News Column

LILIS ENERGY, INC. - 10-Q - MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

June 17, 2014

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



General

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



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

Financial Condition and Liquidity

As of March 31, 2014, the Company had $18.57 million outstanding under its term loans with Hexagon, LLC ("Hexagon") and $6.73 million outstanding under its 8% Senior Secured Convertible Debentures (the "Debentures"). Both the term loans and the Debentures were to mature on May 16, 2014. In the first three months of 2014, the Company consummated the following transactions: (i) on January 22, 2014, the Company closed a $7.50 million private placement of units consisting of one share of Common Stock and one three-year warrant to purchase one share of Common Stock for aggregate gross proceeds of $5,918,250, plus an additional $1,425,000 in proceeds committed by certain officers and directors of the Company, which we expect to be funded upon our receipt of the required shareholder approval; (ii) on January 31, 2014, the Company entered into a Debenture Conversion Agreement, under which $9.0 million in Debentures was immediately converted to Common Stock at a price of $2.00 per common share. In addition, (i) on May 19, 2014, the Company received extensions from both Hexagon and the remaining Debenture holders of the maturity dates under the Company's term loans and Debentures, respectively, from May 16, 2014 to August 15, 2014; (ii) on May 30, 2014, the Company and Hexagon entered into an agreement providing for the settlement of all amounts outstanding under the term loans, in exchange for two cash payments of $5.0 million each to be made by the Company to Hexagon on May 30,2014 and June 30, 2014; as well as the issuance to Hexagon of a two-year $6.0 million unsecured 8% note and 943,208 shares of unregistered Common Stock; (iii) on May 30, 2014 the Company consummated a private placement to accredited investors of 8% Convertible Preferred Stock and three-year warrants to purchase Common Stock equal to 50% of the number of shares issuable upon full conversion of the Preferred Stock for gross proceeds of $7.50 million; (iv) on June 6, 2014, the holders of the remaining Debentures agreed to further extend the maturity date under the Debentures from August 15, 2014 to January 15, 2015; and (v) on June 6, 2014, TR Winston executed a commitment to purchase or effect the purchase by third parties of an additional $15 million in Preferred Stock, which transaction is to be consummated within ninety (90) days. The consummation of these transactions has been partially reflected in the Company's balance sheet via the classification of certain portions of the Hexagon term loans and Debentures as long-term debt. 18 -------------------------------------------------------------------------------- The closing of these transactions provided the Company with working capital for general corporate purposes, as well as a portion of the initial capital requirements to initiate further development activities on two of its Wattenberg prospects. However, the Company will require additional capital to satisfy its obligations to Hexagon under the settlement agreement, to fund its current drilling commitments and capital budget plans, to help fund its ongoing overhead, and to provide additional capital to generally improve its working capital position. We anticipate that such additional funding will be provided by a combination of capital raising activities, including the selling of additional debt and/or equity securities, the selling of certain assets and by the development of certain of the Company's undeveloped properties via arrangements with joint venture partners. If we are not successful in obtaining sufficient cash sources to fund the aforementioned capital requirements, we may be required to curtail our expenditures, restructure our operations, sell assets on terms which may not be deemed favorable and/or curtail other aspects of our operations, including deferring portions of capital budget. There is no assurance that any such funding will be available to the Company.



Cash Flows

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



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

Three months ended March 31, 2014 2013 Cash provided by (used in): Operating activities $ (1,952 )$ (904 ) Investing activities (369 ) 588 Financing activities 5,012 (177 ) Net change in cash $ 2,691$ (493 ) During the three months ended March 31, 2014, net used in operating activities was $1.95 million, compared to cash used in operating activities of $0.90 million during the three months ended March 31, 2014, an increase of cash used in operating activities of $1.05 million. The primary changes in operating cash during the three months ended March 31, 2014 were $10.05 million of net loss, $0.43 million increase in cash for other assets, increase in cash for accounts payable and other accrued expenses of $4.74 million, and an increase of cash of $0.09 million for accounts receivable, and offset by a decrease of $0.01 million for restricted cash. The cash flows from operating activities were adjusted for non-cash charges of $0.39 million of depreciation, depletion, amortization and accretion expenses, $ 0.66 million of debt discount accretion, $0.19 million of amortization of deferred financing costs, common stock issued for financing costs for both the private placement of issuance of common stock and convertible debentures of $0.69 million, common stock issued for interest of $0.15 million, $6.61 million issuance of a warrant to purchase common stock recorded as a debt inducement for the conversion of convertible debentures, $0.44 million for issuance of stock for services and compensation, and offset by a decrease in cash for non-cash change in fair value of convertible debentures conversion option of $1.15 million. Operating cash was increased by $0.09 million of cash provided by a decrease in accounts receivable, cash provided by other assets of $0.43 million, which was offset by cash used in restricted cash and accounts payable and other accrued expenses of $0.01 million and $0.46 million, respectively. During the three month ended March 31, 2014, net cash used in investing activities was $0.37 million, compared to net cash provided by investing activity of $0.59 million during the three months ended March 31, 2013, a decrease of cash used in investing activities of $0.22 million. The primary changes in investing cash during the three months ended March 31, 2014 were a decrease in cash of $0.32 million of drilling expenditures, $0.05 million in expenditures related to additions to oil and gas properties, and $0.01 million in expenditures related to office equipment. During the three months ended March 31, 2014, net cash provided by financing activities was $5.01 million, compared to net cash used in financing activities of $0.18 million during the three months ended March 31, 2013, an increase of $5.19 million. The changes in financing cash during the three months ended March 31, 2014 were primarily due to proceeds from the January 2014 Private Placement of $7.5 million which was offset by $1.43 million from participating management and directors which are subject to receipt of shareholder approval as required by NASDAQ's continued listing requirements. The $7.5 million was further reduced by fees associated with financing paid which resulted in proceeds of $5.33 million from the January 2014 Private Placement. The proceeds from the January 2014 Private Placement were partially offset by net repayments of debt of $0.31 million. Capital Resources The Company will require additional capital to fund its current capital obligations, capital budget plans, to help fund its ongoing G&A and to provide additional capital to generally improve its working capital position. We anticipate that such additional funding will be provided by a combination of capital raising activities, including the selling of additional debt and/or equity securities, the selling of certain un-evaluated and evaluated properties and by the development of certain undeveloped properties via arrangements with joint venture partners. If we are not successful in obtaining sufficient cash resources to fund the aforementioned capital requirements, we may be required to curtail our expenditures, restructure our operations, sell assets on terms which may not be deemed favorable and/or curtail other aspects of our operations, decrease our working interest in planned drilling areas, including deferring certain capital expenditures in key development areas. There is no assurance that any such funding will be available to the Company. 19 -------------------------------------------------------------------------------- During the year ended December 31, 2014, the Company was provided three JV authorizations for expenditures cash calls totaling $5.05 million by the operator of three horizontal wells in the North Wattenberg field. Per the terms of the JOA, if the Company does not generate enough capital from equity or debt raises, and then the Company may be placed in non-pay status with the operator per a Notice of Default. Should this occur, after thirty days without cure, the operator may forward the Company a Notice of Non-Consent and will be imposed up to a 300% penalty to buy-back working interest in the new drill wells.



Results of Operations

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

The following table compares operating data for the three months ended March 31, 2014 to March 31, 2013: Three months ended March 31, 2014 2013 Revenues: Oil sales $ 700,087$ 1,127,333 Gas sales 87,667 106,397 Operating fees 34,727 48,503 Realized gain on commodity price derivatives 11,143 19,890 Total revenues 833,624 1,302,123 Costs and expenses: Production costs 416,323 303,847 Production taxes 93,680 115,994 General and administrative 2,958,416 984,259 Depreciation, depletion and amortization 388,635 689,654 Total costs and expenses 3,857,054 2,093,754 Loss from operations (3,023,429 ) (791,631 ) Other Income (expenses): Other income 53 251 Inducement expense (6,661,275 ) -



Convertible notes conversion derivative gain (loss) 1,150,000

(20,000 ) Interest expense (1,516,331 ) (1,636,159 ) Total other expenses (7,027,553 ) (1,655,908 ) Net loss $ (10,050,982 )$ (2,447,539 ) Total revenues Total revenues were $0.83 million for the three months ended March 31, 2014, compared to $1.30 million for the three months ended March 31, 2013, a decrease of $0.47 million, or 36%. The decrease in revenues was due primarily to a decrease in production volumes. During the three months ended March 2014 and 2013, production amounts were 10,288 and 18,215 BOE, respectively, a decrease of 7,927 BOE, or 44%. Declines in production are primarily attributable to natural production declines related to mature producing properties, but were also affected by the temporary reduction in production from five of the Company's properties that experienced production difficulties during the quarter. Producing wells that went off-line were idle for longer periods of time than expected due to the lack of availability of workover/production rigs in the area. The effect of this production decrease was partially offset by an increase in the overall average price per BOE to $76.58 in 2014 from $67.73 in 2013, an increase of $8.85 or 13%. 20

-------------------------------------------------------------------------------- The following table shows a comparison of production volumes and average prices: For the Three Months Ended March 31, 2014 2013 Product Oil (Bbl.) 8,455 13,458 Oil (Bbls)-average price (1) $ 82.80 $ 83.77 Natural Gas (MCF)-volume 10,997 24,215 Natural Gas (MCF)-average price (2) $ 7.97 $ 4.39 Barrels of oil equivalent (BOE) 10,288 18,215 Average daily net production (BOE) 114 202 Average Price per BOE (1) $ 76.58 $ 67.73



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

Oil and gas production costs, production taxes, depreciation, depletion, and amortization Average Price per BOE(1) $ 76.58 $ 67.73 Production costs per BOE 40.47 16.68 Production taxes per BOE 9.11 6.37 Depreciation, depletion, and amortization per BOE 37.78 37.86 Total operating costs per BOE $ 87.36 $ 60.91 Gross margin per BOE $ (10.78 ) $ 6.82 Gross margin percentage -14 % 10.07 %



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

Commodity Price Derivative Activities

Changes in the market price of oil can significantly affect our profitability and cash flow. In the past we have entered into various commodity derivative instruments to mitigate the risk associated with downward fluctuations in oil prices. These derivative instruments consisted exclusively of swaps. The duration and size of our various derivative instruments varies, and depends on our view of market conditions, available contract prices and our operating strategy. As of March 31, 2014, the Company did not maintain any active commodity swaps. The commodity swap ended in January 31, 2014 for 100 barrels of oil per day at a price of $99.25 per barrel. Commodity price derivative realized gains were $0.01 million for the three months ended March 31, 2014, compared to realize gains of $0.02 million during the three months ended March 31, 2013, a decrease in realized gains/losses of $0.01 million or 50%. Production costs Production costs were $0.42 million during the three months ended March 31, 2014, compared to $0.30 million for the three months ended March 31, 2013, an increase of $0.12 million, or 40%. Increase in production costs in 2014 was from an increase of the number of required well work, property improvements, and maintenance of productive wells. Production costs per BOE increased to $40.47 for the three months ended March 31, 2014 from $16.68 in 2013, an increase of $23.79 per BOE, or 143%, primarily as a result of reduced volumes of BOE in 2013 and high well work frequency. During the three months ended March 31, 2014, work-over rigs had limited availability due to high Industry activity within the operating area of the Company. As a result, idled wells for routine well maintenance or other repairs were off-line longer than anticipated, which substantially decreased our production.



Production taxes

Production taxes were $0.09 million for the three months ended March 31, 2014, compared to $0.12 million for the three months ended March 31, 2013, a decrease of $0.03 million, or 25%. Decrease in production taxes was from a decrease in production and product mix per state. Currently, ad valorem, severance and conservation taxes range from 1% to 13% based on the state and county which production is derived. Production taxes per BOE increased to $9.11 during the three months ended March 31, 2014 from $6.37 in 2013, an increase of $2.74 or 43%. During the three months ended March 31, 2014, work-over rigs were in high demand within the operating area of the Company with a small supply of work-over rigs. As a result, our wells which went down for normal well maintenance or other repairs did not operate for an extended period of time which substantially decreased our BOE. 21

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General and administrative

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



Depreciation, depletion, and amortization

Depreciation, depletion, and amortization were $0.39 million during the three months ended March 31, 2014, compared to $0.70 million during the three months ended March 31, 2013, a decrease of $0.31 million, or 44%. Decrease in depreciation, depletion, and amortization was from (i) a decrease in production amounts in 2014 from 2013, (ii) an increase in the depletion base for the depletion calculation, and (iii) a decrease in the depletion rate. Production amounts decreased to 10,288 from 18,215 for the three months ended March 31, 2014 and 2013, respectively, a decrease of 7,927, or 44%. The decrease in depletion was based on a lower depletion base. Depreciation, depletion, and amortization per BOE decreased to $37.78 from $37.86, respectively, for the three months ended March 31, 2014 and 2013, a decrease of $0.08, or 1%. During the three months ended March 31, 2014, work-over rigs were in high demand within the operating area of the Company with a small supply of work-over rigs. As a result, our wells which went down for normal well maintenance or other repairs did not operate for an extended period of time which substantially decreased our BOE. Inducement expense Inducement expenses were $6.66million during the three months ended March 31, 2014, compared to $0 during the three months ended March 31, 2013. In January 2014, the Company entered into the Conversion Agreement between the Company and all of the holders of the Debentures. Under the terms of the Conversion Agreement, $9.0 million of the approximately $15.6 million in Debentures then outstanding converted to common stock at a price of $2.00 per common share. As inducement for the Company issued warrants to the converting Debenture holders to purchase one share of Common Stock, at an exercise price equal to $2.50 per share (the "Warrants"), for each share of Common Stock issued upon conversion of the Debentures. The Company used Lattice model to value the warrants, utilizing a volatility of 65%, and a life of 3 years, which arrived at a fair value of $6.61 million for the Warrants.



Interest Expense

For the three months ended March 31, 2014 and 2013, the Company incurred interest expense of approximately $1.52 million and $1.64 million, respectively, of which approximately $1.05 million and $1.00 million, respectively, were non-cash interest expense and amortization of the deferred financing costs, accretion of the convertible debentures payable discount, and convertible debentures interest paid in common stock. The decrease in interest expense was primarily attributable to a decrease in the interest rate on the Company's term loans from 15% to 10% that occurred effective April 1, 2013, but partially offset by an increase in the Company's convertible debentures.



Off-Balance Sheet Arrangements

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

Capital Budget

We anticipate a working capital budget of up to $28.0 million for the remainder of 2014. The budget is allocated toward the exploitation of two unconventional reservoirs located in the Wattenberg field within the DJ Basin that will apply horizontal drilling in the Niobrara shale and Codell formations. This entire capital budget is subject to the securing of adequate capital through drilling, equity, and debt instruments. Although we secured approximately $5.0 million, from the January Private Placement, $15.0 million, commitment to purchase or effect the purchase with Preferred Stock from TR. Winston, and an additional $7.50 million, from the May Private Placement, some of the proceeds from these transactions were applied to the payment and servicing of our term debt. The execution of, and results from, our capital budget are contingent on various factors, including, but not limited to, the sourcing of capital, market conditions, oilfield services and equipment availability, commodity prices and drilling/ production results. Results from the wells identified in the capital budget may lead to additional adjustments to the capital budget. Other factors that could impact our level of activity and capital expenditure budget include, but are not limited to, a reduction or increase in service and material costs, the formation of joint ventures with other exploration and production companies, the divestiture of non-strategic assets,. We do not anticipate any significant expansion of our current DJ Basin acreage position in the near term; however, we are targeting attractive Wattenberg acquisitions. 22 --------------------------------------------------------------------------------



Overview of Our Business, Strategy, and Plan of Operations

We have acquired and developed a producing base of oil and natural gas proved reserves, as well as a portfolio of exploration and other undeveloped assets with conventional and non-conventional reservoir opportunities, with an emphasis on those with multiple producing horizons, in particular the Muddy "J" conventional reservoirs and the Niobrara shale and Codell resource plays. We believe these assets offer the possibility of repeatable year-over-year success and significant and cost-effective production and reserve growth. Our acquisition, development and exploration pursuits are principally directed at oil and natural gas properties in the DJ Basin in Colorado, Nebraska, and Wyoming. Since early 2010, we have acquired and/or developed 25 producing wells. As of December 31, 2013 we owned interests in approximately 123,000 gross (107,000 net) leasehold acres, of which 111,000 gross (88,000 net) acres are classified as undeveloped acreage and all of which are located in Colorado, Wyoming and Nebraska within the DJ Basin. We are primarily focused on our North and South Wattenberg Field, assets which include attractive unconventional reservoir drilling opportunities in mature development areas that offer low risk Niobrara and Codell formation productive potential. We also believe that our conventional reservoir development potential in our Silo-East, Hanson and Wilke/Lukassen well areas will yield competitive results. We expect to pursue an aggressive multi-well program. Our intermediate goal is to create significant value via the investment of up to $50.0 million in our inventory of low and controlled-risk conventional and unconventional properties, while maintaining a low cost structure. To achieve this, our business strategy includes the following elements: Pursuing the initial development of our Greater Wattenberg Field unconventional assets. We currently have two key unconventional reservoir properties located in the Greater Wattenberg field. We participated in the drilling of one non-operated horizontal well in our North Wattenberg asset during the fourth quarter of 2013, which was completed in the first quarter of 2014 and is now on post-frac production. We are also participating in three additional non-operated horizontal wells on this property that were drilled in the first quarter, 2014. We also plan to operate the drilling of two horizontal wells on our South Wattenberg property during the third quarter of 2014 in which we have a 50% working interest and a 25% working interest in two wells. Drilling activities on both properties will target the prolific and well established Niobrara and Codell formations. Subject to the securing of additional capital, we expect to participate in up to 18 wells in these two assets, with an expected investment that exceeds up to $26.0 million. As of June 1, 2014, the Company has participated in the following in the Watttenberg Field: 1) one horizontal well that is currently on-line, and 2) 3 horizontal wells that are drilled and commencing completion operations in 2nd Quarter 2014. Extending the development of certain conventional prospects within our inventory of other DJ Basin properties. Subject to the securing of additional capital, we anticipate the expenditure of up to an additional $25.0 million in drilling and development costs on three of our DJ Basin assets where initial exploitation has yielded positive results. Additional drilling activities will be conducted on each property in an effort to fully assess each property and define field productivity and economic limits. Engaging in certain exploration activities, including geologic and geophysics projects, to define additional prospects within our inventory of DJ Basin properties that may have significant development upside. Subject to the securing of additional capital, we anticipate an expenditure of $2.0 to $5.0 million in 2014 to acquire seismic data on at least three key DJ Basin target areas to identify both conventional and unconventional drilling opportunities. Controlling Costs. We seek to maximize our returns on capital employed by minimizing our production costs via prudent engineering and field management, and by closely monitoring general and administrative expenses. We also minimize initial capital expenditures on geological and geophysical overhead, seismic data, hardware and software by partnering with cost efficient operators that have already invested capital in such. We also outsource some of our technical functions in order to help reduce general and administrative and capital requirements. From time to time, we use commodity price hedging instruments to reduce our exposure to oil and natural gas price fluctuations and to help ensure that we have adequate cash flow to fund our debt service costs and capital programs. From time to time, we will enter into futures contracts, collars and basis swap agreements, as well as fixed price physical delivery contracts. We intend to use hedging primarily to manage price risks and returns on certain acquisitions and drilling programs. Our policy is to consider hedging an appropriate portion of our production at commodity prices we deem attractive. In the future we may also be required by our lenders to hedge a portion of production as part of any financing. Currently, our inventory of developed and undeveloped acreage includes approximately 12,000 net acres that are held by production, approximately 25,000 net acres, 60,000, 4,000, 4,000 and 2,000 net acres that expire in the years 2014, 2015, 2016, 2017, and thereafter, respectively. Approximately 82% of our inventory of undeveloped acreage provides for extension of lease terms from two to five years, at the option of the Company, via payment of varying, but typically nominal, extension amounts. However, due to our current liquidity issues, we may enter into one or more transactions to sell a significant number of leases, both developed and undeveloped, to enable us to pay down our outstanding debt or satisfy other financial obligations. The business of oil and natural gas property acquisition, exploration and development is highly capital intensive and the level of operations attainable by oil and gas company is directly linked to and limited by the amount of available capital. Therefore, a principal part of our plan of operations is to raise the additional capital required to finance the exploration and development of our current oil and natural gas prospects and the acquisition of additional properties to balance our existing organic cash flow. We will need to raise additional capital to fund our exploration and development budget. We will seek additional capital through the sale of our securities, through debt and project financing, joint venture agreements with industry partners, and through sale of assets. Our ability to obtain additional capital through new debt instruments, project financing and sale of assets may be subject to the repayment of our existing obligations. 23 -------------------------------------------------------------------------------- We intend to use the services of independent consultants and contractors to provide various professional services, including land, legal, environmental, technical, investor relations and tax services. We believe that by limiting our management and employee costs, we may be able to better control lifting costs and retain G&A flexibility. Marketing and Pricing We derive revenue principally from the sale of oil and natural gas. As a result, our revenues are determined, to a large degree, by prevailing prices for crude oil and natural gas. We sell our oil and natural gas on the open market at prevailing market prices or through forward delivery contracts. The market price for oil and natural gas is dictated by supply and demand, and we cannot accurately predict or control the price we may receive for our oil and natural gas. Our revenues, cash flows, profitability and future rate of growth will depend substantially upon prevailing prices for oil and natural gas. Prices may also affect the amount of cash flow available for capital expenditures and our ability to borrow money or raise additional capital. Lower prices may also adversely affect the value of our reserves and make it uneconomical for us to commence or continue production levels of oil and natural gas. Historically, the prices received for oil and natural gas have fluctuated widely. Among the factors that can cause these fluctuations are:



? changes in global supply and demand for oil and natural gas;

? the actions of the Organization of Petroleum Exporting Countries, or OPEC;

? the price and quantity of imports of foreign oil and natural gas; ? acts of war or terrorism; ? political conditions and events, including embargoes, affecting oil-producing activity; ? the level of global oil and natural gas exploration and production activity; ? the level of global oil and natural gas inventories; ? weather conditions; ? technological advances affecting energy consumption; and ? transportation options from trucking, rail, and pipeline ? the price and availability of alternative fuels.



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

? our production and/or sales of natural gas are less than expected;

? payments owed under derivative hedging contracts come due prior to receipt

of the hedged month's production revenue; or ? the counter party to the hedging contract defaults on its contract obligations. In addition, hedging arrangements may limit the benefit we would receive from increases in the prices for oil and natural gas. We cannot assure you that any hedging transactions we may enter into will adequately protect us from declines in the prices of oil and natural gas. On the other hand, where we choose not to engage in hedging transactions in the future, we may be more adversely affected by changes in oil and natural gas prices than our competitors who engage in hedging transactions.



Obligations and Commitments

We have the following contractual obligations and commitments as of March 31, 2014 (in thousands): Payments due by period Within 1 More than Contractual obligations Total Year 1-3 years 4-5 years 5 years Secured debt $ 18,566$ 10,483$ 8,083 $ - $ - Interest on secured debt 1,392 1,392 - - - Convertible debentures 6,728 6,728 - - - Interest on convertible debentures 403 403 - - - Operating leases & Other 44 44 - - -



Total contractual cash obligations $ 27,133$ 19,050$ 8,083 $

- $ -



Critical Accounting Policies and Estimates

The preparation of our consolidated financial statements in conformity with generally accepted accounting principles in the United States, or GAAP, requires our management to make assumptions and estimates that affect the reported amounts of assets, liabilities, revenues and expenses, as well as the disclosure of contingent assets and liabilities at the date of our financial statements and the reported amounts of revenues and expenses during the reporting period. The following is a summary of the significant accounting policies and related estimates that affect our financial disclosures. 24 -------------------------------------------------------------------------------- Critical accounting policies are defined as those significant accounting policies that are most critical to an understanding of a company's financial condition and results of operation. We consider an accounting estimate or judgment to be critical if (i) it requires assumptions to be made that were uncertain at the time the estimate was made, and (ii) changes in the estimate or different estimates that could have been selected could have a material impact on our results of operations or financial condition.



Use of Estimates

The financial statements included herein were prepared from our records in accordance with GAAP, and reflect all normal recurring adjustments which are, in the opinion of management, necessary to provide a fair statement of the results of operations and financial position for the interim periods. The preparation of the financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of oil and gas reserves, assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. We evaluate our estimates on an on-going basis and base our estimates on historical experience and on various other assumptions we believe to be reasonable under the circumstances. Although actual results may differ from these estimates under different assumptions or conditions, we believe that our estimates are reasonable. Our most significant financial estimates are associated with our estimated proved oil and gas reserves, assessments of impairment imbedded in the carrying value of undeveloped acreage and proven properties, as well as valuation of Common Stock used in various issuances of Common Stock, options and warrants, and estimated derivative liabilities.



Oil and Natural Gas Reserves

We follow the full cost method of accounting. All of our oil and gas properties are located within the United States, and therefore all costs related to the acquisition and development of oil and gas properties are capitalized into a single cost center referred to as a full cost pool. Depletion of exploration and development costs and depreciation of production equipment is computed using the units-of-production method based upon estimated proved oil and gas reserves. Under the full cost method of accounting, capitalized oil and gas property costs less accumulated depletion and net of deferred income taxes may not exceed an amount equal to the present value, discounted at 10%, of estimated future net revenues from proved oil and gas reserves less the future cash outflows associated with the asset retirement obligations that have been accrued on the balance sheet plus the cost, or estimated fair value if lower, of unproved properties. Should capitalized costs exceed this ceiling, impairment would be recognized. Under the SEC rules, we prepared our oil and gas reserve estimates as of December 31, 2013, using the average, first-day-of-the-month price during the 12-month period ending December 31, 2013. Estimating accumulations of gas and oil is complex and is not exact because of the numerous uncertainties inherent in the process. The process relies on interpretations of available geological, geophysical, engineering and production data. The extent, quality and reliability of this technical data can vary. The process also requires certain economic assumptions, some of which are mandated by the SEC, such as gas and oil prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The accuracy of a reserve estimate is a function of the quality and quantity of available data; the interpretation of that data; the accuracy of various mandated economic assumptions; and the judgment of the persons preparing the estimate. We believe estimated reserve quantities and the related estimates of future net cash flows are the most important estimates made by an exploration and production company such as ours because they affect the perceived value of our company, are used in comparative financial analysis ratios, and are used as the basis for the most significant accounting estimates in our financial statements, including the quarterly calculation of depletion, depreciation and impairment of our proved oil and natural gas properties. Proved oil and natural gas reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future periods from known reservoirs under existing economic and operating conditions. We determine anticipated future cash inflows and future production and development costs by applying benchmark prices and costs, including transportation, quality and basis differentials, in effect at the end of each quarter to the estimated quantities of oil and natural gas remaining to be produced as of the end of that quarter. We reduce expected cash flows to present value using a discount rate that depends upon the purpose for which the reserve estimates will be used. For example, the standardized measure calculation requires us to apply a 10% discount rate. Although reserve estimates are inherently imprecise, and estimates of new discoveries and undeveloped locations are more imprecise than those of established proved producing oil and natural gas properties, we make considerable effort to estimate our reserves, including through the use of independent reserves engineering consultants. We expect that quarterly reserve estimates will change in the future as additional information becomes available or as oil and natural gas prices and operating and capital costs change. We evaluate and estimate our oil and natural gas reserves as of December 31 and quarterly throughout the year. For purposes of depletion, depreciation, and impairment, we adjust reserve quantities at all quarterly periods for the estimated impact of acquisitions and dispositions. Changes in depletion, depreciation or impairment calculations caused by changes in reserve quantities or net cash flows are recorded in the period in which the reserves or net cash flow estimate changes.



Oil and Natural Gas Properties-Full Cost Method of Accounting

We use the full cost method of accounting whereby all costs related to the acquisition and development of oil and natural gas properties are capitalized into a single cost center referred to as a full cost pool. These costs include land acquisition costs, geological and geophysical expenses, carrying charges on non-producing properties, costs of drilling and overhead charges directly related to acquisition and exploration activities. 25 --------------------------------------------------------------------------------



Capitalized costs, together with the costs of production equipment, are depleted and amortized on the unit-of-production method based on the estimated gross proved reserves as determined by independent petroleum engineers. For this purpose, we convert our petroleum products and reserves to a common unit of measure.

Costs of acquiring and evaluating unproved properties are initially excluded from depletion calculations. This undeveloped acreage is assessed quarterly to ascertain whether impairment has occurred. When proved reserves are assigned or the property is considered to be impaired, the cost of the property or the amount of the impairment is added to the full cost pool and becomes subject to depletion calculations. Proceeds from the sale of oil and natural gas properties are applied against capitalized costs, with no gain or loss recognized, unless the sale would alter the rate of depletion by more than 25%. Royalties paid, net of any tax credits received, are netted against oil and natural gas sales. In applying the full cost method, we perform a ceiling test on properties that restricts the capitalized costs, less accumulated depletion, from exceeding an amount equal to the estimated undiscounted value of future net revenues from proved oil and natural gas reserves, as determined by independent petroleum engineers. The estimated future revenues are based on sales prices achievable under existing contracts and posted average reference prices in effect at the end of the applicable period, and current costs, and after deducting estimated future general and administrative expenses, production related expenses, financing costs, future site restoration costs and income taxes. Under the full cost method of accounting, capitalized oil and natural gas property costs, less accumulated depletion and net of deferred income taxes, may not exceed an amount equal to the present value, discounted at 10%, of estimated future net revenues from proved oil and natural gas reserves, plus the cost, or estimated fair value if lower, of unproved properties. Should capitalized costs exceed this ceiling, we would recognize impairment.



Revenue Recognition

The Company derives revenue primarily from the sale of produced natural gas and crude oil. The Company reports revenue as the gross amount received before taking into account production taxes and transportation costs, which are reported as separate expenses and are included in oil and gas production expense in the accompanying consolidated statements of operations. Revenue is recorded in the month the Company's production is delivered to the purchaser, but payment is generally received between 30 and 90 days after the date of production. No revenue is recognized unless it is determined that title to the product has transferred to the purchaser. At the end of each month, the Company estimates the amount of production delivered to the purchaser and the price the Company will receive. The Company uses its knowledge of its properties, its historical performance, existing contracts, NYMEX and local spot market prices, quality and transportation differentials, and other factors as the basis for these estimates.



Share Based Compensation

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



Derivative Instruments

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


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Source: Edgar Glimpses


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