2014, a controlling member of T.R. Winston was elected to the Company’s board of directors. T.R. Winston has informed the Company that there is a possible conflict between being the Company’s investment banker and board member, and as a result will refrain from acting as the Company’s investment banker; and (iii) on October 6, 2014, the Debenture holders agreed to waive any event of default under the Debentures that may have occurred prior to the date of the waiver (including, without limitation, any default relating to the Company’s indebtedness to Hexagon), and to rescind and annul any acceleration or right to acceleration that may have been triggered thereby.

Cash Flows

Cash used in operating activities during the six months ended June 30, 2014 was $4.64 million. Cash used in operating activities and cash used in investing activities was offset by cash provided in financing activities by $1.28 million, and resulted in a corresponding increase in cash.

The following table compares cash flow items during the six months ended June 30, 2014 and 2013 (in thousands):

	Six months ended June 30,
	2014			2013
Cash provided by (used in):
Operating activities	$	(4,464	)	$	(1,257	)
Investing activities		(439	)		(201	)
Financing activities		6,187			1,118
Net change in cash	$	1,283		$	(340	)

During the six months ended June 30, 2014, net cash used in operating activities was $4.46 million, compared to net cash used in operating activities of $1.26 million during the six months ended June 30, 2014, an increase of cash used in operating activities of $3.16 million. The primary changes in operating cash during the six months ended June 30, 2014 were $14.72 million of net loss, $0.43 million increase in cash for other assets, an increase in cash of $0.10 million for restricted cash, an increase in accounts payable and accrued expenses of $0.07 million, and offset a decrease of cash of $0.15 million for accounts receivable. The cash flows from operating activities were adjusted for non-cash charges of $0.99 million of depreciation, depletion, amortization and accretion expenses, $0.90 million of debt discount accretion, $0.13 million of amortization of deferred financing costs; $0.70 million for common stock issued in satisfaction of financing costs for both the private placement of common stock and the conversion of convertible debentures; $0.15 million for common stock issued for interest on the Debentures; $6.66 million for the issuance of a warrant to purchase common stock recorded as a debt inducement for the conversion of the Debentures; $1.18 million for issuance of stock for services and compensation, and offset by a decrease in cash of $0.85 million for a non-cash change in fair value of the conversion option with respect to the Debentures.

During the six months ended June 30, 2014, net cash used in investing activities was $0.44 million, compared to net cash used in investing activity of $0.20 million during the six months ended June 30, 2013, an increase of cash used in investing activities of $0.24 million. The primary changes in investing cash during the six months ended June 30, 2014 were a decrease in cash of $0.11 million of drilling expenditures and acquisitions of undeveloped properties, $0.33 million in expenditures related to additions to oil and gas properties, and $0.01 million in expenditures related to office equipment.

During the six months ended June 30, 2014, net cash provided by financing activities was $6.19 million, compared to net cash provided by financing activities of $1.12 million during the six months ended June 30, 2013, an increase of $5.02 million. The increase in financing cash during the six months ended June 30, 2014 were primarily due to net proceeds of $4.94 million from the May Private Placement, and net proceeds of $5.33 million from the private placement of 3,750,000 units in January 2014 (the “January 2014 Private Placement”) consisting of (i) one share of Common Stock and (ii) one warrant to purchase one share of Common Stock, for proceeds of $5.33 million net of fees associated with the financing. The proceeds from the January 2014 Private Placement and the May 2014 Private Placement were partially offset by net repayments of debt of $5.08 million payment of dividend for Series A Convertible Preferred Stock of $0.04 million.

As of June 30, 2014, the Company had received gross proceeds of $4.94 million in connection with the January 2014 Private Placement and $5.65 million from the May 2014 Private Placement. As of June 30, 2014, the Company immediately recognized an accretion expense of $3.57 million and a private preferred subscription receivable of $1.85 million. The subscription receivable was fully funded in September 2014.

Capital Resources

The Company will require additional capital to fund its current debt obligations and accrued interest of $7.43 million, current capital obligations, capital budget plans, to help fund its ongoing overhead and general and administrative expenses, and to provide additional capital to generally improve its working capital position. We anticipate that such additional funding will be provided by a combination of capital raising activities, including borrowing transactions, the sale of additional debt and/or equity securities, the sale of working interests in certain un-evaluated and evaluated properties and by the development of certain undeveloped properties via arrangements with joint venture (“JV”) partners which may reduce our working interest in certain properties. If we are not successful in obtaining sufficient cash resources to fund the aforementioned capital requirements, we may be required to curtail our expenditures, restructure our operations, sell assets on terms which may not be deemed favorable and/or curtail other aspects of our operations, decrease our working interest in planned drilling areas, including deferring certain capital expenditures in key development areas. There is no assurance that any such funding will be available to the Company.

During the second quarter of 2014, the Company was provided cash call notices for authorizations for expenditures (“AFE’s”) relating to three horizontal wells in the North Wattenberg field, for a total of approximately $5.05 million. A notice of default was issued to the Company on June 12, 2014, and the thirty-day cure period under the notice of default and applicable joint operating agreements (“JOA’s”) expired on July 12, 2014. Per the terms of the applicable JOA’s, while this default remains uncured, the operator of the three wells is entitled to exercise its remedies under the JOA, including, without limitation, issuing to the Company a notice of non-consent, which would entitle the operator to recoup 300% of its expenditures before the Company would be permitted to participate in the wells. As of November 2014, the Company is in further negotiations with the operator to remedy the default under the JOA’s and participate in the current and future wells on the lease. Furthermore, the Company has accrued $5.05 million in well cost as wells-in-progress and believes the Company will retain an interest in the wells.

Results of Operations

Three months ended June 30, 2014 compared to three months ended June 30, 2013

The following table compares operating data for the three months ended June 30, 2014 to June 30, 2013:

	Three months ended June 30,
	2014			2013
Revenues:
Oil sales	$	979,523		$	1,189,005
Gas sales		102,324			38,805
Operating fees		42,152			42,019
Total revenues		1,123,999			1,269,829

Costs and expenses:
Production costs		221,260			255,454
Production taxes		101,230			162,045
General and administrative		2,643,063			1,367,976
Depreciation, depletion and amortization		570,403			651,175
Total costs and expenses		2,293,764			2,436,650

Loss from operations		(2,411,957	)		1,166,821

Other Income (expenses):
Other income		44			141
Inducement expense		-			-
Convertible notes conversion derivative gain (loss)		(300,000	)		(10,000	)
Interest expense		(1,953,127	)		(1,669,519	)
Total other expenses		(2,253,083	)		(1,679,378	)

Net loss	$	(4,665,040	)	$	(2,846,199	)

Total revenues

Total revenues were $0.98 million for the three months ended June 30, 2014, compared to $1.19 million for the three months ended June 30, 2013, decrease of $0.21 million, or 18%. The decrease in revenues was due primarily to a decrease in production volumes. During the three months ended June 30, 2014 and 2013, production amounts were 15,533 and 16,145 BOE, respectively, a decrease of 612 BOE, or 4%. Declines in production are primarily attributable to natural production declines related to mature producing properties and wells which need work-overs to continue production. During the three months ended June 30, 2014, the differential between the price per BOE received by the Company and the NYMEX crude price ranged from $11.50-$15.15 from the excess supply of oil in the area; compared to $7.64 from the same period in 2013. The work-over down time can range from a few days to a few months based on the availability of the work-over rigs in the immediate area. Furthermore, the decrease in production is from the Company analyzing the economics of the wells and cycling producing days instead of continuous production. These decreases were offset by the Company’s participation in and production from one non-operated horizontal Wattenberg well. The effect of the production decrease was offset by an increase of overall average price decrease per BOE to $69.95 in 2014 from $76.05 in 2013, decrease of $6.40 or 8%.

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

	For the
	Three Months Ended
	June 30,
	2014			2013
Product
Oil (Bbl.)		10,918			13,617
Oil (Bbls)-average price (1)	$	89.72		$	87.32

Natural Gas (MCF)-volume		27,688			15,170
Natural Gas (MCF)-average price (2)	$	3.70		$	2.56

Barrels of oil equivalent (BOE)		15,533			16,145
Average daily net production (BOE)		171			177
Average Price per BOE (1)	$	69.65		$	76.05

(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)	$	69.65		$	76.05

Production costs per BOE		14.24			15.82
Production taxes per BOE		6.52			10.04
Depreciation, depletion, and amortization per BOE		36.72			40.33
Total operating costs per BOE		57.55			66.19

Gross margin per BOE	$	12.10		$	9.86

Gross margin percentage		17	%		13	%

(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 June 30, 2014, the Company did not maintain any active commodity derivatives.

Production costs

Production costs were $0.22 million during the three months ended June 30, 2014, compared to $0.26 million for the three months ended June 30, 2013, decrease of $0.04 million, or 15%. Decrease in production costs in 2014 was from the Company’s in-depth analysis of our wells and determining the economics of the wells and changing well mechanics to reduce work-overs from strain on the pumping units and downhole equipment. Production costs per BOE decreased to $14.24 for the three months ended June 30, 2014 from $15.82 in 2013, decrease of $1.58 per BOE, or 10%.

Production taxes

Production taxes were $0.10 million for the three months ended June 30, 2014, compared to $0.16 million for the three months ended June 30, 2013, a decrease of $0.06 million, or 38%. 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 in which production is derived. Production taxes per BOE decreased to $6.52 during the three months ended June 30, 2014 from $10.04 in 2013, decrease of $3.52 or 35%. Declines in production taxes per BOE are primarily attributable to declines in production, which are the result of natural production declines related to mature producing properties and wells which need work-overs to continue production. Additionally, the decrease is from product mix within certain states which have different tax burdens for hydrocarbons. The work-over down time can range from a few days to a few months based on the availability of the work-over rigs in the immediate area. Furthermore, the decrease in production is from the Company analyzing the economics of the wells and cycling producing days instead of continuous production.

General and administrative

General and administrative expenses were $2.64 million during the three months ended June 30, 2014, compared to $1.37 million during the three months ended June 30, 2013, an increase of $1.27 million, or 92%. Non-cash general and administrative items for the three months ended June 30, 2014 was an expense of $0.60 million compared to $0.64 million during the three months ending June 30, 2013, decrease of $.04 million, or 6%. The increase in non-cash general and administrative expenses was due to the reversal of non-cash stock compensation for executive management and reevaluation of the stock issued at a lower cost basis. Cash general and administrative expenses were $2.04 million during the three months ended June 30, 2014, compared to $0.73 million during the three months ended June 30, 2013, an increase of $1.31 million, or 179%. The increase in cash general and administrative expenses was due to $0.15 million of due diligence cost incurred in connection with a potential acquisition, $0.65 million for expenses related to severance agreements, $0.87 million for employee incentive payments, and additional contractors, as well as additional legal and other contract professional services expenses.

Depreciation, depletion, and amortization

Depreciation, depletion, and amortization were $0.57 million during the three months ended June 30, 2014, compared to $0.65 million during the three months ended June 30, 2013, a decrease of $0.08 million, or 12%. Decrease in depreciation, depletion, and amortization was from (i) a decrease in production amounts in 2014 from 2013, (ii) an increase in the depletion base for the depletion calculation, and (iii) a decrease in the depletion rate. Production amounts decreased to 15,533 from 16,145 for the three months ended June 30, 2014 and 2013, respectively, a decrease of 612, or 4%. The decrease in depletion was based on a lower depletion base. Depreciation, depletion, and amortization per BOE decreased to $36.72 from $40.33, respectively, for the three months ended June 30, 2014 and 2013, a decrease of $3.61, or 9%. Declines in production are primarily attributable to natural production declines related to mature producing properties, but were also affected by the temporary reduction in production from five of the Company’s properties that experienced production difficulties during the quarter. Producing wells that went off-line were idle for longer periods of time than expected due to the lack of availability of work-over/production rigs in the area.

Interest Expense

For the three months ended June 30, 2014 and 2013, the Company incurred interest expense of approximately $1.95 million and $1.67 million, respectively, of which approximately $1.47 million and $1.04 million is classified as non-cash interest expense, respectively. The details of the non-cash interest expense are as follows: (i) amortization of the deferred financing costs of $0.07 million, (ii) accretion of the convertible debentures payable discount of $0.23 million, (iii) accrued interest for term note loan fees of $1.00 million and (iv)amortization of forbearance fees of $0.12 million. Cash interest is comprised of term loan cash expense payment. The increase in interest expense was primarily attributable to fees for not paying a designated amount to the term note holder. Other cash interest increased due to $0.25 million forbearance fees paid to Hexagon, which is being amortized over the life of the extension.

Results of Operations

Six months ended June 30, 2014 compared to six ended June 30, 2013

The following table compares operating data for the six months ended June 30, 2014 to June 30, 2013:

	Six months ended
	June 30,
	2014			2013
Revenues:
Oil sales	$	1,679,609		$	2,316,338
Gas sales		189,990			145,202
Operating fees		76,881			90,522
Realized gain on commodity price derivatives		11,143			19,890
Total revenues		1,957,623			2,571,952

Costs and expenses:
Production costs		637,583			559,301
Production taxes		194,910			278,039
General and administrative		5,601,478			2,352,235
Depreciation, depletion and amortization		959,039			1,340,829
Total costs and expenses		7,393,010			4,530,404

Loss from operations		(5,435,387	)		(1,958,452	)

Other Income (expenses):
Other income		97			392
Inducement expense		(6,661,275	)		-
Convertible notes conversion derivative gain (loss)		850,000			(30,000	)
Interest expense		(3,469,458	)		(3,305,678	)
Total other expenses		(9,280,636	)		(3,335,286	)

Net loss	$	(14,716,023	)	$	(5,293,738	)

Total revenues

Total revenues were $1.68 million for the six months ended June 30, 2014, compared to $2.32 million for the six months ended June 30, 2013, a decrease of $0.64 million, or 28%. The decrease in revenues was due primarily to a decrease in production volumes. During the six months ended June 30, 2014, the Company’s differential from the purchaser ranged from $11.50-$15.00 from the excess supply of oil in the area; compared to $7.64 from the same period in 2013. During the six months ended June 30, 2014 and 2013, production amounts were 25,821 and 34,359 BOE, respectively, a decrease of 8,538 BOE, or 25%. Declines in production are primarily attributable to natural production declines related to mature producing properties, but were also affected by the temporary reduction in production from five of the Company’s properties that experienced production difficulties during the six months ended June 30, 2014. Work-over rigs had limited availability due to high industry activity within the operating area of the Company and the Company performed an in-depth analysis of production and started to reduce the amount of on-time that the wells pumped. As a result, idled wells for routine well maintenance or other repairs were off-line more often and longer than anticipated, which substantially decreased our production. The effect of this production decrease was partially offset by an increase in the overall average price per BOE to $72.41 in 2014 from $71.64 in 2013, an increase of $0.77 or 1%.

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

	For the
	Six Months Ended
	June 30,
	2014			2013
Product
Oil (Bbl.)		19,373			27,075
Oil (Bbls)-average price (1)	$	86.70		$	85.55

Natural Gas (MCF)-volume		38,685			43,704
Natural Gas (MCF)-average price	$	4.91		$	3.89

Barrels of oil equivalent (BOE)		25,821			34,359
Average daily net production (BOE)		143			190
Average Price per BOE (1)	$	72.41		$	71.64

(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)	$	72.41		$	71.64

Production costs per BOE		24.69			16.28
Production taxes per BOE		7.55			8.09
Depreciation, depletion, and amortization per BOE		37.14			39.02
Total operating costs per BOE		69.38			63.39

Gross margin per BOE	$	3.03		$	8.25

Gross margin percentage		4	%		12	%

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

Commodity Price Derivative Activities

As of June 30, 2014, the Company did not maintain any active commodity swaps. The commodity swap ended in January 31, 2014 for 100 barrels of oil per day at a price of $99.25 per barrel.

Commodity price derivative realized gains were $0.01 million for the six months ended June 30, 2014, compared to realize gains of $0.02 million during the six months ended June 30, 2013, a decrease in realized gains/losses of $0.01 million or 50%.

Production costs

Production costs were $0.64 million during the six months ended June 30, 2014, compared to $0.56 million for the six months ended June 30, 2013, an increase of $0.08 million, or 14%. Increase in production costs in 2014 was from an increase of the number of required well work, property improvements, and maintenance of productive wells. Production costs per BOE increased to $24.69 for the six months ended June 30, 2014 from $16.28 in 2013, an increase of $8.41 per BOE, or 52%. The increase in production costs was several wells were requiring work overs from over-working the pumping units and creating an excessive amount of tubing leaks, whole in the tubing, and parted rods. Due to the large amount of work overs needed at one time, the Company hired different Company’s to perform the work which costs a premium from the normal vendors. During the second three months ended the Company performed an in-depth analysis of our wells and determining the economics of the wells and changing well mechanics to reduce work-overs from strain on the pumping units and downhole equipment.

Production taxes

Production taxes were $0.19 million for the six months ended June 30, 2014, compared to $0.28 million for the six months ended June 30, 2013, a decrease of $0.09 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 in which production is derived. Production taxes per BOE decreased to $7.55 during the three months ended June 30, 2014 from $8.09 in 2013, decrease of $0.54 or 7%. During the six months ended June 30, 2014, work-over rigs were in high demand within the operating area of the Company with a small supply of work-over rigs. As a result, our wells that went down for normal well maintenance or other repairs did not operate for an extended period of time which substantially decreased our BOE.

General and administrative

General and administrative expenses were $5.60 million during the six months ended June 30, 2014, compared to $2.35 million during the six months ended June 30, 2013, an increase of $3.25 million, or 138%. Non-cash general and administrative items for the six months ended June 30, 2014 were $2.28 million compared to $1.00 million during the six months ending June 30, 2013, an increase of $1.28 million, or 128%. The increase in non-cash general and administrative expenses was due to additional financing costs of $0.69 million; increase in non-cash compensation of $0.44 million; $0.69 million fees associated with completing the January 2014 Private Placement; $0.06 million for non-cash payment of the financing fees for the May 2014 Private Placement, and $0.5 million non-cash compensation to a third party. Cash general and administrative expenses were $3.31 million during the six months ended June 30, 2014, compared to $1.35 million during the six months ended June 30, 2013, an increase of $1.96 million, or 145%. The increase in cash general and administrative expenses was largely due to $0.15 million of due diligence cost incurred in connection with a potential acquisition, $0.65 million for expenses related to severance agreements, $0.87 million for employee incentive payments, $0.25 million to our term loan holder as a forbearance fees, as well as additional legal and other contract professional services expenses.

Depreciation, depletion, and amortization

Depreciation, depletion, and amortization were $0.96 million during the six months ended June 30, 2014, compared to $1.34 million during the six months ended June 30, 2013, a decrease of $0.38 million, or 28%. Decrease in depreciation, depletion, and amortization was from (i) a decrease in production amounts in 2014 from 2013, (ii) an increase in the depletion base for the depletion calculation, and (iii) a decrease in the depletion rate. Production amounts decreased to 25,821 from 34,359 for the six months ended June 30, 2014 and 2013, respectively, a decrease of 8,538, or 25%. The decrease in depletion was based on a lower depletion base. Depreciation, depletion, and amortization per BOE decreased to $37.14 from $39.02, respectively, for the six months ended June 30, 2014 and 2013, a decrease of $1.88, or 5%. During the six months ended June 30, 2014, work-over rigs were in high demand within the operating area of the Company with a small supply of work-over rigs. As a result, our wells which went down for normal well maintenance or other repairs did not operate for an extended period of time which substantially decreased our BOE.

Inducement expense

Inducement expenses were $6.66 million during the six months ended June 30, 2014, compared to $0 during the six months ended June 30, 2013. In January 2014, the Company entered into the Conversion Agreement between the Company and all of the holders of the Debentures. Under the terms of the Conversion Agreement, $9.0 million of the approximately $15.6 million in Debentures then outstanding converted to Common Stock at a price of $2.00 per common share. As inducement for the conversion, the Company issued warrants to the converting Debenture holders to purchase one share of Common Stock, at an exercise price equal to $2.50 per share, for each share of Common Stock issued upon conversion of the Debentures. The Company used the Black Sholes Lattice Model to value the warrants, utilizing a volatility of 65%, and a life of 3 years, arriving at a fair value of $6.61 million for the warrants.

Interest Expense

For the six months ended June 30, 2014 and 2013, the Company incurred interest expense of approximately $3.47 million and $3.31 million, respectively, of which approximately $2.82 million and $1.75 million is classified as non-cash interest expense, respectively. The details of the non-cash interest expense are as follows: (i) amortization of the deferred financing costs of $0.13 million, (ii) accretion of the convertible debentures payable discount of $0.90 million, (iii) common stock issued for interest of $0.15 million, (iv) accrued interest for term note loan fees of $1.00 million and (v) accrued interest to convertible debenture of $0.34 million (vi) amortization of forbearance fees of $0.12 million. Cash interest is comprised of term loan cash expenses of payment. The increase in interest expense was primarily attributable to fees for not paying a designated amount to the term note holder.

Off-Balance Sheet Arrangements

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

Capital Budget

We anticipate a working capital budget of up to $50.0 million for 2015. The budget is expected to be allocated toward the acquisition and exploitation of opportunities to develop two unconventional reservoirs located in the Wattenberg field, within Colorado, that will apply horizontal drilling in the Niobrara and Codell formations. The Company is also targeting additional reservoirs in Wyoming which will target both the Codell and J-sand formations within the Silo and Pine Bluffs field. The entire capital budget is subject to the securing of adequate capital through drilling, equity, and debt instruments.

Although we secured approximately $5.0 million, from the January 2014 Private Placement and an additional $7.50 million, from the May 2014 Private Placement, some of the proceeds from these transactions were applied to the payment and servicing of our term debt and working capital and participating in working interest in the Wattenberg area. Furthermore, the Company has $6.93 million in outstanding principal amount of Debentures and $0.50 million of accrued interest that will mature in January 2015 if not converted.

In addition to the need to secure adequate capital to fund our working capital budget, the execution of, and results from, our capital budget are contingent on various other factors, including, but not limited to, market conditions, oilfield services and equipment availability, commodity prices and drilling/ production results. Results from the wells identified in the capital budget may lead to additional adjustments to the capital budget. Other factors that could impact our level of activity and capital expenditure budget include, but are not limited to, a reduction or increase in service and material costs, the formation of joint ventures with other exploration and production companies, the divestiture of non-strategic assets, and oil and gas prices. We do not anticipate any significant expansion of our current DJ Basin acreage position in the near term; however, we are targeting attractive opportunities for acquisition in the Wattenberg and surrounding areas.

Overview of Our Business, Strategy, and Plan of Operations

We have acquired and developed a producing base of oil and natural gas proved reserves, as well as a portfolio of exploration and other undeveloped assets with conventional and non-conventional reservoir opportunities, with an emphasis on those with multiple producing horizons, in particular the Muddy “J” conventional reservoirs and the Niobrara shale and Codell resource plays. We believe these assets and related acquisition opportunities offer the possibility of repeatable year-over-year success and significant and cost-effective production and reserve growth. Our acquisition, development and exploration pursuits are principally directed at oil and natural gas properties in the DJ Basin in Colorado, Nebraska, and Wyoming. Since early 2010, we have acquired and/or developed 25 producing wells. As of September 1, 2014, after we assigned 30,000 net acres and 17 wells to Hexagon pursuant to the Final Settlement Agreement, we owned interests in approximately 93,000 gross (84,000 net) leasehold acres, of which 81,000 gross (58,000 net) acres are classified as undeveloped acreage and all of which are located in Colorado, Wyoming and Nebraska within the DJ Basin. Our remaining 8 wells are located in Wyoming and Colorado. We are primarily focused on our North and South Wattenberg Field assets which include attractive unconventional reservoir drilling opportunities in mature development areas that offer low risk drilling opportunities within the Niobrara and Codell formation. We also believe that our conventional reservoir development potential in our Silo-East and south Pine Bluffs well areas will yield competitive results. We expect to pursue an aggressive multi-well development drilling program during 2015.

During September 2014, in connection with the Final Settlement Agreement, in exchange for full extinguishment of the term notes, the Company assigned to Hexagon property consisting of 30,000 net acres and 17 producing wells, and provided Hexagon $ 2.0 million in Redeemable Preferred. The relief of the $14.03 million secured term loan has reduced the Company’s level of debt, but the loss of the property assigned to Hexagon will have a significant impact on the Company’s production volumes and revenues in 2014 and until we develop additional production and reserves.

Our intermediate goal is to create significant value via the attraction of additional capital to develop and expand through acquisition our inventory of low and controlled-risk conventional and unconventional properties, while maintaining a low cost structure, which will result in high investment returns and shareholder value. To achieve this, our business strategy includes the following elements:

Pursuing the initial development of our Greater Wattenberg Field unconventional assets. We currently have two key unconventional reservoir properties located in the Greater Wattenberg field. We participated in the drilling of one non-operated horizontal well in our North Wattenberg during the fourth quarter of 2013, which was completed in the first quarter of 2014 and is now producing both crude oil, natural gas liquids, and natural gas. We also plan to operate the drilling of horizontal wells on our South Wattenberg property during the first half of 2015 in which we have a 50% working interest in up to 6 wells and a 25% working interest in two additional wells. Drilling activities on both properties will target the prolific and well established Niobrara shale and Codell formations. Subject to the securing of additional capital, we expect to purchase additional property in the Wattenberg field which will bring substantial amount of reserves and drilling opportunities.

Extending the development of certain conventional prospects within our inventory of other DJ Basin properties. Subject to the securing of additional capital, we anticipate the expenditure of up to an additional $5.0 million in drilling and development costs on three of our DJ Basin assets where initial exploitation has yielded positive results. We currently have one well permitted and ready to drill in the Silo field of Wyoming. Additional drilling activities will be conducted on each property in an effort to fully assess each property and define field productivity and economic limits.

Engaging in certain exploration activities, including geologic and geophysics projects, to define additional prospects within our inventory of DJ Basin properties that may have significant development upside. Subject to the securing of additional capital, we anticipate an expenditure of $2.0 to $5.0 million in 2015 to acquire 3-D seismic data and utilizing other advanced technological resources which reduce the drilling risks of future wells on our Wattenberg, Pine Bluffs, and Silo Field locations and increase our ultimate recovery of our wells.

Purchasing strategic land and wells with proved production and enhanced reserves.Subject to securing financing, we are currently analyzing “bolt-on” property which will increase our strategic acreage in the prolific Wattenberg area and the surrounding Silo field.

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

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

Currently, our inventory of developed and undeveloped acreage includes approximately 7,600 net acres that are held by production, approximately 15,740 net acres, 49,000, 6,900, 1,800 and 200 net acres that expire in the years 2014, 2015, 2016, 2017, and thereafter, respectively. Approximately 82% of our inventory of undeveloped acreage provides for extension of lease terms from two to five years, at the option of the Company, via payment of varying, but typically nominal, extension amounts. However, due to our current liquidity issues, we may enter into one or more transactions to sell a significant number of leases, both developed and undeveloped, to enable us to pay down our outstanding debt or satisfy other financial obligations.

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

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

Marketing and Pricing

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

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

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

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

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

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

Obligations and Commitments

We had the following contractual obligations and commitments as of June 30, 2014 (in thousands):

	Payments due by period
Contractual obligations	Total		Within 1 Year		1-3 years		4-5 years		More than 5 years
Secured debt	$	14,800	$	-	$	14,800	$	-	$	-
Interest on secured debt		189		189		-		-		-
Convertible debentures		6,728		6,728		-		-		-
Interest on convertible debentures		298		298		-		-		-
Operating leases & Other		35		35		-		-		-
Total contractual cash obligations	$	22,050	$	7,250	$	14,800	$	-	$	-

The Company has an obligation to pay a cumulative divided on the 8% Series A Convertible Preferred Stock which is payable on April 1, July 1, October 1, and January 1 until the preferred stock is converted to common stock. In September 2014, the Company

In September 2014, as a result of the final settlement with Hexagon, the Company issued Hexagon $2.0 million in Redeemable Preferred. The Redeemable Preferred bears a 6% dividend per annum, payable quarterly, and is redeemable at face value (plus any accrued and unpaid dividends) at any time at the Company’s option, or at Hexagon’s option upon the Company’s achievement of certain production and reserves thresholds

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. See our 2013 Annual Report on Form 10-K for the year ended December 31, 2013 for the remaining Critical Accounting Policies and Estimates.

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

Item 3. Quantitative and Qualitative Disclosures about Market Risk.

Not Applicable

Item 4. Controls and Procedures.

Evaluation of Disclosure Controls and Procedures

Management is required to evaluate, with the participation of the Company’s Chief Executive Officer and Chief Financial Officer, the effectiveness of the Company’s disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act), as of the end of each fiscal quarter. In addition, management is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act. Internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements in accordance with GAAP. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projection of any evaluation of effectiveness to future periods is subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Management has conducted, with the participation of our Chief Executive Officer and Chief Financial Officer, an assessment, including evaluating the effectiveness of the Company’s disclosure controls and procedures and testing of the effectiveness of our internal control over financial reporting as of June 30, 2014. Management’s assessment of internal control over financial reporting was conducted using the criteria in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission, or COSO.

Based on the evaluation and the identification of the material weaknesses in internal control over financial reporting described below, our Chief Executive Officer, Chief Financial Officer, and our Interim Chief Financial Officer have concluded that, as of June 30, 2014, the Company’s disclosure controls and procedures were not effective.

A material weakness is a control deficiency, or combination of control deficiencies, that results in more than a remote likelihood that a material misstatement of the annual or interim financial statements will not be prevented or detected. In connection with management’s assessment of our internal control over financial reporting, we identified the following material weaknesses in our internal control over financial reporting as of June 30, 2014:

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

	●	As disclosed in the Form 8-K filed on November 7, 2014, the Company determined that during the fourth quarter of 2013 and the first three quarters of 2014, there existed a material weakness with respect to the operation of the Company’s internal controls relating to the documentation and authorization procedures of certain travel and entertaining expenses incurred by certain past and present officers in those periods.

Because of both the material weaknesses described above, management has concluded that we did not maintain effective internal control over financial reporting as of June 30, 2014, based on the Internal Control—Integrated Framework issued by COSO.

Remediation Efforts

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

We have implemented a new extensive Travel and Entertainment policy which all employees and directors have been presented the policy. All employees and directors are required to review and sign the document. Furthermore, the Company has required all employees and directors to review and sign all of the Company’s corporate documents which include, yet not limited to, the Code of Ethics, By-laws, and Corporate Governance Policy.

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

Changes in Internal Control over Financial Reporting

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

Also on May 16, 2014, the Board of Directors appointed Eric Ulwelling, who was the Company’s Chief Accounting Officer and Controller, to the position of Interim Chief Financial Officer. This event caused a change in our internal control over financial reporting during the quarter-ended March 31, 2014 and continued through the quarter ended June 30, 2014.

PART II - OTHER INFORMATION

Item 1. Legal Proceedings.

Parker v. Tracinda Corporation, Denver District Court, Case No. 2011CV561. In November 2012, the Company filed a motion to intervene in garnishment proceedings involving Roger Parker, the Company’s former Chief Executive Officer and Chairman. The Defendant 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 were stayed by Court Order dated January 30, 2013. Judgment was entered by the trial court in favor of defendant Tracinda Corp. (“Tracinda”) on Tracinda’s counterclaim for breach of a promissory note before Mr. Parker’s bankruptcy. Although the trial court found that Tracinda had breached its pledge agreement with Mr. Parker, the court ruled Tracinda was not liable on Mr. Parker’s breach of contract claim based on several defenses. Mr. Parker appealed the judgment to the Colorado Court of Appeals (Case No. 2012CA2096) and the appellate proceedings were also stayed by Order of the Colorado Court of Appeals dated April 1, 2013. Stay of the state court proceedings was lifted by Bankruptcy Court Order dated April 12, 2013. On October 17, 2013, the Colorado Court of Appeals affirmed in part, reversed in part (reversing judgment on Mr. Parker’s contract claim) and remanded the case to the trial court with directions to determine damages. At this stage, we cannot express an opinion as to the probable outcome of this matter, although a determination of the issues relating to rights in the unvested stock is expected to be made in the Adversary Proceeding currently pending in the United States Bankruptcy Court for the District of Colorado (described below).

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 in an Adversary Proceeding (Adversary No. 13-01301 EEB) against the Company and Roger Parker in connection with the personal bankruptcy proceedings of Roger Parker, alleging that the Company improperly failed to remit to Tracinda certain property in connection with various writs of garnishment issued by the Denver District Court (discussed above). Tracinda seeks, among other things, a declaratory judgment stating that Tracinda is entitled to such property allegedly subject to such writs. The Company filed an answer to this complaint on July 10, 2013. The Bankruptcy Court entered an Order dated August 12, 2014, holding the case in abeyance pending resolution of the state-court appeal of the Denver District Court lawsuit. On October 2, 2014, the Bankruptcy Court entered a Minute Order declaring that it would issue an order in due course continuing the abeyance or ruling on pending motions for summary judgment. A trial date has not been set.

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

Item 1A. Risk Factors.

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

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

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

Limitations upon the Payment of Dividends

The Company filed a Certificate of Designation of Preferences, Rights and Limitations of Series A 8% Convertible Preferred Stock (the “Certificate of Designation”) on May 30, 2014 with the Secretary of State of the State of Nevada, which was effective upon filing. The Certificate of Designation provides that the holders of the Series A Preferred are entitled to receive a dividend payable at the election of the Company at a rate of 8% per annum. (See Note 12 – Preferred Stock). In addition, the Certificate of Designation provides that so long as the Series A Preferred remains outstanding, neither the Company nor any subsidiary of the Company may directly or indirectly pay or declare any dividend or make any distribution upon or in respect of any Junior Securities (as that term is defined in the Certificate of Designation) as long as any dividends due on the Series A Preferred remain unpaid. Moreover, no money may be set aside for or applied to the purchase of or redemption (through a sinking fund or otherwise) of any Junior Securities or sharesparipassu with the Series A Preferred.

Item 3. Defaults upon Senior Securities.

None other than what has previously been disclosed.

Item 4. Mine Safety Disclosures.

Not Applicable

Item 5. Other Information.

None.

Item 6. Exhibits.

Exhibit Number		Exhibit Description
3.1		Certificate of Designation of Preferences, Rights, and Limitations, dated May 30 2014 (incorporated herein by reference to Exhibit 3.1 from our current report filed on Form 8-K filed on June 4, 2014).
3.2		Amendment to Certificate of Designations of Preferences, Rights, and Limitations, dated June 12, 2014 (incorporated herein by reference to Exhibit 3.1 from our quarterly report filed on Form 10-Q filed on June 17, 2014).
3.3		Certificate of Designation of 6% Redeemable Preferred Stock, dated August 29, 2014.
4.1		Form of Warrant dated May 30, 2014 (incorporated herein by reference to Exhibit 10.2 from our current report filed on Form 8-K filed on June 4, 2014).
4.2		Form of Hexagon Replacement Note (incorporated herein by reference to Exhibit 10.4 from our current report filed on Form 8-K filed on June 4, 2014).
4.3		Form of Bristol Capital Warrant.
10.1		Amendment to Transaction Fee Agreement with T.R. Winston dated as of April 29, 2014 (incorporated herein by reference to Exhibit 10.7 from our quarterly report filed on Form 10-Q filed on June 17, 2014).
10.2		Form of Securities Purchase Agreement dated May 30, 2014 (incorporated herein by reference to Exhibit 10.1 from our current report filed on Form 8-K filed on June 4, 2014).
10.3		Hexagon Settlement Agreement, dated May 30, 2014 (incorporated herein by reference to Exhibit 10.3 from our current report filed on Form 8-K filed on June 4, 2014).
10.4		Letter Agreement dated May 19, 2014 with holders of the 8% Senior Secured Convertible Debentures (incorporated herein by reference to Exhibit 10.1 from our quarterly report filed on Form 10-Q filed on June 17, 2014).
10.5		Letter Agreement with T.R. Winston dated as of June 6, 2014 (incorporated herein by reference to Exhibit 10.9 from our quarterly report filed on Form 10-Q filed on June 17, 2014).
10.6		Amendment to Debentures dated June 6, 2014 (incorporated herein by reference to Exhibit 10.2 from our quarterly report filed on Form 10-Q filed on June 17, 2014).
10.7		Separation Agreement with W. Phillip Marcum dated April 24, 2014 (incorporated herein by reference to Exhibit 10.3 from our quarterly report filed on Form 10-Q filed on June 17, 2014).
10.8		Employment Agreement with Robert A. Bell dated May 1, 2014 (incorporated herein by reference to Exhibit 10.4 from our quarterly report filed on Form 10-Q filed on June 17, 2014).
10.9		Separation Agreement with Robert A. Bell dated August 1, 2014.
10.10		Settlement Agreement with Hexagon dated September 2, 2014.
10.11		Consulting Agreement with Bristol Capital dated September 2, 2014.
10.12		Letter Agreement with holders of the Company’s 8% Senior Secured Convertible Debentures, dated as of October 6, 2014 (incorporated herein by reference to Exhibit 99.1 from our current report filed on Form 8-K filed on October 7, 2014).
31.1		Certification of the Chief Executive Officer pursuant to Section 302 of the Sarbanes Oxley Act of 2002
31.2		Certification of the 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

SIGNATURES

Pursuant to the requirements of the Securities and Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized

Signature	Title	Date

/s/ Abraham Mirman	Chief Executive Officer	November 25, 2014
Abraham Mirman	(Principal Executive Officer)

/s/ Eric Ulwelling	Chief Financial Officer and Chief Accounting Officer	November 25, 2014
Eric Ulwelling	(Principal Financial Officer)

EXHIBIT INDEX

Exhibit Number		Exhibit Description
3.1		Certificate of Designation of Preferences, Rights, and Limitations, dated May 30 2014 (incorporated herein by reference to Exhibit 3.1 from our current report filed on Form 8-K filed on June 4, 2014).
3.2		Amendment to Certificate of Designations of Preferences, Rights, and Limitations, dated June 12, 2014 (incorporated herein by reference to Exhibit 3.1 from our quarterly report filed on Form 10-Q filed on June 17, 2014).
3.3		Certificate of Designation of 6% Redeemable Preferred Stock, dated August 29, 2014.
4.1		Form of Warrant dated May 30, 2014 (incorporated herein by reference to Exhibit 10.2 from our current report filed on Form 8-K filed on June 4, 2014).
4.2		Form of Hexagon Replacement Note (incorporated herein by reference to Exhibit 10.4 from our current report filed on Form 8-K filed on June 4, 2014).
4.3		Form of Bristol Capital Warrant.
10.1		Amendment to Transaction Fee Agreement with T.R. Winston dated as of April 29, 2014 (incorporated herein by reference to Exhibit 10.7 from our quarterly report filed on Form 10-Q filed on June 17, 2014).
10.2		Form of Securities Purchase Agreement dated May 30, 2014 (incorporated herein by reference to Exhibit 10.1 from our current report filed on Form 8-K filed on June 4, 2014).
10.3		Hexagon Settlement Agreement, dated May 30, 2014 (incorporated herein by reference to Exhibit 10.3 from our current report filed on Form 8-K filed on June 4, 2014).
10.4		Letter Agreement dated May 19, 2014 with holders of the 8% Senior Secured Convertible Debentures (incorporated herein by reference to Exhibit 10.1 from our quarterly report filed on Form 10-Q filed on June 17, 2014).
10.5		Letter Agreement with T.R. Winston dated as of June 6, 2014 (incorporated herein by reference to Exhibit 10.9 from our quarterly report filed on Form 10-Q filed on June 17, 2014).
10.6		Amendment to Debentures dated June 6, 2014 (incorporated herein by reference to Exhibit 10.2 from our quarterly report filed on Form 10-Q filed on June 17, 2014).
10.7		Separation Agreement with W. Phillip Marcum dated April 24, 2014 (incorporated herein by reference to Exhibit 10.3 from our quarterly report filed on Form 10-Q filed on June 17, 2014).
10.8		Employment Agreement with Robert A. Bell dated May 1, 2014 (incorporated herein by reference to Exhibit 10.4 from our quarterly report filed on Form 10-Q filed on June 17, 2014).
10.9		Separation Agreement with Robert A. Bell dated August 1, 2014.
10.10		Settlement Agreement with Hexagon dated September 2, 2014.
10.11		Consulting Agreement with Bristol Capital dated September 2, 2014.
10.12		Letter Agreement with holders of the Company’s 8% Senior Secured Convertible Debentures, dated as of October 6, 2014 (incorporated herein by reference to Exhibit 99.1 from our current report filed on Form 8-K filed on October 7, 2014).
31.1		Certification of the Chief Executive Officer pursuant to Section 302 of the Sarbanes Oxley Act of 2002
31.2		Certification of the 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

Positive
Negative
Uncertain
Constraining
Legalese
Litigous
Readability	H.S. sophomore Avg

Lilis Energy (LLEX) 10-Q2014 Q2 Quarterly report

Content analysis