UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

 

FORM 10-Q

 

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

 

For the quarterly period ended September 30, 2014

 

☐  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 Employer Identification No.)

 

216 16th Street, Suite #1350

Denver, CO 80202

(Address of Principal Executive Offices)

 

(303) 951-7920

(Registrant’s telephone number, including area code)

 

	1900 Grant Street, Suite #720 Denver, CO 80203
	(Former name, former address and former fiscal year, if changed since last report)

 

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

 

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

 

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

 

Large accelerated filer	☐	Accelerated filer	☐
Non-accelerated filer	☐	Smaller reporting company	☒

 

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

 

As of February 24, 2015, 28,918,475 shares of the registrant’s common stock were issued and outstanding.

 

 

 

Lilis Energy, Inc.

 

INDEX

 

PART I– FINANCIAL INFORMATION
Item 1.		Financial Statements (Unaudited)	4
		Condensed Balance Sheets as of September 30, 2014 and December 31, 2013 (Audited)	4-5
		Condensed Statements of Operations for the Three and Nine Months Ended September 30, 2014 and 2013	6
		Condensed Statements of Cash Flows for the Nine Months Ended September 30, 2014 and 2013	7
		Notes to Condensed Financial Statements	8
Item 2.		Management’s Discussion and Analysis of Financial Condition	26
Item 3.		Quantitative and Qualitative Disclosures About Market Risk	40
Item 4.		Control and Procedures	40
PART II– OTHER INFORMATION
Item 1.		Legal Proceedings	41
Item 1A.		Risk Factors	42
Item 2.		Unregistered Sales of Equity Securities and Use of Proceeds	42
Item 3.		Defaults Upon Senior Securities	42
Item 4.		Mine Safety Disclosures	43
Item 5.		Other Information	43
Item 6.		Exhibits	43
SIGNATURES			44
EXHIBIT INDEX			45

 

 

FORWARD-LOOKING STATEMENTS

 

This quarterly report 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 or operating needs;
●	failure to meet requirements or covenants under our debt instruments, which could lead to foreclosure of significant core assets;
●	failure to fund our authorization for expenditures from other operators for key projects which will reduce/ or eliminate our interest in the wells/asset
●	inability to address our negative working capital position in a timely manner;
●	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 further 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 natural gas;
●	the timing and success of our drilling and completion activity;
●	lower oil and natural gas prices negatively affecting our ability to borrow or raise capital, or enter into joint venture arrangements;
●	declines in the values of our natural gas and oil properties resulting in write-down or impairments;
●	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;
●	Availability of funds under our credit facility;
●	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 on a timely basis;
●	transportation capacity constraints or interruptions, curtailment of production, natural disasters, adverse weather conditions, or other issues affecting the Denver-Julesburg Basin;
●	technique risks inherent in drilling in existing or emerging unconventional shale plays using horizontal drilling and complex 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, blow-outs, fires and uncontrollable flows of oil, natural 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.

CONDENSED BALANCE SHEETS

 

		September 30,				December 31,
		2014				2013
		(Unaudited)				(Audited)
Assets
Current assets:
Cash		$	1,472,996			$	165,365
Restricted cash			221,774				504,623
Accounts receivable (net of allowance of $76,016 at September 30, 2014 and $50,000 at December 31, 2013, respectively)			705,332				467,337
Prepaid assets			134,091				195,716
Commodity price derivative receivable			-				6,679
Total current assets			2,534,193				1,339,720
Oil and natural gas properties (full cost method), at cost:
Evaluated properties			37,298,201				68,213,467
Unevaluated acreage, excluded from amortization			12,931,701				18,663,569
Wells in progress, excluded from amortization			6,041,743				1,145,794
Total oil and natural gas properties, at cost			56,271,645				88,022,830
Less accumulated depreciation, depletion, and amortization			(25,525,672	)			(45,457,637	)
Total oil and natural gas properties, net			30,745,973				42,565,193
Other assets:
Office equipment, net			81,304				91,161
Deferred financing costs, net			15,949				294,699
Restricted cash and deposits			215,541				215,541
Total other assets			312,794				601,401
Total assets		$	33,592,960			$	44,506,314

 

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

 

 

LILIS ENERGY, INC.

CONDENSED BALANCE SHEETS

 

		September 30,				December 31,
		2014				2013
		(Unaudited)				(Audited)
Liabilities and Shareholders' Equity
Current liabilities:
Dividends accrued on preferred stock		$	121,167			$	-
Accrued expenses for drilling activity			5,698,193				-
Accounts payable			282,421				1,932,618
Accrued expenses			3,055,462				1,439,956
Short term loans payable			-				10,662,904
Total current liabilities			9,157,243				14,035,478
Long term liabilities:
Asset retirement obligation			196,248				1,104,952
Term loans payable			-				8,111,436
Convertible debentures payable, net of discount			6,683,299				14,724,366
Convertible debentures conversion derivative liability			1,540,481				605,315
Total long-term liabilities			8,420,028				24,546,069
Total liabilities			17,577,271				38,581,547
Commitments and contingencies
Conditionally redeemable 6% preferred stock, $0.0001 par value: 7,000 shares issued and authorized, 2,000 shares, outstanding at September 30, 2014, liquidation preferences of $2,000,000 as of September 30, 2014. No shares were outstanding as of December 31, 2013			2,000,000				-
Shareholders’ equity:
Series A Preferred Stock, $.0001 par value; stated rate $1,000:10,000,000 authorized, 7,500 and issued and outstanding as of September 30, 2014 and, liquidation preferences of $7,621,167 as of September 30, 2014. No shares were issued as of December 31, 2013.			6,794,000				-
Common stock, $0.0001 par value:100,000,000 shares authorized; 27,655,631 and 19,671,901 shares issued and outstanding as of September 30, 2014 and December 31, 2013, respectively			2,765				1,967
Additional paid in capital			154,224,704				121,451,232
Accumulated deficit			(147,005,780	)			(115,528,432	)
Total shareholders' equity			14,015,689				5,924,767
Total liabilities and shareholders’ equity		$	33,592,960			$	44,506,314

 

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

 

 

LILIS ENERGY, INC.

CONDENSED STATEMENTS OF OPERATIONS

(UNAUDITED)

 

		Three months ended September 30,								Nine months ended September 30,
		2014				2013				2014				2013
Revenues:
Oil sales		$	735,386			$	1,003,745			$	2,414,995			$	3,320,083
Natural gas sales			118,639				82,651				308,629				227,853
Operating fees			(39,015	)			28,331				37,866				118,853
Realized gain (loss) on commodity price derivatives			-				(43,551	)			11,143				(23,661	)
Change in fair value on  commodity price derivatives			-				(20,000	)			-				(20,000	)
Total revenues			815,010				1,051,176				2,772,633				3,623,128
Costs and expenses:
Production costs			101,593				318,322				739,176				877,623
Production taxes			71,864				102,919				266,774				380,958
General and administrative			2,935,404				1,214,029				8,536,882				3,566,264
Depreciation, depletion and amortization			252,548				532,173				1,211,587				1,873,002
Total costs and expenses			3,361,409				2,167,443				10,754,419				6,697,847
Loss from operations before loss on conveyance of property			(2,546,399	)			(1,116,267	)			(7,981,786	)			(3,074,719	)
Loss on conveyance of property			(2,694,466	)			-				(2,694,466	)			-
Loss from operations			(5,240,865	)			(1,116,267	)			(10,676,252	)			(3,074,719	)
Other Income (expenses):
Other income			32,338				145				32,435				536
Inducement expense			-				-				(6,661,275	)			-
Change in fair value of convertible debentures conversion derivative			(572,427	)			(207,251	)			(5,966,236	)			93,851
Interest expense			(1,130,727	)			(1,582,881	)			(4,477,277	)			(4,723,624	)
Total other expenses			(1,670,816	)			(1,789,987	)			(17,072,353	)			(4,629,238	)
Net loss			(6,911,681	)			(2,906,254	)			(27,748,605	)		$	(7,703,956	)
Dividends on preferred stock			(121,167	)			-				(161,848	)			-
Deemed dividend Series A Convertible Preferred Stock			-				-				(3,566,895	)			-
Net loss attributable to common shareholders		$	(7,032,848	)		$	(2,906,254	)		$	(31,477,348	)		$	(7,703,956	)
Loss per common share:
Net loss per common share (basic and diluted)		$	(0.25	)		$	(0.15	)		$	(1.17	)		$	(0.41	)
Weighted average common shares outstanding (basic and diluted)			27,631,220				19,254,329				26,794,437				18,786,598

 

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

 

 

LILIS ENERGY, INC.

CONDENSED STATEMENTS OF CASH FLOWS

(UNAUDITED)

 

		Nine months ended
		September 30,
		2014				2013
Cash flows from operating activities:
Net loss		$	(27,748,605	)			(7,703,956	)
Adjustments to reconcile net loss to net cash used in operating activities:
Inducement expenses			6,661,275				-
Common stock issued to investment bank for fees related to conversion of convertible debentures			686,251				-
Common stock issued for services and compensation			2,667,213				1,293,315
Reserve on bad debt expense			26,016				-
Loss on conveyance of property			2,694,466				-
Change in fair value of commodity price derivative			6,679				20,000
Change in fair value of executive incentive bonus			(35,000	)			-
Amortization of deferred financing costs			278,750				531,739
Change in fair value of convertible debentures conversion derivative			5,966,236				(93,851	)
Accretion of debt discount			810,804				1,742,099
Depreciation, depletion, amortization and accretion of asset retirement obligation			1,211,587				1,873,002
Changes in operating assets and liabilities:
Accounts receivable			(264,011	)			452,476
Restricted cash			282,849				86,636
Other assets			(104,510	)			77,486
Accounts payable and other accrued expenses			566,855				162,748
Net cash used in operating activities			(6,293,145	)			(1,558,306	)
Cash flows from investing activities:
Acquisition of undeveloped acreage			(305,000	)			(303,814	)
Drilling capital expenditures			(92,708	)			(429,678	)
Sale of oil and natural gas properties			-				640,000
Additions to office furniture and fixtures			(10,815	)			(25,081	)
Net cash used in investing activities			(408,523	)			(118,573	)
Cash flows from financing activities:
Proceeds from issuance of common stock			5,327,700				-
Proceeds from issuance of debt			1,000,000				1,429,902
Proceeds from issuance of Series A Convertible Preferred Stock			6,794,000
Dividend payments on preferred stock			(40,681	)			-
Repayment of debt			(5,071,720	)			(369,123	)
Net cash provided by financing activities			8,009,299				1,060,779
Change in cash			1,307,631				(616,101	)
Cash at beginning of period			165,365				970,035
Cash at end of period		$	1,472,996			$	353,934
Supplementary Cash Flow Information:
Cash paid during the period for:
Interest		$	1,170,300			$	1,614,243
Income taxes			-				-
Non-cash investing and financing activities:
Common stock issued for accrued convertible debenture interest		$	148,129				830,660
Acquisition of oil and natural gas assets for accounts payable and other accrued expenses		$	5,410,467				-
Transfer from derivative liability to equity classification		$	5,031,070				-
Issuance of common stock for payment of convertible debentures		$	8,851,871				-
Issuance of redeemable preferred stock for payment of term note		$	2,000,000				-
Conveyance of property for payment of term note		$	14,833,311				-
Disposition of asset retirement obligation (liability) through the conveyance of property for payment of term loan		$	973,135				-

 

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

 

 

LILIS ENERGY, INC.

NOTES TO CONDENSED FINANCIAL STATEMENTS

(UNAUDITED)

 

NOTE 1 – ORGANIZATION

 

Lilis Energy, Inc. (“Lilis”, “Lilis Energy”, and the “Company) is an independent oil and natural gas exploration and production company focused on the Denver-Julesburg Basin (“DJ Basin”), where it holds approximately 84,000 net acres. Lilis drills, operates and produces oil and natural gas wells through the Company’s land holdings located in Colorado, Wyoming, and Nebraska.

 

All references to production, sales volumes and reserves quantities are net to the Company’s interest unless otherwise indicated.

 

NOTE 2 – LIQUIDITY AND MANAGEMENT PLANS

 

As of September 30, 2014, the Company had a negative working capital balance and a cash balance of approximately $6.62 million and $1.47 million, respectively. Also as of September 30, 2014, the Company had $6.68 million, net, outstanding under its 8% Senior Secured Convertible Debentures (the “Debentures”). The Debentures were originally to mature on January 15, 2015; however, in connection with the Company’s entry into the Credit Agreement (discussed below) in January 2015. As of the date of the report, the Company has entered into an extension agreement with the holders of the Debentures which extends the maturity date until January 8, 2018. The maturity date now coincides with the maturity date of the Credit Agreement.

 

On January 8, 2015, the Company entered into a credit agreement with Heartland Bank (the “Credit Agreement”) which provides for a three-year senior secured term loan in an initial aggregate principal amount of $3,000,000, which principal amount may be increased to a maximum principal amount of $50,000,000 at the request of the Company, subject to certain conditions, and pursuant to an accordion advance provision in the Credit Agreement (the “Term Loan”). The availability of additional funds is generally based on the value of the Company’s proved developed producing (“PDP”) and proved undeveloped (“PUD”) reserves. The Company intends to use proceeds borrowed under the Credit Agreement to fund producing property acquisitions in North America, drill wells in the core of the Company’s lease positions and to fund working capital (See Note 13-Subsequent Events.)

 

As of February 23, 2015, the Company has $2.40 million in cash on hand and is currently producing approximately 70 barrels of oil equivalent (“BOE”) a day from eight economically producing wells.

 

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

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

 

 

NOTE 3 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

 

Basis of Presentation and Restatement

 

The condensed financial statements and accompanying footnotes are prepared in accordance with generally accepted accounting principles in the United States (“U.S. GAAP”).

 

The unaudited condensed financial information furnished herein reflects all adjustments, consisting solely of normal recurring items, which in the opinion of management are necessary to fairly state the financial position of the Company and the results of its operations for the periods presented.

 

This report should be read in conjunction with the Company’s financial statements and notes thereto included in the Company’s Form 10-K for the year ended December 31, 2013 filed with the Securities and Exchange Commission (the “SEC”) on June 11, 2014. The results of operations for the interim periods presented are not necessarily indicative of results for the entire year ending December 31, 2014. The financial statements in this Quarterly Report on Form 10-Q include the restated figures for the comparative periods in 2013, as provided in Amendment No. 1 to Form 10-Q/A to the Quarterly Report on Form 10-Q of Lilis Energy for the quarterly period ended September 30, 2013 (the “Amended Q3 2013 Report”).

 

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

 

The Company has evaluated the effect of the error on all Relevant Periods in accordance with Staff Accounting Bulletin (“SAB”) 99 and SAB 108 and determined that the impact of the error on its previously filed annual financial statements for the fiscal years ended December 31, 2011, December 31, 2012, and December 31, 2013 was not material. However, the Company has concluded that the impact of these non-cash items in its previously filed quarterly financial statements for the fiscal quarters ended September 30, 2013, March 31, 2014 and June 30, 2014 was sufficiently material to warrant restatement of the Company’s previously filed Quarterly Reports on Form 10-Q for those periods. In addition, the Company will restate the immaterial amounts for the fiscal years ended December 31, 2011, December 31, 2012, and December 31, 2013 in its Annual Report on Form 10-K for the fiscal year ended December 31, 2014. The opening balance as of January 1, 2013 will be adjusted in the annual report on Form 10K for the fiscal year ended December 31, 2014 to reflect the restatement of the immaterial amounts for the fiscal year ended December 31, 2011 and 2012. The Company filed amended quarterly reports on Form 10-Q/A for the fiscal quarters ended September 30, 2013, March 31, 2014 and June 30, 2014 on February 23, 2015. This Quarterly Report should be read in conjunction with those amended quarterly reports on Form 10-Q/A, which resulted in retroactive changes to financial statements for those periods, including changes to net loss and net loss per common share.

 

Use of Estimates

 

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

 

The most significant financial estimates are associated with the Company’s estimated volumes of proved oil and natural gas reserves, asset retirement obligations, assessments of impairment imbedded in the carrying value of undeveloped acreage and undeveloped properties, fair value of financial instruments, estimated convertible debentures derivative liabilities, depreciation and accretion, income taxes and contingencies.

 

Oil and Natural Gas Properties

 

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

 

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

 

 

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

 

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

 

Under the full cost method of accounting, capitalized oil and natural gas property costs less accumulated depletion and net of deferred income taxes may not exceed an amount equal to sum of: i.) The present value, discounted at 10%, of estimated future net revenues from proved oil and natural gas reserves, plus ii.) The cost of unproved properties not subject to amortization (without regard to estimates of fair value), or estimated fair value, if lower, of unproved properties that are not subject to amortization.  Should capitalized costs exceed this ceiling, an impairment expense is recognized. As of September 30, 2014, the Company tested its oil and natural gas assets under the ceiling test which yielded no impairment.

 

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

 

Wells in Progress

 

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

 

Asset Retirement Obligation

 

The Company incurs asset retirement obligations for certain oil and natural gas assets at the time they are placed in service.  The fair values of these obligations are recorded as liabilities on a discounted basis. The costs associated with these liabilities are capitalized as part of the related assets and accretion.  Over time, the liabilities are accreted for the change in their present value.

 

For purposes of depletion calculations, the Company also includes estimated dismantlement and abandonment costs, net of salvage values, associated with future development activities that have not yet been capitalized as asset retirement obligations.

 

Oil and Natural Gas Revenue

 

Sales of oil and natural gas, net of any royalties, are recognized when oil and natural gas have been delivered to a custody transfer point, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser upon delivery, collection of revenue from the sale is reasonably assured, and the sales price is fixed or determinable. Virtually all of the Company’s contracts’ oil and natural gas pricing provisions are tied to a NYMEX market index, with certain local differential adjustments based on, among other factors, whether a well delivers oil or natural gas to a gathering, refinery, marketing company, or transmission line and prevailing local supply and demand conditions. The price of the oil and natural gas fluctuates to remain competitive with other local oil suppliers.

 

 

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 shares issuable upon the conversion of debt or preferred stock, and exercise of stock purchase warrants and options, are excluded from the calculation when their effect would be anti-dilutive. As of September 30, 2014 and 2013 shares underlying options, warrants, preferred stock and convertible debentures have been excluded from the diluted share calculations as they were anti-dilutive as a result of net losses incurred.

 

The Company had the following common stock equivalents at September 30, 2014 and 2013:

 

As of		September 30, 2014				September 30, 2013
Stock Options			3,600,000				3,800,000
Series A Preferred Stock			3,112,033				-
Stock Purchase Warrants			17,749,281				6,773,913
Convertible debentures			3,364,016				3,665,859
			27,825,330				14,239,772

 

Recent Accounting Pronouncements

 

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. The Company is currently evaluating the provisions of ASU 2014-09 and assessing the impact, if any, it may have on its condensed financial position and results of operations.

 

In June 2014, FASB issued Accounting Standards Update 2014–12, Compensation – Stock Compensation (Topic 718), which clarifies accounting for share–based payments for which the terms of an award provide that a performance target could be achieved after the requisite service period. That is the case when an employee is eligible to retire or otherwise terminate employment before the end of the period in which a performance target could be achieved and still be eligible to vest in the award if and when the performance target is achieved. The updated guidance clarifies that such a term should be treated as a performance condition that affects vesting. As such, the performance target should not be reflected in estimating the grant–date fair value of the award. Compensation cost should be recognized in the period in which it becomes probable that the performance target will be achieved and should represent the compensation cost attributable to the periods for which the requisite service has already been rendered. The guidance will be effective for the annual periods (and interim periods therein) ending after December 15, 2015. Early application is permitted. The Company is currently evaluating the effects of ASU 2014–12 on the condensed financial statements.

 

 

In August 2014, the Financial Accounting Standards Board issued Accounting Standards Update 2014–15, Presentation of Financial Statements – Going Concern.  The Update provides U.S. GAAP guidance on management’s responsibility in evaluating whether there is substantial doubt about a company’s ability to continue as a going concern and about related footnote disclosures. For each reporting period, management will be required to evaluate whether there are conditions or events that raise substantial doubt about a company’s ability to continue as a going concern within one year from the date the financial statements are issued.  This Accounting Standards Update is the final version of Proposed Accounting Standards Update 2013–300—Presentation of Financial Statements (Topic 205): Disclosure of Uncertainties about an Entity’s Going Concern Presumption, which has been deleted. The Company is currently evaluating the effects of ASU 2014–15 on the condensed financial statements.

 

Management does not believe that these or any other recently issued, but not yet effective accounting pronouncements, if adopted, would have a material effect on the accompanying condensed financial statements.

 

Subsequent Events

 

The Company evaluates subsequent events through the date the condensed financial statements are issued.

  

NOTE 4 – OIL AND NATURAL GAS PROPERTIES

 

On September 2, 2014, the Company entered into an agreement to convey its interest in 31,725 evaluated and unevaluated net acres located in the Denver Julesburg Basin and the associated oil and natural gas production (the “Hexagon Collateral”) to its primary lender, Hexagon, LLC (“Hexagon”) in exchange for extinguishment of all outstanding debt and accrued interest obligations owed to Hexagon aggregating to $14,833,311. The conveyance assigned all assets and liabilities associated with the property, which includes PDP and PUD reserves, plugging and abandonment, and other assets and liabilities associated with the property. Pursuant to the agreement, the Company also issued to Hexagon $2.0 million in Conditionally Redeemable 6% Preferred Stock, which is recognized as temporary equity.

 

Under the full cost method, sales or abandonments of oil and natural gas properties, whether or not being amortized, are accounted for as adjustments of capitalized costs, with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil and natural gas attributable to the cost center. The conveyance to Hexagon represented greater than 25 percent of the Company’s proved reserves of oil and natural gas attributable to the full cost pool, as a result, there was a significant alteration in the relationship between capitalized costs and proved reserves of oil and natural gas attributable to the full cost pool. Total capitalized costs within the full cost pool are allocated on the basis of the relative fair values of the properties sold and those retained due to substantial economic differences between the properties sold and those retained.

 

The following table represents an allocation of the transaction:

 

Conveyance of oil and natural gas property to extinguish the obligation of debt and accrued interest payable		$	14,833,311
Add: disposition of asset retirement obligations			973,135
Net value of liabilities satisfied upon conveyance		$	15,806,446
Oil and natural gas properties (full cost method), at cost
Evaluated oil and natural gas properties		$	31,022,171
Wells in progress, transferred to evaluated oil and natural gas properties			510,895
Unevaluated oil and natural gas properties, transferred to evaluated oil and natural gas properties			6,026,297
Total evaluated oil and natural gas properties			37,559,363
Accumulated depletion			(21,058,451	)
Net oil and natural gas properties conveyed, at cost			16,500,912
Conditionally 6% Redeemable Preferred Stock			2,000,000
Loss on conveyance of evaluated oil and natural gas properties			(2,694,466	)
Net value of transaction		$	15,806,446

 

 

NOTE 5 – WELLS IN PROGRESS

 

As of September 30, 2014 and December 31, 2013, the Company had $6.04 million and $1.15 million of wells in progress, respectively. Wells in progress are related to certain wells in the Company’s core development program within the Northern Wattenberg field. The Company has capitalized and accrued approximately $5.70 million of costs through September 30, 2014 associated with these wells, which are currently in dispute.

 

The dispute relates to the Company ownership in certain wells being reduced and or eliminated from a possible farm-out.  The operator of the producing wells claims the Company entered into a farm-out which will reduce the Company’s ownership in the wells. As of February 23, 2015, the Company is currently attempting to negotiate a settlement to this dispute or will pursue litigation to resolve the dispute. The Company will continue analyzing the ownership of the wells on a periodic basis to determine if any impairment is deemed necessary. If the dispute is resolved in favor of the Company, the value of the assets will be transferred to the full cost pool and the accrual of $5.20 million will be relieved from accrued expenses.

 

During 2014, the Company transferred $0.47 million from wells-in progress to developed oil and natural gas properties for one of its other wells in Northern Wattenberg, when it became producing and economic. The amount transferred to producing properties represents 12.5% of the total 25% interest owned by the Company. The remaining 12.5% ownership in the well is currently being accrued at $0.50 million for the authorization for expenditure to drill the wells, since the remaining ownership is being disputed by the mineral owners. The Company purchased the rights from both royalty owners which claimed ownership of the mineral rights. The Company has secured its 12.5% ownership by paying both owners $0.10 million (total $0.20 million). The payment was recorded as an asset to obtain the right to the minerals. By securing the interest with both interest owners, the Company’s interest will remain at 25%.

 

The mineral owners are disputing the validity of an overriding royalty interest, and as a result, the operator of the well is currently holding revenues from the Company until the dispute is resolved. The Company believes the well is near payout and this should be resolved in the near future. The Company is currently accruing the remaining 12.5% authorization of expenditure and deferring the revenue in a suspense receivable account. As of February 23, 2015, the Company received notification that the settlement between both royalty owners has been settled. As a result, the Company is working with the operator to receive payment of its interest.

 

NOTE 6 - DERIVATIVES

 

Oil Price Hedging

 

The Company is exposed to fluctuations in crude oil prices for all of its production. In order to mitigate the effect of commodity price volatility and enhance the predictability of cash flows relating to the marketing of the Company’s crude oil, from time to time, the Company enters into crude oil price hedging arrangements with respect to a portion of its expected production. Realized gains and losses are recorded as income or expenses in the periods during which applicable contracts mature and settle. As of December 31, 2013, such hedges were not material and as of September 30, 2014, the Company did not maintain any commodity derivatives.

 

NOTE 7 - FAIR VALUE OF FINANCIAL INSTRUMENTS

 

The Company measures the 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 accounts receivable, accounts payable, accrued expenses and interest payable approximate fair value due to the short-term nature or maturity of the instruments.

 

Convertible Debentures Conversion Derivative Liability

 

As of September 30, 2014, the Company had $6.68 million, net, in remaining Debentures which are convertible at any time at the holders’ option into shares of Common Stock at $2.00 per share, or 3,364,016 underlying conversion shares. The debentures have elements of a derivative from the ability for certain adjustments, including both the conversion option and the price protection embedded in the Debentures. The conversion option allows the Debenture holders to convert their Debentures to the underlying common stock at $2.00. When the price of the common stock exceeds $2.00, it is more attractive for the Debenture holders to convert. Adversely, the price protection protects the holder of the Debenture for any capital raises with a strike price lower than $2.00 per share. The Company values this conversion liability at each reporting period using a Monte Carlo pricing model.

 

Common stock incentive options

 

The Executive Stock Incentive Options Bonus was issued on September 16, 2013 as a part of the employment agreement with the current Chief Executive Officer. The incentive bonus contains a target provision, whereby the bonus amount to be earned by the executive may vary between 0% and 300%, depending on the Company achieving certain operating milestones. The change in fair value for the common stock incentive option bonus is recorded in general and administrative expenses.

 

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

 

September 30, 2014:

 

		Level 1				Level 2				Level 3				Total
Liabilities
Convertible debentures conversion derivative liability		$	-			$	-			$	(1,540	)		$	(1,540	)
Common stock incentive options for executive employment agreements compensation with both market and performance factors.			-				-				(110	)			(110	)
Total liability, at fair value		$	-			$	-			$	(1,650	)		$	(1,650	)

 

December 31, 2013:

 

		Level 1				Level 2				Level 3				Total
Liabilities
Common stock  incentive options for executive employment agreements compensation with both market and performance factors		$	-			$	-			$	(145	)		$	(145	)
Convertible debentures conversion derivative liability		$	-			$	-			$	(605	)		$	(605	)
Total liability, at fair value		$	-			$	-			$	(750	)		$	(750	)

 

 

The following table provides a summary of changes in fair value of the Company’s Level 3 financial assets and liabilities:

 

For the nine months ended September 30, 2014 (in thousands)		Executive compensation liability				Convertible  debentures derivative  liability				Total
Beginning balance, January 1, 2014		$	(145	)		$	(605	)		$	(750	)
Change in fair value of the common stock executive employment agreement			35				-				35
Change in fair value of the convertible debentures conversion derivative liability							(5,966	)			(5,966	)
Reclassification of convertible debenture conversion derivative liability to additional paid in capital upon conversion of debenture			-				5,031				5,031
Ending balance, September 30, 2014		$	(110	)			(1,540	)			(1,650	)

 

For the three months ended September 30, 2014 (in thousands)		Executive compensation liability				Convertible debentures derivative  liability				Total
Beginning balance, June 1, 2014		$	(325	)		$	(968	)		$	(1,293	)
Change in fair value of the common stock executive employment agreement			215				-				215
Change in fair value of the convertible conversion debentures derivative liability			-				(572	)			(572	)
Ending balance, September 30, 2014		$	(110	)			(1,540	)			(1,650	)

 

For the nine months ended September 30, 2013 (in thousands)		Convertible notes derivative  liability
Beginning balance, January 1, 2013		$	(694	)
Change in fair value of the convertible debentures conversion derivative liability			48
Ending balance, September 30, 2013			(646	)

 

For the three months ended September 30, 2013 (in thousands)		Convertible  debentures derivative  liability
Beginning balance, June 30, 2013		$	(427	)
Change in fair value of the convertible debentures derivative			(218	)
Ending balance, September 30, 2013			(646	)

 

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

 

NOTE 8 – LOAN AGREEMENTS

 

The Company’s term loan and Debenture for the period ended September 30, 2014 and December 31, 2014, consists of the following:

 

(thousands, except percentages)		As of September 30, 2014				As of December 31, 2013
10% Hexagon term loans		$	-			$	18,774
8% Convertible Debentures			6,728				15,580
Total			6,728				34,354
Unamortized debenture discount			(45	)			(993	)
Total debt, net of discount			6,683				33,361
Less: amount due within one year			-				(10,663	)
Long-term debt due after one year		$	6,683			$	22,698

 

 

10% Term Loans

 

Prior to September 2, 2014, the Company had three term loans with Hexagon, its senior lender, with an aggregate outstanding principal amount of approximately $19.83 million. The loans required the Company to make monthly payments of $0.23 million 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.

 

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 an initial cash payment of $5.0 million reducing the total principal and interest due under the term loan from $19.83 million to $14.83 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 first settlement agreement was superseded by the final settlement agreement which is discussed below.

  

On September 2, 2014, the Company entered into the Final Settlement Agreement with Hexagon which replaced the First Settlement Agreement, pursuant to which, in exchange for full extinguishment of all amounts outstanding under the term loans (approximately $14.83 million in principal and interest as of the settlement date), the Company assigned Hexagon the Hexagon Collateral, which consisted of approximately 32,000 net acres including 17 producing wells that consisted of several economic wells which secured properties with PDP reserves and PUD reserves with a carrying value of approximately $16.5 million. The Company also conveyed $0.97 million in asset retirement obligations (“ARO”) for the 17 active and several non-producing wells. In addition to the conveyance of oil and natural gas property, the Company issued to Hexagon $2,000,000 in 6% Conditionally Redeemable Preferred Stock with a par value of $0.0001, stated value of $1,000 and dividends paid on a quarterly basis. As a result of this conveyance, the Company recorded a loss on conveyance of property during the three and nine months ended September 30, 2014 of approximately $2.7 million.

 

8% Convertible Debentures

 

In numerous separate private placement transactions between February 2011 and October 2013, the Company issued an aggregate of approximately $15.6 million of Debentures, secured by mortgages on several of its properties. The Debentures are currently convertible at the holders' option into shares of Common Stock at $2.00 per share, subject to certain adjustments which include a convertible option and price protection, 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. The interest option price is calculated using a 10 day VWAP discounted by 10% and applied to the outstanding interest.

 

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 (approximately $8.85 million of principal and $0.15 million in interest) was converted by the holders to shares of 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 (see Inducement Expense, discussed below).  As of September 30, 2014, the Company had $6.68 million, net, 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.

 

During September 30, 2014 and December 31, 2013, the Company valued the conversion feature associated with the Debentures at $1.54 million and $0.61 million, respectively. The Company used the following inputs to calculate the valuation of the derivative as of September 30, 2014: volatility 70%; conversion price $2.00; stock price $2.25; and present value of conversion feature $0.47 per convertible share. For the year ended December 31, 2013, the Company valued the derivative using the following inputs: volatility 70%, stock price $2.32, conversion price $4.25, risk free rate 0.38%, and present value of conversion feature of $0.17 per convertible share. The Company utilized a Monte Carlo model to value both conversion features.

 

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 waived their right to declare a default in respect of that matter.

 

The Debentures were to mature on January 15, 2015; however, as of the date of this filing, the Company has received waivers from each Debenture holders extending the maturity date thereunder to match the maturity date of the Credit Agreement to January 8, 2018.

 

Convertible Debenture Interest

 

During the nine months ended September 30, 2014, the Company elected to fund their interest payment for their convertible debentures with stock and issued 70,000 shares valued at $0.15 million which is an add back to accrued expense in the cash flow and further disclosed in the supplemental disclosure. The interest was accrued for past interest from November 15, 2013 to January 2014.

 

 

Debenture Conversion Agreement

 

As of September 30, 2014, the Company has $6.68 million, net, outstanding convertible debentures.

 

		Convertible Debentures				Convertible Debentures Debt Discount				Total
Balance at 12/31/2013		$	(15,579,902	)		$	855,536			$	(14,724,366	)
Accretion of debt discount			-				(433,725	)			(433,725	)
Less: conversion of convertible debenture			8,851,871				(377,079	)			8,474,792
Balance at 9/30/2014			(6,728,031	)			44,732				(6,683,299	)

 

Inducement Expense

 

On January 31, 2014, the Company entered into a Debenture Conversion Agreement (the “Conversion Agreement”) with all of the holders of the Debentures.  Under the terms of the Conversion Agreement, $9.0 million of the approximately $15.6 million in Debentures outstanding as of January 30, 2014 immediately converted to shares of common stock at a price of $2.00 per common share.  As additional inducement for the conversions, the Company issued warrants to the converting Debenture holders to purchase one share of Common Stock, at an exercise price equal to $2.50 per share (the “Warrants”), for each share of Common Stock issued upon conversion of the Debentures. Utilizing Black Scholes option price model, with a 3 year life and 65% volatility, risk free rate of 0.2%, and the market price of $3.05. The Company recorded an inducement expense of $6.61 million, during the nine months ended September 30, 2014 for the warrants issued to induce the convertible debentures to convert their debt to Common Stock. T.R. Winston acted as the investment banker for the Conversion Agreement and was compensated by issuing 225,000 shares of the Company’s common stock and valued at a market price of $3.05 per share. During the nine months ended September 30, 2014, the Company valued the investment banker compensation at $0.69 million, which was expensed immediately.

 

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

 

NOTE 9 - COMMITMENTS and CONTINGENCIES

 

Environmental and Governmental Regulation

 

At September 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 natural gas industry legislation and administrative regulations are periodically changed for a variety of political, economic, and other reasons. As of September 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, Tracinda, served various writs of garnishment on the Company to enforce a judgment against Mr. Parker seeking, among other things, shares of unvested restricted stock. The Company asserted rights to lawful set-offs and deductions in connection with certain tax consequences, which may be material to the Company. The underlying judgment against Mr. Parker was appealed to the Colorado Court of Appeals and, by Order dated October 17, 2013, that Court reversed the trial court with respect to Mr. Parker’s claims of waiver, estoppel and mitigation of damages and remanded with instruction to enter judgment for Mr. Parker. The Court of Appeals also ordered the trial court to conduct further proceedings to determine the amount of damages to award Mr. Parker on his breach of contract claim. The trial court conducted a later hearing and found in its Findings of Fact, Conclusions of Law and Order dated January 9, 2015, in favor of Mr. Parker on his claim for breach of contract, awarding him $6,981,302.60. Tracinda’s Motion for Amendment of the Court’s January 9 Findings and Conclusions is pending.

In re Roger A. Parker: Tracinda Corp. v. Recovery Energy, Inc. and Roger A. Parker, United States Bankruptcy Court for the District of Colorado, Case No. 13-10897-EEB. On June 10, 2013, Tracinda Corp. (“Tracinda”) filed a complaint (Adversary No. 13-01301 EEB) against the Company and Roger Parker in connection with the personal bankruptcy proceedings of Roger Parker, alleging that the Company improperly failed to remit to Tracinda certain property in connection with a writs of garnishment issued by the Denver District Court (discussed above). The Company filed an answer to this complaint on July 10, 2013. A trial date has not been set and, by Order dated February 2, 2015, the Bankruptcy Court ordered that the Adversary Proceeding be held in abeyance pending final resolution of the state-court action (2011CV561). The Company is unable to predict the timing and outcome of this matter.

 

From time to time the Company is involved in legal proceedings arising in the ordinary course of business. The Company believes there is no other litigation pending that could have, individually or in the aggregate, a material adverse effect on its results of operations or financial condition.

 

 

NOTE 10 - SHAREHOLDERS’ EQUITY

 

January 2014 Private Placement

 

In January 2014, the Company entered into and closed a series of subscription agreements with accredited investors, pursuant to which the Company issued an aggregate of 2,959,125 units, with each unit consisting of (i) one share of the Common Stock and (ii) one three-year warrant to purchase one share of Common Stock, at an exercise price equal to $2.50 per share (together, the “Units”), for a purchase price of $2.00 per Unit, for aggregate gross proceeds of $5,918,250 (the “January Private Placement”).  The warrants are not exercisable for six months following the closing of the January Private Placement. As of February 23, 2015, the underlying common shares have not been registered. The warrants still can be exercised without an effective registration statement on file. The Company will be filing a registration statement during the year 2015. The Company valued the warrants within the Unit, utilizing a Black Scholes Option Pricing Model using a volatility calculation of 65%, and 3 year term, the relative fair value allocated to warrants were approximately $1.69 million. The Company paid $1.06 million in financing fees to T.R. Winston.

 

Series A 8% Convertible Preferred Stock

 

On May 30, 2014, the Company consummated a private placement of 7,500 shares of Series A Preferred, along with detachable warrants to purchase up to 1,556,016 shares of Common Stock at an exercise price of $2.89 per share, for aggregate proceeds of $7.50 million. The Series A Preferred has a par value of $0.0001 per share, a stated value of $1,000 per share, a conversion price of $2.41 per share, and a liquidation preference to any junior securities. Except as otherwise required by law, holders of Series A Preferred shall not be entitled to voting rights, except with respect to proposals to alter or change adversely the powers, preferences or rights given to the Series A Preferred, authorize or create any class of stock ranking senior to the Series A Preferred as to dividends, redemption or distribution of assets upon liquidation, amend its certificate of incorporation or other charter documents in any manner that adversely affects any rights of the Preferred Stock holder, or increase the number of authorized Series A Preferred Stock. 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 payable a day after the end of each quarter. 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.

 

The Series A Preferred is classified as equity based on the following criteria: i) the redemption of the instrument at the control of the Company; ii) the instrument is convertible into a fixed amount of shares at a conversion price of $2.41; iii) the instrument is closely related to the underlying Company’s common stock; iv) the conversion option is indexed to the Company’s stock; v) the conversion option cannot be settled in cash and only can be redeemed at the discretion of the Company; vi) and the Series A Preferred is not considered convertible debt.

 

In connection with the issuance of the Series A Preferred, the Company also issued a warrant for 50% of the amount of shares of Common Stock into which the Series A Preferred is convertible.

 

In connection with issuance of the Series A Preferred, the beneficial conversion feature (“BCF”) was valued at $2.25 million and the fair value of the warrant were valued at $1.35 million. The BCF was valued at $3.6 million was considered a deemed dividend and the full amount was expensed immediately.

 

The Company determined the transaction created a beneficial conversion feature which is calculated by taking the net proceeds of $6.79 million and valuing the warrants as of May 2014, utilizing a Black Scholes option pricing model. The inputs for the pricing model are: $2.48 market price per share; exercise price of $2.89 per share; expected life of 3 years; volatility of 70%; and risk free rate of 0.20 %. The Company calculated the total consideration given to be $8.40 million comprised of $5.50 million for the Series A Preferred and $1.30 million for the warrants. The Company deemed the value of the beneficial conversion feature to be $2.21 million and immediately accreted that amount as a deemed dividend. As of September 30, 2014, the Company has accrued a cumulative dividend for $0.11 million, which was paid fully on October 1, 2014. 

 

Conditionally Redeemable 6% Preferred Stock

 

In August 2014, the Company designated 2,000 shares of its authorized preferred stock as “Conditionally Redeemable 6% Preferred Stock” (“Redeemable Preferred”). The Redeemable Preferred has the same par value and stated value characteristics and liquidation preferences of the Series A preferred stock, yet the 6% Conditionally 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 Redeemable Preferred Stock bears a 6% dividend per annum, payable quarterly, and is redeemable at face value (plus any accrued and unpaid dividends) at any time at the Company’s option, or at the Holders option upon the Company’s achievement of certain production and reserves thresholds. As of September 30, 2014, the Company accrued $0.01 million of accrued dividends during the period. In September 2014, the 2,000 shares of Redeemable Preferred Stock were issued pursuant to the Settlement Agreement with Hexagon at a value of $2.0 million.

 

Consulting Agreement with Market Development Consulting Group, Inc. (“MDC”)

 

In January 2014, the Company entered into a consulting agreement with MDC, a public relations company. The agreement provided for the issuance by the Company of 90,000 shares of Common Stock, 350,000 warrants to purchase common shares, and cash of $0.1 million a month.

 

The 90,000 shares of Common Stock were issued on February 7, 2014 with an original market price of $3.35 for a total value of $0.30 million. The fair value of the shares amortized over the life of the contract, or until December 31, 2014 which were revalued at each reporting period. As of September 30, 2014, the Company had 25,322 shares remaining to vest at a value of $0.06 million. During the three and nine months ended September 30, 2014, the Company amortized the non-cash consulting expense for the Common Stock issued of $0.06 million and $0.20 million, respectively.

 

The 350,000 warrants were valued using the Black Scholes option pricing model with the following inputs: (i) 350,000 warrants to purchase common stock; (ii) assumed stock price $2.33; (iii) strike price $4.25 for 100,000 and $2.33 for 250,000 warrants; volatility 45%; risk free rate of 0.20%; and expected life of 5 years. The valuation yielded a value of $0.40 million. The warrant value vested immediately and was recognized as stock based non-employee compensation.

 

 

Investment Banking Agreement

 

During the year ended December 31, 2013, the Company was party to a one-year, non-exclusive investment banking agreement with T.R. Winston, pursuant to which the Company issued to T.R. Winston 100,000 common shares, and 900,000 common stock purchase warrants. All warrants have a term of three years and a strike price of $4.25 per share, risk free rate of 0.20%, common stock price $1.880, volatility 63% valued at $0.26 million and amortized over the life of the contract. As of September 30, 2014, the full $0.26 million has been expensed through general and administrative expenses.

 

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 agreed to assist the Company in general corporate activities including but not limited to strategic planning; management and business operations; introductions to further its business goals; advice and services related to the Company’s growth initiatives; 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 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 issued to Bristol an option to purchase up to 1,000,000 shares with no forfeitures provisions. 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 Shares 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 does not include any cash payment. The Company used a Black Scholes option pricing model to value the warrants/options using the following variables: (i) warrants/options issued 1,000,000 total (as stated above, the Company will only issue a total of 1,000,000 shares of Common Stock under the option or the warrant, but no more than 1,000,000 shares in the aggregate); (ii) stock price $1.47; (iii) exercise price $ 2.00; expected life of 5 years; volatility of 60%; risk free rate of 0.20% for a total value of $0.62 million, which was expensed immediately. The warrants/options did not have any cancellation or forfeiture provisions in the contract and as a result, the amounts were fully recognized at the date of issuance.

 

Warrants

 

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

 

		Warrants				Weighted- Average Exercise Price
Outstanding at December 31, 2013			6,773,913			$	5.24
Granted – January 2014 private placement			3,326,340				2.50
Granted – May 2014 preferred private placement			1,556,017				2.89
Granted-debenture conversion agreement			4,743,011				2.5
Granted-issued to service consulting firms			350,000				2.88
Granted – Consulting Agreement with Bristol Capital			1,000,000				2.00
Exercised, forfeited, or expired			-				-
Outstanding at September 30, 2014			17,749,281			$	3.25

 

The weighted average remaining contract life of the warrants, as of September 30, 2014, was 1.09 years. These warrants are valued at $63.17 million. These warrants are cash warrants and the holders must pay the Company the full exercise price in cash. The intrinsic value of the warrants as of September 30, 2014 is $0.25 million.

 

 

NOTE 11 - SHARE BASED AND OTHER COMPENSATION

 

Share-Based Compensation

 

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

 

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

 

During the nine months ended September 30, 2014, the Company granted 324,428 shares of restricted common stock and 1,500,000 stock options, to employees, directors and consultants, which 2,212,084 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 1,500,000 options to purchase common stock were subsequently forfeited upon the resignation of Robert A. Bell, ex-COO/ President. As a result, the Company currently has 1,852,928 restricted shares and 3,600,000 options to purchase common shares outstanding to employees and directors. The restricted shares are included in the outstanding share count in the balance sheet and at the front of this document, yet they are currently on a vesting schedule based on service. Some of the options vest based on time and other options to purchase common stock are vested based certain operating thresholds.

 

The Company recognized a restricted stock share based compensation expense of approximately $2.67 million, net of a credit of $0.31 million for cancelled Plan shares and options for the nine months ended September 30, 2014. The elements of share based compensation are as follows:

 

Restricted Stock

 

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

 

		Shares
Balance outstanding at December 31, 2013			2,024,375
Granted restricted shares			12,750
Granted restricted shares			45,011
Granted restricted shares			216,667
Granted restricted shares			50,000
Vested			(183,791	)
Expired/ cancelled			(312,084	)
Balance outstanding at September 30, 2014			1,852,928

 

As of September 30, 2014, total unrecognized compensation cost related to unvested stock grants was approximately $0.18 million, which is expected to be recognized over a weighted-average remaining service period of 1years. 

 

Employment and Separation Agreements

 

W. Phillip Marcum

 

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

 

In connection with the Marcum Agreement, the Company reversed the 200,000 unvested options previously issued to Mr. Marcum valued at $0.07 million, and reissued fully vested options, which it valued utilizing the Black Scholes option pricing model at $0.41 million. The Company used a Black Scholes option pricing model to value the 200,000 options which Mr. Marcum retained using the following variables: i) 200,000 options; ii) stock price $ 3.50; iii) strike price $1.60; volatility 65%; and a total value of $0.41 million which is expensed immediately since under the terms of his separation agreement, the Company is not to be provided any additional services.

 

 

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 “Separation Agreement”). The Separation Agreement provides, among other things, that the Company would pay to Mr. Bell an aggregate of $100,000 in cash and issue to Mr. Bell 66,667 shares of Common Stock, in addition to satisfying the Company’s outstanding obligation to pay Mr. Bell $100,000 in cash and issue to Mr. Bell 33,333 shares of Common Stock. The Separation Agreement also contains certain mutual covenants, and reaffirms the survival of certain confidentiality provisions contained in the 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. The total amount was fully expensed as of September 30, 2014 for $0.26 million.

 

In connection with the termination of his employment, Mr. Bell forfeited the 1,500,000 stock options that were unvested at the time of his termination and the Company reversed $0.30 million.

 

A .Bradley Gabbard

 

In May 2014, in connection with his resignation as CFO of the Company, A. Bradley Gabbard forfeited the 200,000 options that were unvested at the time of his termination. At the date of his resignation, the Company recorded a credit of $0.07 million into the shareholder employee compensation expense account. Additionally, Mr. Gabbard forfeited his respective 52,084 shares of unvested restricted stock, for which the Company recorded a reversal of $0.07 million.

 

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 connection with execution of an amended independent agreement, each director also agreed to receive 31,250 shares of restricted common stock in lieu of a portion of their cash salaries, to vest on April 15, 2014. During the three and nine months ended September 30, 2104, the Company recognized $0.05 million and $0.20 million, respectively.

 

Stock Options

 

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

 

		Stock				Weighted Average Exercise
		Options				Price
Outstanding at December 31, 2013			3,800,000				2.25
Granted			1,700,000				2.45
Exercised, forfeited, or expired			(1,900,000	)			(2.36	)
Outstanding at September 30, 2014			3,600,000				2.28

 

The average life of the options is 3 years and has no intrinsic value as of September 30, 2014.

 

As of September 30, 2014, the Company has 3,600,000 options outstanding which have an unrecognized expense to be expensed over the next 25 months of $0.50 million.

 

 

NOTE 12- RELATED PARTY TRANSACTIONS

 

Abraham Mirman

Transactions between the Company and Abraham Mirman

 

The Company’s Chief Executive Officer (“CEO”) is an indirect owner of a group which converted approximately $0.22 million of Debentures in connection with the $9.00 million of Debentures converted in January 2014,and was paid $0.01 million in interest at the time of the Debenture conversion.

 

During the January 2014 private placement, Mr. Mirman entered into a subscription agreement with the Company to invest $0.50 million, for which Mr. Mirman will receive 250,000 shares of stock and 250,000 warrants. The subscription agreement will not be consummated until a shareholder meeting is conducted to allow executives and board directors the ability to participate in the offering.

 

During the May Private Placement, Mr. Mirman invested $0.25 million, for which Mr. Mirman received 250 shares of Series A Preferred and 51,867 warrants.

 

In September 2013, the Company appointed Abraham Mirman as its President and in April 2014 he was appointed to serve as the Company’s Chief Executive Officer. Prior to joining the Company, Mr. Mirman was employed by TRW as its Managing Director of Investment Banking and until September 2014 continued to devote a portion of his time to serving in that role. In connection with the appointment of Mr. Mirman, the Company and TRW amended the investment banking agreement in place between the Company and TRW at that time to provide that, upon the receipt by the Company of gross cash proceeds or drawing availability of at least $30,000,000, measured on a cumulative basis and including certain restructuring transactions, subject to the Company’s continued employment of Mr. Mirman, TRW would receive from the Company a lump sum payment of $1.00 million. Mr. Mirman’s compensation arrangements with TRW provided that upon TRW’s receipt from the Company of the lump sum payment, TRW would make a payment of $1.00 million to Mr. Mirman. The Board determined in September 2014 that the criteria for the lump sum payment had been met. Mr. Mirman also received, as part of his compensation arrangement with TRW, the 100,000 common shares of the Company that were issued to TRW in conjunction with the investment banking agreement.

 

G. Tyler Runnells

Transactions between the Company and G. Tyler Runnels

 

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

 

On January 22, 2014, the Company paid TRW a commission equal to $486,000 (equal to 8% of gross proceeds at the closing of the January Private Placement). Of this $486,000 commission, $313,750 was paid in cash and $172,250 was paid in 86,125 Units. In addition, the Company paid TRW a non-accountable expense allowance of $182,250 (equal to 3% of gross proceeds at the closing of the January Private Placement) in cash. If the participation of certain of the Company’s current and former officers and directors is approved by the Company’s shareholders, the Company will pay TRW an additional commission equal to $0.06 million (equal to 8% of gross proceeds from the sale of Units of the Company’s officers and directors agreed to purchase in the January Private Placement), and the Company will pay TRW a non-accountable expense allowance of $0.02 million (equal to 3% of gross proceeds of the Units members of the Company’s officers and board of directors agreed to purchase in the January Private Placement). The Units issued to TRW were the same Units sold in the January Private Placement and were invested in the January Private Placement.

 

On January 31, 2014, the Company entered into a Debenture Conversion Agreement (the “Conversion Agreement”) with all of the holders of the Debentures.  Under the terms of the Conversion Agreement, $9.0 million of the approximately $15.6 million in Debentures outstanding as of January 30, 2014 immediately converted to shares of common stock at a price of $2.00 per common share.  As additional inducement for the conversions, the Company issued warrants to the converting Debenture holders to purchase one share of Common Stock, at an exercise price equal to $2.50 per share (the “Warrants”), for each share of Common Stock issued upon conversion of the Debentures. T.R. Winston acted as the investment banker for the Conversion Agreement and was compensated by issuing 225,000 shares of the Company’s common stock and valued at a market price of $3.05 per share. During the nine months ended September 30, 2014, the Company valued the investment banker compensation at $0.69 million, which was expensed immediately.

 

 

 

On May 19, 2014, the Company and the holders of the Debentures agreed to extend the maturity date under the Debentures until August 15, 2014, and on June 6, 2014, they agreed to further extend the maturity date under the Debentures from August 15, 2014 to January 15, 2015. In January 2015, the Company has entered into an extension agreement which extends the maturity date until January 8, 2018. The maturity date now coincides with the maturity date of the Credit Agreement.

 

On March 28, 2014, the Company and TRW entered into a Transaction Fee Agreement in connection the May Private Placement. Pursuant to the Transaction Fee Agreement, the Company agreed to compensate TRW 5% of the gross proceeds of the May Private Placement, plus a $25,000 expense reimbursement. On April 29, 2014, the Company and TRW amended the Transaction Fee Agreement to increase TRW’s compensation to 8% of the gross proceeds, plus an additional 1% of the gross proceeds as a non-accountable expense reimbursement in addition to the $25,000 originally contemplated.

 

On October 6, 2014, the Company entered into a letter agreement (the “Waiver”) with the holders of its Debentures. Pursuant to the Waiver, the holders of the Debentures agreed to waive any Event of Default (as that term is defined in the Debentures) that may have occurred prior to the date of the Waiver, including any default in connection with the Hexagon term loan, and to rescind and annul any acceleration or right to acceleration that may have been triggered thereby. In exchange for the Waiver, the Company agreed that TRW, as representative for the holders of the Debentures, would have the right to nominate two qualified individuals to serve on the Company’s Board. Mr. Runnells is one of the qualified nomination designees which TRW has elected to place on the board.

 

On May 30, 2014, the Company paid TRW a commission equal to $600,000 (equal to 8% of gross proceeds at the closing of the May Private Placement). Of this $600,000 commission, $51,850 was paid in cash to TRW, $94,150 was paid in cash to other brokers designated by TRW, and $454,000 was paid in shares of Preferred Stock. In addition, the Company paid TRW a non-accountable expense allowance of $75,000 (equal to 1% of gross proceeds at the closing of the May Private Placement) in cash.

 

From May 2013 until March 2014, the Company was party to a one-year, non-exclusive investment banking agreement with T.R. Winston, pursuant to which the Company issued to T.R. Winston 100,000 common shares, and 900,000 common stock purchase warrants. All warrants have a term of three years and a strike price of $4.25 per share, risk free rate of 0.20%, common stock price $1.880, volatility 63% valued at $0.26 million and amortized over the life of the contract. As of September 30, 2014, the full $0.26 million has been expensed through general and administrative expenses.

 

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

 

NOTE 13- SUBSEQUENT EVENTS

 

Waiver of Default under Debentures

 

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.

 

Heartland Bank

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

 

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

 

The Term Loan bears interest at a rate calculated based upon the Company’s leverage ratio and the “prime rate” then in effect. In connection with its entry into the Credit Agreement, the Company also paid a nonrefundable commitment fee in the amount of $75,000, and agreed to issue to the Lenders 75,000, 5-year warrants for every $1 million funded. An initial warrant to purchase up to 225,000 shares of the Company’s common stock at $2.50 per share was issued in connection with closing.

  

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

 

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

 

Debenture extension

As of September 30, 2014, the Company had $6.68 million, net, outstanding under the Debentures. The Debentures were originally to mature on January 15, 2015; however, as of the date of this Form 10Q, the Company has entered into an extension agreement with each of the Debenture holders which extends the maturity date until January 8, 2018. As of the date of this filing, the maturity date now coincides with the maturity date of the Credit Agreement (discussed above).

 

Convertible Debenture Interest Payment

On December 29, 2014, the Company issued 1,262,844 shares to fund $0.94 million Debenture interest obligation.

 

T.R. Winston

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

 

Executive Employment Agreement

On February 19, 2015, the Company entered into an Employment Agreement with Eric Ulwelling, its Chief Financial Officer. The Employment Agreement provides for a base salary of $175,000, a discretionary bonus equal to up to 50% of base salary, and 400,000 stock options with an exercise price equal to the greater of fair market value of the Company’s common stock on the date of execution of the Employment Agreement or $2.50 per share. One quarter of the stock options vested immediately upon grant, and the other three quarters will vest in three annual installments on the anniversary of the execution of the Employment Agreement. The Employment Agreement provides for severance and accelerated vesting of any outstanding equity award upon termination of Mr. Ulwelling’s employment by the Company without cause or by Mr. Ulwelling for good reason or in connection with a change in control, as each is defined in the Employment Agreement.

 

The foregoing description of the Employment Agreement is not complete and is qualified in its entirety by reference to the text of the full Employment Agreement, which is attached as Exhibit 10.14 hereto and is incorporated herein by reference.

 

 

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 financial statements and notes thereto included in this Quarterly Report on Form 10-Q. This discussion contains forward-looking statements that involve risks and uncertainties. Our actual results could differ materially from those anticipated in these forward-looking statements as a result of various factors including those set forth under Item “1A. Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2013.

 

General

 

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

 

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

 

Financial Condition and Liquidity

 

As of September 30, 2014, the Company had a negative working capital balance and a cash balance of approximately $6.62 million and $1.47 million, respectively. Also as of September 30, 2014, the Company had $6.68 million, net, outstanding under its 8% Senior Secured Convertible Debentures (the “Debentures”). The Debentures were originally to mature on January 15, 2015; however, in connection with the Company’s entry into the Credit Agreement (discussed below) in January 2015, as of the date of this filing, the Company has entered into an extension agreement with each of the Debenture holders which extends the maturity date until January 8, 2018. The maturity date now coincides with the maturity date of the Credit Agreement.

 

 

On January 8, 2015, the Company entered into a credit agreement with Heartland Bank (the “Credit Agreement”) which provides for a three-year senior secured term loan in an initial aggregate principal amount of $3,000,000, which principal amount may be increased to a maximum principal amount of $50,000,000 at the request of the Company, subject to certain conditions, and pursuant to an accordion advance provision in the Credit Agreement (the “Term Loan”). The availability of additional funds is generally based on the value of the Company’s proved developed producing (“PDP”) and proved undeveloped (“PUD”) reserves. The Company intends to use proceeds borrowed under the Credit Agreement to fund producing property acquisitions throughout North America, to drill wells in the core of the Company’s lease positions and to fund working capital.

 

On June 6, 2014, T.R. Winston executed a commitment to purchase or affect the purchase by third parties of an additional $15 million in Series A 8% Convertible Preferred Stock, to be consummated within ninety (90) days thereof. The agreement was subsequently extended and expired on February 22, 2015. On February 25, 2015, the Company and TRW agreed in principal to a replacement commitment, pursuant to which TRW has agreed to purchase or affect the purchase by third parties of an additional $7.5 million in Series A 8% Convertible Preferred Stock, to be consummated no later than February 23, 2016, with all other terms substantially the same as those of the original commitment. As of February 23, 2015, the Company has $2.40 million in cash on hand and is currently producing approximately 70 barrels of oil equivalent (“BOE”) a day from eight economically producing wells.

 

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

 

Restatement

 

This report should be read in conjunction with the Company’s financial statements and notes thereto included in the Company’s Form 10-K for the year ended December 31, 2013 filed with the Securities and Exchange Commission (the “SEC”) on June 11, 2014. The results of operations for the interim periods presented are not necessarily indicative of results for the entire year ending December 31, 2014. The financial statements in this Quarterly Report on Form 10-Q include the restated figures for the comparative periods in 2013, as provided in Amendment No. 1 to Form 10-Q/A to the Quarterly Report on Form 10-Q of Lilis Energy for the quarterly period ended September 30, 2013 (the “Amended Q3 2013 Report”).

 

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

 

 

The Company has evaluated the effect of the error on all Relevant Periods in accordance with Staff Accounting Bulletin (“SAB”) 99 and SAB 108 and determined that the impact of the error on its previously filed annual financial statements for the fiscal years ended December 31, 2011, December 31, 2012, and December 31, 2013 was not material. However, the Company has concluded that the impact of these non-cash items in its previously filed quarterly financial statements for the fiscal quarters ended September 30, 2013, March 31, 2014 and June 30, 2014 was sufficiently material to warrant restatement of the Company’s previously filed Quarterly Reports on Form 10-Q for those periods. In addition, the Company will restate the immaterial amounts for the fiscal years ended December 31, 2011, December 31, 2012, and December 31, 2013 in its Annual Report on Form 10-K for the fiscal year ended December 31, 2014. The opening balance as of January 1, 2013 will be adjusted. In the annual report on Form 10K for the fiscal year ended December 31, 2011 and 2012. The Company filed amended quarterly reports on Form 10-Q/A for the fiscal quarters ended September 30, 2013, March 31, 2014 and June 30, 2014 on February 23, 2015. This Quarterly Report should be read in conjunction with those amended quarterly reports on Form 10-Q/A, which resulted in retroactive changes to financial statements for those periods, including changes to net loss and net loss per common share.

 

Cash Flows

 

Cash used in operating activities during the nine months ended September 30, 2014 was $6.29 million. Cash used in operating activities and cash used in investing activities was offset by cash provided in financing activities of $8.00 million, and resulted in a corresponding increase in cash.  

 

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

 

		Nine months ended September 30,
		2014				2013
Cash provided by (used in):
Operating activities		$	(6,293	)		$	(1,558	)
Investing activities			(409	)			(119	)
Financing activities			8,009				1,061
Net change in cash		$	1,307			$	(616	)

 

During the nine months ended September 30, 2014, net cash used in operating activities was $6.29 million, compared to cash used in operating activities of $1.56 million during the nine months ended September 30, 2013, cash used in operating activities increased by $4.73 million. The changes to operating cash was predominately the increase in net loss during the nine months ended September 30, 2014 of $27.75 million compared to $7.70 million in September 30, 2013, respectively. The increase in cash used for operating activities was a direct result of the Company paying $1.00 million to TRW for financing fees in connection with closing of $30.0 million of financing and debt restructuring. Additionally, the decrease in operating cash flow was from the due diligence efforts in January 2014 related to a potential acquisition, which the Company expended $0.35 million. In addition, general and administrative went up from legal, accounting, and other professional services from the possible due diligence and several opportunities being analyzed. During the nine months ended September 30, 2014, the Company did not have these types of events. In connection with non-cash expenses, in 2014, the Company had additional non-cash charges for an inducement expense of $6.61 million $ 2.69 million for conveyance of property, and $0.68 million in fees paid to an investment bank related to conversion of convertible debt. These charges were not present in 2013.

 

During the nine months ended September 30, 2014, net cash used in investing activities was $0.41 million, compared to net cash used in investing activities of $0.12 million during the nine months ended September 30, 2013, an increase of cash used in investing activities of $0.29 million. The primary change between nine months ended September 30, 2014 and 2013 is that in 2014 the Company expended $0.40 million to acquire oil and gas assets while in 2013, the Company expended $0.76 million, respectively. The $0.76 million, for the nine months ended September 30, 2013, was offset by a sale of property of $0.64 million.

 

 

During the nine months ended September 30, 2014, net cash provided by financing activities was $8.01 million, compared $1.06 million during the nine months ended September 30, 2013, an increase of $6.96 million. The changes in financing cash during the nine months ended September 30, 2014 were primarily due to proceeds from a private placement of 3,750,000 units in January 2014 for net proceeds of $5.33 million. Investment activities were additionally increased by the proceeds from a private placement of the Series A Preferred for $7.50 million. The proceeds of the May Private Placement were offset by transaction fees paid in cash and preferred shares for $0.70 million. The proceeds from the January 2014 Private Placement were partially offset by net repayments of debt of $4.07 million.

 

Capital Resources and Budget

 

Capital Resources 

 

The Company will require substantial additional capital to fund its long-term convertible debenture obligations of $6.68 million, net, due in 2018, current capital obligations, capital budget plans, to help fund its ongoing G&A, to execute acquisitions of other oil and gas companies, and to provide an additional capital and to generally improve its working capital position.  We anticipate that such additional funding will be provided by a combination of new capital raising activities, including the selling of additional debt and/or equity securities in common stock and preferred stock, the receipt of additional advances under the Credit Agreement with Heartland Bank, the selling of working interests in certain un-evaluated and evaluated properties and by the development of certain undeveloped properties via arrangements with joint venture partners which may reduce our working interest in the minerals.  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.

 

The Company is party to a dispute relating to the ownership in certain wells in the Company’s Wattenberg acreage being reduced and or eliminated from a possible farm-out.  The operator of the producing wells claims the Company entered into a farm-out which would reduce the Company’s ownership in the wells. As of February 23, 2015, the Company is currently attempting to negotiate a settlement to this dispute or will pursue litigation to resolve the dispute. The Company will continue analyzing the ownership of the wells on a periodic basis to determine if any impairment is deemed necessary. If the dispute is resolved in favor of the Company, the value of the assets will be transferred to the full cost pool and the accrual of $5.20 million will be relieved from accrued expenses.

 

Capital Budget

 

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

 

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

 

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

 

 

Results of Operations

 

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

 

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

 

		Three months ended September 30,
		2014				2013
Revenues:
Oil sales		$	735,386			$	1,003,745
Gas sales			118,639				82,651
Operating fees			(39,015	)			28,331
Realized gain (loss) on commodity price derivatives			-				(43,551	)
Unrealized gain (loss) on commodity price derivatives			-				(20,000	)
Total revenues			815,010				1,051,176
Costs and expenses:
Production costs			101,593				318,322
Production taxes			71,864				102,919
General and administrative			2,935,404				1,214,029
Depreciation, depletion and amortization			252,548				532,173
Total costs and expenses			3,361,409				2,167,443
Loss from operations before loss of conveyance of property			(2,546,399	)			(1,116,267	)
Loss on conveyance of oil and gas properties			(2,694,466	)			-
Loss from operations			(2,546,399	)			(1,116,267	)
Other Income (expenses):
Other income			32,338				145
Convertible debentures conversion derivative gain (loss)			(572,427	)			(207,251	)
Interest expense			(1,130,727	)			(1,582,881	)
Total other expenses			(1,670,816	)			(1,789,987	)
Net loss		$	(6,911,681	)		$	(2,906,254	)

 

 

Total revenues

 

Total revenues were $0.82 million for the three months ended September 30, 2014, compared to $1.05 million for the three months ended September 30, 2013, decrease of $0.23 million, or 22%. The decrease in revenues was primarily due to a decrease in production volumes from the conveyance of 17 producing wells and approximately 32,000 net acres. During the three months ended September 30, 2014 and 2013, production amounts were 13,285 and 13,822 BOE, respectively, a decrease of 537 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 September 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.

 

During the three months September 2014, the work over down time can range from a few days to a 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 revenue effect of the production decrease was worsened by an overall average effective price decrease per BOE to $64.28 in 2014 from $78.60 in 2013, decrease of $14.32 or 18%. 

 

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

 

		For the
		Three Months Ended
		September 30,
		2014				2013
Product
Oil (Bbl.)			9,633				11,389
Oil (Bbls)-average price		$	76.34			$	88.13
Natural Gas (MCF)-volume			21,909				14,595
Natural Gas  (MCF)-average price (1)		$	5.41			$	5.66
Barrels of oil equivalent (BOE)			13,285				13,822
Average daily net production (BOE)			144				150
Average Price per BOE (1)		$	64.28			$	78.60
(1) Includes proceeds from the sale of Natural Gas Liquids (“NGL”)
Oil and gas production costs, production taxes, depreciation, depletion, and amortization
Average Price per BOE		$	64.28			$	78.60
Production costs per BOE			12.72				23.03
Production taxes per BOE			5.41				7.45
Depreciation, depletion, and amortization per BOE			19.01				39.00
Total operating costs per BOE			37.14				69.48

 

Commodity Price Derivative Activities

 

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

 

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

 

Production costs

 

Production costs were $0.10 million during the three months ended September 30, 2014, compared to $0.32 million for the three months ended September 30, 2013, a decrease of $0.22 million, or 69%. Decrease in production costs in 2014 resulted 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 and strain on the pumping units and downhole mechanics. Additionally, as discussed above, in September 2014, the Company conveyed 32,000 acres and 17 operated wells to their senior lender, Hexagon, LLC. Within the 17 wells, there were numerous wells which were uneconomic and which required several work overs in a period. As a result of the conveyance of these older wells, the Company now receives revenue from newer wells which have a lower lease operating cost and production tax burden. Production costs per BOE decreased to $12.72 for the three months ended September 30, 2014 from $23.03 in 2013, a decrease of $10.31 per BOE, or 45%.

 

 

Production taxes

 

Production taxes were $0.07 million for the three months ended September 30, 2014, compared to $0.10 million for the three months ended September 30, 2013, a decrease of $0.03 million, or 30%.  Decrease in production taxes was due primarily to a change 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 from which production is derived.  Additionally, as discussed above, in September 2014, the Company conveyed 32,000 acres and 17 operated wells to their senior lender, Hexagon, LLC. As a result of the conveyance, the Company now receives revenue from newer wells which have a lower lease operating cost and production tax. Production taxes per BOE decreased to $5.41 during the three months ended September 30, 2014 from $7.45 in 2013, a decrease of $2.04 or 27%. Decline in production tax is a result of the change in product mix by state. The Company produced more oil and natural gas from lower taxed states and counties in 2014 compared to 2013.

 

General and administrative

 

General and administrative expenses were $2.94 million during the three months ended September 30, 2014, compared to $1.21 million during the three months ended September 30, 2013, an increase of $1.73 million, or 143%.  Non-cash general and administrative items for the three months ended September 30, 2014 were $2.16 million compared to $0.72 million during the three months ending September 30, 2013, an increase of $1.44 million, or 200%. The increase in non-cash general and administrative expenses was the change in non-cash stock compensation for employees and consultants due to the issuance of $1.49 million of stock and options for services for both employee, board of directors and consultants; Cash general and administrative expense was $0.78 million during the three months ended September 30, 2014, compared to $0.49 million during the three months ended September 30, 2013, an increase of $0.29 million, or 59%. The increase in cash general and administrative expense for the three months ended September 30, 2014 was due to the lump sum payment of $1.00 million paid by the Company to TRW. Mr. Mirman’s compensation arrangements with TRW provided that upon TRW’s receipt from the Company of the lump sum payment, TRW would make a payment of $1.00 million to Mr. Mirman. This was offset by a reduction other general and administrative expenses which include a reduction in employee compensation due to the reduction of staff from 9 to 3 employees.

 

Depreciation, depletion, and amortization

 

Depreciation, depletion, and amortization were $0.25 million during the three months ended September 30, 2014, compared to $0.53 million during the three months ended September 30, 2013, a decrease of $0.28 million, or 53%.  Decrease in depreciation, depletion, and amortization was from (i) a decrease in production amounts in 2014 from 2013, (ii) a decrease in the depletion base for the depletion calculation due to the conveyance of assets, and (iii) a decrease in the depletion rate.  Production amounts decreased to 13,285 BOE from 13,822 BOE for the three months ended September 30, 2014 and 2013, respectively, a decrease of 537, or 4%. The decrease in depletion was based on a lower depletion base. Depreciation, depletion, and amortization per BOE decreased to $16.50 from $39.00, respectively, for the three months ended September 30, 2014 and 2013, a decrease of $22.50, or 58%.  Declines in production are primarily attributable to the conveyance of property and natural production declines related to mature producing properties.

 

Loss on conveyance of oil and gas properties

 

On September 2, 2014, the Company entered into an agreement to convey its interest in 31,725 evaluated and unevaluated net acres located in the Denver Julesburg Basin and the associated oil and natural gas production (the “Hexagon Collateral”) to its primary lender, Hexagon, LLC (“Hexagon”) in exchange for extinguishment of all outstanding debt and accrued interest obligations owed to Hexagon aggregating to $14,833,311. The conveyance assigned all assets and liabilities associated with the property, which includes PDP and PUD reserves, plugging and abandonment, and other assets and liabilities associated with the property. Pursuant to the agreement, the Company also issued to Hexagon $2.0 million in 6% Conditionally Redeemable Preferred Stock, which is recognized as temporary equity.

 

Under the full cost method, sales or abandonments of oil and natural gas properties, whether or not being amortized, are accounted for as adjustments of capitalized costs, with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil and natural gas attributable to the cost center. The conveyance to Hexagon represented greater than 25 percent of the Company’s proved reserves of oil and natural gas attributable to the full cost pool, as a result, there was a significant alteration in the relationship between capitalized costs and proved reserves of oil and natural gas attributable to the full cost pool. Total capitalized costs within the full cost pool are allocated on the basis of the relative fair values of the properties sold and those retained due to substantial economic differences between the properties sold and those retained.

 

The following table represents an allocation of the transaction:

 

Conveyance of oil and natural gas property to extinguish the obligation of debt and accrued interest payable		$	14,833,311
Add: disposition of asset retirement obligations			973,135
Net value of liabilities satisfied upon conveyance		$	15,806,446
Oil and natural gas properties (full cost method), at cost
Evaluated oil and natural gas properties		$	31,022,171
Wells in progress, transferred to evaluated oil and natural gas properties			510,895
Unevaluated oil and natural gas properties, transferred to evaluated oil and natural gas properties			6,026,297
Total evaluated oil and natural gas properties			37,559,363
Accumulated depletion			(21,058,451	)
Net oil and natural gas properties conveyed, at cost			16,500,912
Conditionally 6% Redeemable Preferred Stock			2,000,000
Loss on conveyance of evaluated oil and natural gas properties			(2,694,466	)
Net value of transaction		$	15,806,446

 

Interest Expense

 

For the three months ended September 30, 2014 and 2013, the Company incurred interest expense of approximately $1.13 million and $1.58 million, respectively, of which approximately $0.86 million and $1.68 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 $0.01 million, (ii) accretion of the convertible debentures payable discount of $0.04 million, (iii) common stock issued for interest of $0.59 million, (iv) accrued interest for term note loan fees of $0.04 million and (v) amortization of forbearance fees of $0.13 million. Cash interest is comprised of term loan cash expenses of payment. In comparative, during the three months ended September 30, 2013, non-cash interest consisted of: (i) amortization of the deferred financing costs of $0.18 million, and (ii) accretion of the convertible debentures payable discount of $0.61 million.

 

Change in derivative liability of convertible debentures

 

For the three months ended September 30, 2014 and 2013, the Company incurred a loss on change in the fair value of the derivative liability related to the convertible debentures of approximately $0.57 million and $0.21 million, respectively.

 

Results of Operations

 

Nine months ended September 30, 2014 compared to nine ended September 30, 2013

 

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

 

		Nine months ended
		September 30,
		2014				2013
Revenues:
Oil sales		$	2,414,995			$	3,320,083
Gas sales			308,629				227,853
Operating fees			37,866				118,853
Realized gain on commodity price derivatives			11,143				(23,661	)
Unrealized gain (loss) on commodity price derivatives			-				(20,000	)
Total revenues			2,772,633				3,623,128
Costs and expenses:
Production costs			739,176				877,623
Production taxes			266,774				380,958
General and administrative			8,536,882				3,566,264
Depreciation, depletion and amortization			1,211,587				1,873,002
Total costs and expenses			10,754,419				6,697,847
Loss from operations before loss on conveyance of oil and natural gas properties			(7,981,786	)			(3,074,719	)
Loss on conveyance of oil and natural gas properties			(2,694,466	)			-
Loss from operations			(10,676,252	)			(3,074,719	)
Other Income (expenses):
Other income			32,435				536
Inducement expense			(6,661,275	)			-
Convertible debentures conversion derivative gain (loss)			(5,966,236	)			93,851
Interest expense			(4,477,277	)			(4,723,624	)
Total other expenses			(17,072,353	)			(4,629,237	)
Net loss		$	(27,748,605	)		$	(7,703,956	)

 

Total revenues

 

Total revenues were $2.77 million for the nine months ended September 30, 2014, compared to $3.62 million for the nine months ended September 30, 2013, a decrease of $0.85 million, or 23%. The decrease in revenues was due primarily to a decrease in production volumes including decreases attributable to the Company’s conveyance of properties. As discussed, in September 2014, the Company conveyed 32,000 acres and 17 operated wells its senior lender, Hexagon, LLC. During the nine months ended September 30, 2014 and 2013, production amounts were 38,191 and 46,904 BOE, respectively, a decrease of 8,713 BOE, or 19%. The 2014 period declines in production were primarily attributable to few properties owned and 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 nine months ended September 30, 2014, the differential between the price per BOE received by the Company and the NYMEX crude price ranged from $11.50-$15.15 due to the excess supply of oil in the area; compared to a $7.64 basis differential from the same period in 2013.

 

 

During the nine months ended September 30, 2014, work-over rigs had limited availability due to high industry activity within the Company’s operating area, 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 following table shows a comparison of production volumes and average prices:

 

		For the
		Nine Months Ended
		September 30,
		2014				2013
Product
Oil (Bbl.)			29,353				38,464
Oil (Bbls)-average price		$	82.27			$	86.32
Natural Gas (MCF)-volume			53,028				50,642
Natural Gas (MCF)-average price (1)		$	5.82			$	4.49
Barrels of oil equivalent (BOE)			38,191				46,904
Average daily net production (BOE)			140				172
Average Price per BOE		$	71.32			$	75.64
(1) Includes proceeds from the sale of NGL's
Oil and gas production costs, production taxes, depreciation, depletion, and amortization
Average Price per BOE		$	70.60			$	75.64
Production costs per BOE			19.35				18.71
Production taxes per BOE			6.99				8.12
Depreciation, depletion, and amortization per BOE			31.72				40.08
Total operating costs per BOE			58.06				66.91

 

Commodity Price Derivative Activities

 

Changes in the market price of oil and natural gas 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 and natural gas prices.  These derivative instruments consisted exclusively of swaps.  The duration and size of our various derivative instruments varies, and depends on our view of market conditions, available contract prices and our operating strategy.

 

As of September 30, 2014, the Company did not maintain any active commodity swaps. The Company held one commodity swap during the nine months ended September 30, 2014, which matured in January 31, 2014.

 

Commodity price derivative realized gains were $0.01 million for the nine months ended September 30, 2014, compared to a realized loss of $0.02 million during the nine months ended September 30, 2013, an increase in realized gains/losses of $0.01 million or 50%.

 

 

Production costs

 

Production costs were $0.74 million during the nine months ended September 30, 2014, compared to $0.88 million for the nine months ended September 30, 2013, a decrease of $0.14 million, or 16%. Decrease in production costs in 2014 was from a decrease operated wells from the conveyance of property discussed below. The decrease in production costs was due primarily to a decrease in well count including decreases attributable to the Company’s conveyance of properties. As discussed above, in September 2014, the Company conveyed 32,000 acres and 17 operated wells to its senior lender, Hexagon, LLC. Production costs per BOE increased to $19.35 for the nine months ended September 30, 2014 from $18.71 in 2013, an increase of $0.64 per BOE, or 3%, primarily as a result of reduced volumes of BOE in 2014 and high well work frequency. During the nine months ended September 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, the Company has idled wells for regular scheduled well maintenance or other repairs. A substantial amount of the wells needed continuous replacement of rod strings and holes in the tubing. An addition, as a result of the conveyance of properties to Hexagon, the Company now receives revenue from newer wells which have a lower lease operating cost and production tax.

 

Production taxes

 

Production taxes were $0.27 million for the nine months ended September 30, 2014, compared to $0.38 million for the nine months ended September 30, 2013, a decrease of $0.11 million, or 30%.  Decrease in production taxes was due to a decrease in production and product mix per state and the decrease in well count including decreases attributable to the Company’s conveyance of properties to Hexagon. Currently, ad valorem, severance and conservation taxes range from 1% to 13% based on the state and county from which production is derived.  Production taxes per BOE decreased to $6.99 during the three months ended September 30, 2014 from $8.12 in 2013, a decrease of $1.13 or 14%. Decline in production tax is a result of the change in product mix by state. The Company produced more oil and natural gas from lower taxed states and counties in 2014 compared to 2013. 

 

General and administrative

 

General and administrative expenses were $8.57 million during the nine months ended September 30, 2014, compared to $3.57 million during the nine months ended September 30, 2013, an increase of $5.00 million, or 140%.  Non-cash general and administrative items for the nine months ended September 30, 2014 were $4.05 million compared to $1.73 million during the nine months ended September 30, 2013, an increase of $2.32 million, or 134%.  The increase in non-cash general and administrative expenses was due to an increase of $0.69 million fees associated with completing the January 2014 Private Placement; and $0.70 million for non-cash payment of the financing fees for the May Private Placement, increase in stock based compensation of $1.37 million, increase in reserve for bad debt of $0.03 million. Cash general and administrative expenses were $4.49 million during the nine months ended September 30, 2014, compared to $1.83 million during the nine months ended September 30, 2013, an increase of $4.09 million, or 223%.  The increase in cash general and administrative expenses was largely due to a $1.00 million in placement fees paid to T.R. Winston which was ultimately paid to Mr. Mirman. In connection with the appointment of Mr. Mirman, Chief Executive Officer, the Company and TRW amended the investment banking agreement in place between the Company an TRW at that time to provide that, upon the receipt by the Company of gross cash proceeds or drawing availability of at least $30,000,000, measured on a cumulative basis and including certain restructuring transactions, subject to the Company’s continued employment of Mr. Mirman, TRW would receive from the Company a lump sum payment of $1.00 million. Mr. Mirman’s compensation arrangements with TRW provided that upon TRW’s receipt from the Company of the lump sum payment, TRW would make a payment of $1.00 million to Mr. Mirman. The Board determined in September 2014 that the criteria for the lump sum payment had been met.  Furthermore, the Company paid $0.33 million for the due diligence of a potential acquisition which dissolved in Q1 2014, $0.25 million for additional investment banking firms, additional legal fees and other professional fees for acquisitions and additional support during the year of $0.65 million.

 

Depreciation, depletion, and amortization

 

Depreciation, depletion, and amortization were $1.21 million during the nine months ended September 30, 2014, compared to $1.88 million during the nine months ended September 30, 2013, a decrease of $0.67 million, or 36%.  Decrease in depreciation, depletion, and amortization was from (i) a decrease in production amounts in 2014 from 2013, (ii) an decrease in the depletion base for the depletion calculation due to the conveyance of property, and (iii) a decrease in the depletion rate.  During the nine months ended September 30, 2014 and 2013, production amounts were 38,191 and 46,904 BOE, respectively, a decrease of 8,713 BOE, or 19%. The decrease in depletion was based on a lower depletion base. Depreciation, depletion, and amortization per BOE decreased to $31.72 from $40.08, respectively, for the nine months ended September 30, 2014 and 2013, a decrease of $8.36, or 21%.

 

Inducement expense

 

Inducement expenses were $6.66 million during the nine months ended September 30, 2014, compared to $0 during the nine months ended September 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 Company issued warrants to the converting Debenture holders to purchase one share of Common Stock, at an exercise price equal to $2.50 per share (the “Warrants”), for each share of Common Stock issued upon conversion of the Debentures. The Company used the Lattice model to value the warrants, utilizing a volatility of 65%, and a life of 3 years, which arrived at a fair value of $6.61 million for the Warrants.

 

 

Loss on conveyance of oil and gas properties

 

On September 2, 2014, the Company entered into an agreement to convey its interest in 31,725 evaluated and unevaluated net acres located in the Denver Julesburg Basin and the associated oil and natural gas production (the “Hexagon Collateral”) to its primary lender, Hexagon, LLC (“Hexagon”) in exchange for extinguishment of all outstanding debt and accrued interest obligations owed to Hexagon aggregating to $14,833,311. The conveyance assigned all assets and liabilities associated with the property, which includes PDP and PUD reserves, plugging and abandonment, and other assets and liabilities associated with the property. Pursuant to the agreement, the Company also issued to Hexagon $2.0 million in 6% Conditionally Redeemable Preferred Stock, which is recognized as temporary equity.

 

Under the full cost method, sales or abandonments of oil and natural gas properties, whether or not being amortized, are accounted for as adjustments of capitalized costs, with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil and natural gas attributable to the cost center. The conveyance to Hexagon represented greater than 25 percent of the Company’s proved reserves of oil and natural gas attributable to the full cost pool, as a result, there was a significant alteration in the relationship between capitalized costs and proved reserves of oil and natural gas attributable to the full cost pool. Total capitalized costs within the full cost pool are allocated on the basis of the relative fair values of the properties sold and those retained due to substantial economic differences between the properties sold and those retained.

 

The following table represents an allocation of the transaction:

 

Conveyance of oil and natural gas property to extinguish the obligation of debt and accrued interest payable		$	14,833,311
Add: disposition of asset retirement obligations			973,135
Net value of liabilities satisfied upon conveyance		$	15,806,446
Oil and natural gas properties (full cost method), at cost
Evaluated oil and natural gas properties		$	31,022,171
Wells in progress, transferred to evaluated oil and natural gas properties			510,895
Unevaluated oil and natural gas properties, transferred to evaluated oil and natural gas properties			6,026,297
Total evaluated oil and natural gas properties			37,559,363
Accumulated depletion			(21,058,451	)
Net oil and natural gas properties conveyed, at cost			16,500,912
Conditionally 6% Redeemable Preferred Stock			2,000,000
Loss on conveyance of evaluated oil and natural gas properties			(2,694,466	)
Net value of transaction		$	15,806,446

 

Interest Expense

 

For the nine months ended September 30, 2014 and 2013, the Company incurred interest expense of approximately $4.48 million and $4.72 million, respectively, of which approximately $2.30 million and $1.68 million is classified as non-cash interest expense, respectively. The details of the non-cash interest expense for the nine months ended September 30, 2014 are as follows: (i) amortization of the deferred financing costs of $0.28 million, (ii) accretion of the convertible debentures payable discount of $0.81 million, (iii) common stock issued for interest of $0.46 million, and (iv) accrued interest for term note loan fees of $0.25 million and (v) accrued interest to convertible debenture of $0.50 million (vi) amortization of forbearance fees of $0.25 million. Cash interest is comprised of term loan cash expenses of payment. In comparative, during the nine months ended September 30, 2013, non-cash interest consisted of: (i) amortization of the deferred financing costs of $0.53 million, and (ii) accretion of the convertible debentures payable discount of $1.74 million.

 

Change in derivative liability of convertible debentures

 

For the nine months ended September 30, 2014 and 2013, the Company incurred a change in the fair value of the derivative liability related to the convertible debentures of approximately $5.97 million and <$0.09> million respectively. During the nine months ended September 30, 2014, the Company’s conversion price of the convertible debentures was priced at $2.00 compared to $4.25 in 2013. During the nine months ended September 30, 2014, the Company reduced the conversion price from $4.25 to $2.00, as a result the Debenture converted $9.0 million of the outstanding Debentures. The conversion resulted in a reduction of the convertible debenture liability by $5.03 million and an increase in additional paid in capital.

 

Off-Balance Sheet Arrangements

 

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

 

 

Overview of Our Business, Strategy, and Plan of Operations

 

We have acquired and developed a producing base of oil and natural gas proved reserves, as well as a portfolio of exploration and other undeveloped assets with conventional and non-conventional reservoir opportunities, with an emphasis on those with multiple producing horizons, in particular the Muddy “J” conventional reservoirs and the Niobrara shale and Codell resource plays. We believe these assets offer the possibility of repeatable year-over-year success and significant and cost-effective production and reserve growth. Our acquisition, development and exploration pursuits are principally directed at oil and natural gas properties in North America. Since early 2010, we have acquired and/or developed 25 producing wells. As of September 30, 2014 we owned interests in approximately 8 economically producing wells and 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.   We are primarily focused on acquiring companies and production throughout North America and developing our North and South Wattenberg Field, assets which include attractive unconventional reservoir drilling opportunities in mature development areas that low risk Niobrara and Codell formation productive potential. 

 

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

 

Acquiring additional assets and companies throughout North America. We are targeting acquisitions in North America which meet certain current and future production thresholds to increase shareholder value. We anticipate the acquisitions will be funded by Heartland Bank $50.0 million facility and also utilizing either a preferred stock or a common stock offering.

 

Pursuing the initial development of our Greater Wattenberg Field unconventional assets. We currently have two key unconventional reservoir properties located in the Greater Wattenberg field.  We participated in the drilling of one non-operated horizontal well in our North Wattenberg asset during the fourth quarter of 2013, which was completed in the first quarter of 2014 and is now producing. We also plan to operate the drilling of several horizontal wells on our South Wattenberg property during the third quarter of 2015 in which we have a 50% working interest and a 25% working interest for a net of two wells.  Drilling activities on both properties will target the prolific and well established Niobrara and Codell formations.  Subject to the securing of additional capital, we expect to participate in up to 18 wells in these two assets, with an expected investment of up to $26.0 million. As of February 23, 2015, the Company has participated in one horizontal well that is currently on-line.

 

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

 

Engaging in certain exploration activities, including geologic and geophysics projects, to define additional prospects within our inventory of DJ Basin properties that may have significant development upside.   Subject to the securing of additional capital, we anticipate an expenditure of $5.0 million in second quarter 2015 to acquire seismic data on at least three key DJ Basin target areas to identify both conventional and unconventional drilling opportunities.

 

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

 

 

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

 

Currently, our inventory of developed and undeveloped acreage includes approximately 11,000 net acres that are held by production, approximately, 61,000, 4,000, 5,000 and 2,000 net acres that expire in the years 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. We will use our Credit Agreement with Heartland bank to acquire additional bolt-on properties, acquire other properties throughout North America, or drill wells on the core properties to hold the property by production.

 

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

 

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

 

Marketing and Pricing

 

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

 

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

 

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

 

 

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

 

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

 

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

 

Critical Accounting Policies and Estimates

 

The preparation of our 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

 

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 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 natural 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.

 

Item 3.  Quantitative and Qualitative Disclosures about Market Risk.

 

Not Applicable

 

Item 4.  Controls and Procedures.

 

Evaluation of Disclosure Controls and Procedures

 

The Company’s Chief Executive Officer and Chief Financial Officer have evaluated the effectiveness of the Company’s disclosure controls and procedures (as such term is defined in Rules 13a-15(e) under the Securities Exchange Act of 1934, as amended, the Exchange Act) as of September 30, 2014. Disclosure controls and procedures are controls and other procedures designed to ensure that information required to be disclosed by the Company in its reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms and include, without limitation, controls and procedures designed to ensure that information that the Company is required to disclose in such reports is accumulated and communicated to management, including our Chief Executive Officer and our Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosures. Based upon that evaluation, our Chief Executive Officer and our Chief Financial Officer concluded that, as of September 30, 2014, the Company’s disclosure controls and procedures were not effective, due to the material weaknesses in internal controls over financial reporting described below.

 

Internal Controls over Financial Reporting

 

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

 

Based on the evaluation and the identification of the material weakness in internal control over financial reporting described below, our Chief Executive Officer and our Chief Financial Officer have concluded that, as of September 30, 2014, the Company’s disclosure controls and procedures, which we previously reported as being effective, were actually  not effective.

 

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

 

 

Restatement of Previously Issued Financial Statements

 

As discussed above in the Note 3-Summary of Significant Accounting Policies-Basis of Presentation and Restatement, in February 2015, the Company discovered an error in the valuation of the conversion derivative liability of the Company’s Debentures for the Relevant Periods. Specifically, the calculation of the conversion liability included in the Company’s financial statements for the Relevant Periods only included the value of the price protection (anti-dilution) feature, when it should have included both the conversion option and the price protection embedded in the Debentures. The changes in the value of the derivative resulted in changes to the Company’s financial statements, which warranted restatement of the Company’s Quarterly Reports on Form 10-Q for the fiscal quarters ended September 30, 2013, March 31, 2014 and June 30, 2014.

As a result of the restatement described in this quarterly report, the Company’s Chief Executive Officer and Chief Financial Officer, with the assistance of other members of management and expert internal control consultants, re-evaluated the effectiveness of the Company’s internal controls over financial reporting as of September 30, 2014 in accordance with the assessment and testing procedures described above. Based on this re-evaluation, and because the impact of the errors on the Company’s quarterly financial statements for the fiscal quarters ended September 30, 2013, March 31, 2014 and June 30, 2014, described in Note 3-Summary of Significant Accounting Policies-Basis of Presentation and Restatement, was sufficiently material to warrant restatement of the Company’s Quarterly Reports on Form 10-Q for those periods, we have determined that the following additional material weakness in internal controls over financial reporting existed as of September 30, 2014:

 

●

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

 

Because of the material weaknesses described above, management has concluded that we did not maintain effective internal control over financial reporting as of September 30, 2014, based on the Internal Control—Integrated Framework issued by COSO (1992).

  

Remediation Efforts

 

We plan to make necessary changes and improvements to the overall design of our control environment to address the material weaknesses in internal control over financial reporting described above. In particular, we expect to hire additional staff to assist with journal entry processing and complex accounting issues such as convertible debentures. Additionally, we will perform an analysis of all automated and manual procedures to strengthen the effectiveness of our segregation of duties.

 

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

 

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

 

Changes in Internal Control over Financial Reporting

 

Other than those described above, management has determined that there were no changes in the Company’s internal controls over financial reporting during the fiscal quarter ended September 30, 2014 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting. 

 

PART II - OTHER INFORMATION

 

Item 1. Legal Proceedings.

 

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

 

 

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

In re Roger A. Parker: Tracinda Corp. v. Recovery Energy, Inc. and Roger A. Parker, United States Bankruptcy Court for the District of Colorado, Case No. 13-10897-EEB. On June 10, 2013, Tracinda Corp. (“Tracinda”) filed a complaint (Adversary No. 13-01301 EEB) against the Company and Roger Parker in connection with the personal bankruptcy proceedings of Roger Parker, alleging that the Company improperly failed to remit to Tracinda certain property in connection with a writs of garnishment issued by the Denver District Court (discussed above). The Company filed an answer to this complaint on July 10, 2013. A trial date has not been set and, by Order dated February 2, 2015, the Bankruptcy Court ordered that the Adversary Proceeding be held in abeyance pending final resolution of the state-court action (2011CV561). The Company is unable to predict the timing and outcome of this matter.

 

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

 

Item 1A. Risk Factors.

 

Not applicable.

 

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 nine 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 shares pari passu with the Series A Preferred.

 

Restrictions under Credit Agreement

 

As discussed above, on January 8, 2015 the Company entered into the Credit Agreement with Heartland Bank. Pursuant to the Credit Agreement, the Company is subject to certain customary working capital restrictions and limitations upon the payment of dividends. For example, the Company is prohibited from taking any of the following actions without the prior written consent of Heartland: incurring any debt, other than certain permitted debt as specified in the Credit Agreement; declaring or paying any distributions, including dividends, other than certain permitted distributions specified in the Credit Agreement; making any acquisitions of the stock or equity interests of another person, other than certain permitted equity acquisitions as specified in the Credit Agreement; or making any direct or indirect purchase or other acquisition of stock or other securities of any other person or any other item which would be classified as an “investment” on a balance sheet of such other person, other than certain permitted investments as specified in the Credit Agreement. The foregoing description does not purport to be complete and is qualified in its entirety by reference to the full text of the Credit Agreement, a copy of which is filed herewith as [Exhibit 10.13].

 

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.

 

In December 2014, the Company established a Nominating and Corporate Governance Committee (the “Committee”). Pursuant to the Charter of the Committee (the “Charter”), the Committee is responsible for considering any director candidate recommended by the Company’s stockholders. Stockholders who wish to recommend individuals for consideration by the Committee to become nominees for election to our Board may do so by delivering a written recommendation to the Nominating and Corporate Governance Committee at the following address: 216 16th Street, Suite #1350, Denver CO 80202 at least 120 days prior to the anniversary date of the mailing of our proxy statement for the last annual meeting of stockholders.

 

On February 19, 2015, the Company entered into an Employment Agreement with Eric Ulwelling, its Chief Financial Officer. The Employment Agreement provides for a base salary of $175,000, a discretionary bonus equal to up to 50% of base salary, and 400,000 stock options with an exercise price equal to the greater of fair market value of the Company’s common stock on the date of execution of the Employment Agreement or $2.50 per share. One quarter of the stock options vested immediately upon grant, and the other three quarters will vest in three annual installments on the anniversary of the execution of the Employment Agreement. The Employment Agreement provides for severance and accelerated vesting of any outstanding equity award upon termination of Mr. Ulwelling’s employment by the Company without cause or by Mr. Ulwelling for good reason or in connection with a change in control, as each is defined in the Employment Agreement.

The foregoing description of the Employment Agreement is not complete and is qualified in its entirety by reference to the text of the full Employment Agreement, which is attached as Exhibit 10.14 hereto and is incorporated herein by reference.

Item 6. Exhibits.

 

Exhibit Number		Exhibit Description
4.1		Form of Bristol Capital Warrant (incorporated herein by reference to Exhibit 4.3 from our quarterly report on Form 10-Q filed on November 26, 2014).
4.2		Certificate of Designation of 6% Redeemable Preferred Stock, dated August 29, 2014 (incorporated herein by reference to Exhibit 3.3 from our quarterly report on Form 10-Q filed on November 26, 2014).
4.3		Form of Heartland Bank Warrant.
10.1		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).
10.2		Separation Agreement with Robert A. Bell dated August 1, 2014 (incorporated herein by reference to Exhibit 10.9 from our quarterly report on Form 10-Q filed on November 26, 2014).
10.3		Consulting Agreement with Bristol Capital dated September 2, 2014 (incorporated herein by reference to Exhibit 10.11 from our quarterly report on Form 10-Q filed on November 26, 2014).
10.4		Settlement Agreement with Hexagon dated September 2, 2014 (incorporated herein by reference to Exhibit 10.10 from our quarterly report on Form 10-Q filed on November 26, 2014).
10.5		Option Award Agreement between the Company and Nuno Brandolini, dated as of October 1, 2014 (fully-vested).
10.6		Option Award Agreement between the Company and Nuno Brandolini, dated as of October 1, 2014 (subject to vesting).
10.7		Amendment to Abraham Mirman Employment Agreement, dated as of October 1, 2014.
10.8		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).
10.9		Lilis Energy, Inc. Director agreement with G. Tyler Runnels (incorporated herein by reference to Exhibit 10.1 from our current report filed on Form 8-K filed on December 2, 2014).
10.10		Separation Agreement with Bruce B. White, dated as of December 11, 2014.
10.11		Separation Agreement with Timothy N. Poster, dated as of December 11, 2014.
10.12		Credit Agreement, dated as of January 8, 2015, among Lilis Energy, Inc., Heartland Bank, as administrative agent, and the other lender parties thereto (incorporated herein by reference to Exhibit 10.1 from our current report filed on Form 8-K filed on January 13, 2015).
10.12(a)		Security Agreement, dated as of January 8, 2015, by and between Lilis Energy, Inc. and Heartland Bank, as collateral agent.
10.12(b)		Form of Promissory Note from Lilis Energy, Inc. as Borrower to Heartland Bank as Payee, dated as of January 8, 2015.
10.12(c)		Subordination Agreement, dated as of January 8, 2015.
10.12(d)		Form of Mortgage from Lilis Energy, Inc. as Mortgagor to Heartland Bank as Mortgagee (Colorado Oil and Gas Properties).
10.12(e)		Form of Mortgage from Lilis Energy, Inc. as Mortgagor to Heartland Bank as Mortgagee (Nebraska Oil and Gas Properties).
10.12(f)		Form of Mortgage from Lilis Energy, Inc. as Mortgagor to Heartland Bank as Mortgagee (Wyoming Oil and Gas Properties).
10.13		Letter Agreement with holders of the Company’s 8% Senior Secured Convertible Debentures dated as
10.14		Employment Agreement with Eric Ulwelling.
10.15		Market Development Termination letter (dated August 1, 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

 

 

SIGNATURES

 

Pursuant to the requirements of the Securities 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		February 25, 2015
Abraham Mirman		(Principal Executive Officer)
/s/ Eric Ulwelling		Chief Financial Officer and Chief Accounting Officer		February 25, 2015
Eric Ulwelling		(Principal Financial Officer)

 

 

EXHIBIT INDEX

 

 

Exhibit Number		Exhibit Description
4.1		Form of Bristol Capital Warrant (incorporated herein by reference to Exhibit 4.3 from our quarterly report on Form 10-Q filed on November 26, 2014).
4.2		Certificate of Designation of 6% Redeemable Preferred Stock, dated August 29, 2014 (incorporated herein by reference to Exhibit 3.3 from our quarterly report on Form 10-Q filed on November 26, 2014).
4.3		Form of Heartland Bank Warrant.
10.1		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).
10.2		Separation Agreement with Robert A. Bell dated August 1, 2014 (incorporated herein by reference to Exhibit 10.9 from our quarterly report on Form 10-Q filed on November 26, 2014).
10.3		Consulting Agreement with Bristol Capital dated September 2, 2014 (incorporated herein by reference to Exhibit 10.11 from our quarterly report on Form 10-Q filed on November 26, 2014).
10.4		Settlement Agreement with Hexagon dated September 2, 2014 (incorporated herein by reference to Exhibit 10.10 from our quarterly report on Form 10-Q filed on November 26, 2014).
10.5		Option Award Agreement between the Company and Nuno Brandolini, dated as of October 1, 2014 (fully-vested).
10.6		Option Award Agreement between the Company and Nuno Brandolini, dated as of October 1, 2014 (subject to vesting).
10.7		Amendment to Abraham Mirman Employment Agreement, dated as of October 1, 2014.
10.8		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).
10.9		Lilis Energy, Inc. Director agreement with G. Tyler Runnels (incorporated herein by reference to Exhibit 10.1 from our current report filed on Form 8-K filed on December 2, 2014).
10.10		Separation Agreement with Bruce B. White, dated as of December 11, 2014.
10.11		Separation Agreement with Timothy N. Poster, dated as of December 11, 2014.
10.12		Credit Agreement, dated as of January 8, 2015, among Lilis Energy, Inc., Heartland Bank, as administrative agent, and the other lender parties thereto (incorporated herein by reference to Exhibit 10.1 from our current report filed on Form 8-K filed on January 13, 2015).
10.12(a)		Security Agreement, dated as of January 8, 2015, by and between Lilis Energy, Inc. and Heartland Bank, as collateral agent.
10.12(b)		Form of Promissory Note from Lilis Energy, Inc. as Borrower to Heartland Bank as Payee, dated as of January 8, 2015.
10.12(c)		Subordination Agreement, dated as of January 8, 2015.
10.12(d)		Form of Mortgage from Lilis Energy, Inc. as Mortgagor to Heartland Bank as Mortgagee (Colorado Oil and Gas Properties).
10.12(e)		Form of Mortgage from Lilis Energy, Inc. as Mortgagor to Heartland Bank as Mortgagee (Nebraska Oil and Gas Properties).
10.12(f)		Form of Mortgage from Lilis Energy, Inc. as Mortgagor to Heartland Bank as Mortgagee (Wyoming Oil and Gas Properties).
10.13		Letter Agreement with holders of the Company’s 8% Senior Secured Convertible Debentures dated as
10.14		Employment Agreement with Eric Ulwelling.
10.15		Market Development Termination letter (dated August 1, 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

 

 

 

 

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