Attached files

file filename
EX-32.1 - CERTIFICATION - LILIS ENERGY, INC.f10k2014ex32i_lilisenergy.htm
EX-99.1 - ESTIMATED RESERVES - LILIS ENERGY, INC.f10k2014ex99i_lilis.htm
EX-21.1 - SUBSIDIARIES OF THE REGISTRANT - LILIS ENERGY, INC.f10k2014ex21i_lilisenergy.htm
EX-10.85 - STOCK OPTION AWARD AGREEMENT - LILIS ENERGY, INC.f10k2014ex10lxxxv_lilis.htm
EX-31.1 - CERTIFICATION - LILIS ENERGY, INC.f10k2014ex31i_lilisenergy.htm
EX-10.87 - STOCK OPTION AWARD AGREEMENT - LILIS ENERGY, INC.f10k2014ex10lxxxvii_lilis.htm
EX-32.2 - CERTIFICATION - LILIS ENERGY, INC.f10k2014ex32ii_lilisenergy.htm
EX-23.2 - CONSENT OF HEIN & ASSOCIATES, LLP - LILIS ENERGY, INC.f10k2014ex23ii_lilisenergy.htm
EX-31.2 - CERTIFICATION - LILIS ENERGY, INC.f10k2014ex31ii_lilisenergy.htm
EXCEL - IDEA: XBRL DOCUMENT - LILIS ENERGY, INC.Financial_Report.xls
EX-10.81 - RECOVERY ENERGY, INC. 2012 EQUITY INCENTIVE PLAN STOCK OPTION AWARD AGREEMENT - LILIS ENERGY, INC.f10k2014ex10lxxxi_lilis.htm
EX-10.84 - EMPLOYMENT AGREEMENT - LILIS ENERGY, INC.f10k2014ex10lxxxiv_lilis.htm
EX-23.1 - CONSENT OF MARCUM LLP - LILIS ENERGY, INC.f10k2014ex23i_lilisenergy.htm
EX-10.83 - STOCK OPTION AWARD AGREEMENT - LILIS ENERGY, INC.f10k2014ex10lxxxiii_lilis.htm
EX-23.3 - CONSENT OF RE DAVIS - LILIS ENERGY, INC.f10k2014ex23iii_lilisenergy.htm

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

FORM 10-K

 

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

 

For the fiscal year ended December 31, 2014

 

or

 

   TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

 

For the transition period from __________to_________

 

Commission file number: 001-35330

 

Lilis Energy, Inc.

(Name of registrant as specified in its charter)

 

NEVADA   74-3231613
(State or other jurisdiction of
incorporation or organization)
 

(I.R.S. Employer

Identification No.)

 

216 16th Street, Suite 1350, Denver, CO 80202

(Address of principal executive offices, including zip code)

 

Registrant’s telephone number including area code:  (303) 893-9000

 

Securities registered under Section 12(b) of the Act:

 

Common Stock, $0.0001 par value   The Nasdaq Global Market
Title of class   Name of exchange on which registered

 

Securities registered under Section 12(g) of the Act:

 

None

 

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.  Yes ☐  No ☒

 

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Exchange Act. Yes ☐  No ☒

 

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 if disclosure of delinquent filers in response to Item 405 of Regulation S-K is not  contained herein, and will not be contained, to the best of the registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ☐

 

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

 

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

 

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

 

State the aggregate market value of voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of the last business day of the fiscal quarter ended June 30, 2014:  $31,645,000

 

As of April 15, 2015, 26,988,240 shares of the registrant’s Common Stock were issued and outstanding.

 

DOCUMENTS INCORPORATED BY REFERENCE

 

Information relating to Part III of this report will be incorporated by reference from an amendment to this report or from the proxy statement for our 2015 annual shareholders meeting, which we expect to file with the Securities and Exchange Commission within 120 days after December 31, 2014.

 

 

 
 

 

FORM 10-K ANNUAL REPORT

FISCAL YEAR ENDED DECEMBER 31, 2014

LILIS ENERGY, INC.

 

    Page
PART I 8
Items 1 and 2.  Business and Properties 8
Item 1A.      Risk Factors 22
Item 1B.    Unresolved Staff Comments 35
Item 3.      Legal Proceedings 35
PART II 37
Item 5.     Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities 37
Item 6. Selected Financial Data 38
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations 38
Item 7A. Quantitative and Qualitative Disclosures About Market Risk 48
Item 8.      Financial Statements and Supplementary Data 48
Item 9. Changes in and disagreements with Accountants on Accounting and Financial Disclosure 49
Item 9A. Controls and Procedures 49
Item 9B. Other Information 50
PART III 51
Item 10. Directors, Executive Officers and Corporate Governance 51
Item 11. Executive Compensation 51

Item 12.

Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters 

51
Item 13. Certain Relationships and Related Transactions, and Director Independence 51
Item 14. Principal Accountant Fees and Services 51
PART IV 52
Item 15. Exhibits and Financial Statement Schedules 52

 

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FORWARD-LOOKING STATEMENTS

 

This annual 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; 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 set forth in this Form 10-K in Part I, “Item 1A. Risk Factors” and the following factors:

 

  availability of capital on an economic basis, or at all, to fund our capital or operating needs;
  our level of debt, which could adversely affect our ability to raise additional capital, limit our ability to react to economic changes and make it more difficult to meet our obligations under our debt;
  restrictions imposed on us under our credit agreement that limit our discretion in operating our business;
  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;
  our history of losses;
  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, material debt agreements or agreements with our investors;
  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 (including water) 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 agreement;
  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;

 

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  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 our large inventory of undeveloped acreage we currently hold on a timely basis;
  constraints, interruptions or other issues affecting the Denver-Julesburg Basin, including with respect to transportation, marketing, processing, curtailment of production, natural disasters, and adverse weather conditions;
  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, approvals and permits 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;
  data protection and cyber-security threats;
  loss of senior management or technical personnel;
  litigation and the outcome of other contingencies, including legal proceedings;
  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;
  anticipated trends in our business;
  effectiveness of our disclosure controls and procedures and internal controls over financial reporting;
  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 SEC filings, available free of charge at the SEC’s website (www.sec.gov).

 

4
 

 

GLOSSARY

 

In this report, the following abbreviation and terms are used:

 

Bbl.  Stock tank barrel, or 42 U.S. gallons liquid volume, used in this report in reference to crude, condensate or natural gas liquids.

 

Bcf.  Billion cubic feet of natural gas.

 

BOE.  Barrels of crude oil equivalent, determined using the .ratio of six mcf of natural gas to one bbl of crude oil, condensate or natural gas liquids.

 

BOE/d.  BOE per day.

 

Completion.  Installation of permanent equipment for production of natural gas or oil, or in the case of a dry hole, the reporting to the appropriate authority that the well has been abandoned.

 

Condensate.  A mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure but that, when produced, is in the liquid phase at surface pressure and temperature.

 

Development well. A well drilled within the proved area of a natural gas or oil reservoir to the depth of a stratigraphic horizon known to be productive.

 

Drilling locations.  Total gross locations specifically quantified by management to be included in our multi-year drilling activities on existing acreage. Our actual drilling activities may change depending on the availability of capital, regulatory approvals, seasonal restrictions, oil and natural gas prices, costs, drilling results and other factors.

 

Dry well; dry hole.  A well found to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well.

 

Exploratory well.  A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of natural gas or oil in another reservoir.

 

Field.  An area consisting of either a single reservoir or multiple reservoirs all grouped on or related to the same geological structural feature and/or stratigraphic condition.

 

Formation.  An identifiable layer of subsurface rocks named after its geographical location and dominant rock type.

 

Gross acres, gross wells, or gross reserves.  A well, acre or reserve in which the Company owns a working interest, reported at the 100% or 8/8ths level. For example, the number of gross wells is the total number of wells in which the Company owns a working interest.

 

Lease.  A legal contract that specifies the terms of the business relationship between an energy company and a landowner or mineral rights holder on a particular tract of land.

 

Leasehold.  Mineral rights leased in a certain area to form a project area.

 

Mbbls.  Thousand barrels of crude oil or other liquid hydrocarbons.

 

Mboe.  Thousand barrels of crude oil equivalent, determined using the ratio of six mcf of natural gas to one bbl of crude oil, condensate or natural gas liquids.

 

Mcf.  Thousand cubic feet of natural gas.

 

Mcfe.  Thousand cubic feet equivalent, determined using the ratio of six mcf of natural gas to one bbl of crude oil, condensate or natural gas liquids.

 

5
 

 

MMbtu.  Million British Thermal Units.

 

MMcf.  Million cubic feet of natural gas.

 

Net acres; net wells.  A “net acre” or “net well” is deemed to exist when the sum of fractional ownership working interests in gross acres or wells equals one. The number of net acres or wells is the sum of the fractional working interests owned in gross acres or wells expressed as whole numbers and fractions of whole numbers.

 

Ngl. Natural gas liquids, or liquid hydrocarbons found as a by-product of natural gas.

 

Overriding royalty interest.  Is similar to a basic royalty interest except that it is created out of the working interest. For example, an operator possesses a standard lease providing for a basic royalty to the lessor or mineral rights owner of 1/8 of 8/8.  This then entitles the operator to retain 7/8 of the total oil and natural gas produced.  The 7/8 in this case is the 100% working interest the operator owns.  This operator may assign his working interest to another operator subject to a retained 1/8 overriding royalty.  This would then result in a basic royalty of 1/8, an overriding royalty of 1/8 and a working interest of 3/4.  Overriding royalty interest owners have no financial or other obligation or responsibility for developing and operating the property.  The only expenses borne by the overriding royalty owner are a share of the production or severance taxes and sometimes costs incurred to make the oil or gas salable.

 

Plugging and abandonment.  Refers to the sealing off of fluids in the strata penetrated by a well so that the fluids from one stratum will not escape into another or to the surface.  Regulations of all states require plugging of abandoned wells.

 

Production.  Natural resources, such as oil or gas, flowed or pumped out of the ground.

 

Productive well.  A producing well or a well that is mechanically capable of production.

 

Proved reserves.  Those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible – from a given date forward, from known reservoirs, under existing economic conditions, operating methods, and government regulations – prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. 

 

Proved developed oil and gas reserves. Proved developed oil and gas reserves are proved reserves that can be expected to be recovered (i) through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and (ii) through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

 

Proved undeveloped reserves.  Proved undeveloped oil and gas reserves are proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

 

Project.  A targeted development area where it is probable that commercial oil and/or gas can be produced from new wells.

 

Prospect.  A specific geographic area which, based on supporting geological, geophysical or other data and also preliminary economic analysis using reasonably anticipated prices and costs, is deemed to have potential for the discovery of commercial hydrocarbons.

 

PV-10 (Present value of future net cash flow). The present value of estimated future revenues to be generated from the production of estimated proved reserves, net of capital expenditures and operating expenses, using the simple 12 month arithmetic average of first of the month prices and current costs (unless such prices or costs are subject to change pursuant to contractual provisions), without giving effect to non-property related expenses such as general and administrative expenses, debt service, future income tax expenses, depreciation, depletion and amortization or impairment, discounted using an annual discount rate of 10%. While this non-GAAP measure does not include the effect of income taxes as would the use of the standardized measure calculation, we believe it provides an indicative representation of the relative value of Lilis Energy on a comparative basis to other companies and from period to period.

 

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Recompletion.  The process of re-entering an existing well bore that is either producing or not producing and modifying the existing completion and/or completing new reservoirs in an attempt to establish new production or increase or re-activate existing production.

 

Reserves.  Estimated remaining quantities of oil, natural gas and gas liquids anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

 

Reservoir.  A subsurface formation containing a natural accumulation of producible natural gas and/or oil that is naturally trapped by impermeable rock or other geologic structures or water barriers and is individual and separate from other reservoirs.

 

Secondary Recovery.  A recovery process that uses mechanisms other than the natural pressure or fluid drive of the reservoir, such as gas injection or water flooding, to produce residual oil and natural gas remaining after the primary recovery phase.

 

Shut-in.  A well suspended from production or injection but not abandoned.

 

Standardized measure.  The present value of estimated future cash flows from proved oil and natural gas reserves, less future development, abandonment, production and income tax expenses, discounted at 10% per annum to reflect timing of future cash flows and using the same pricing assumptions as were used to calculate PV-10.  Standardized measure differs from PV-10 because standardized measure includes the effect of future income taxes.

 

Successful.  A well is determined to be successful if it is producing oil or natural gas in paying quantities.

 

Undeveloped acreage.  Leased acreage on which wells have not been drilled or completed to a point that would permit the production of economic quantities of oil or natural gas regardless of whether such acreage contains proved reserves.

 

Water-flood.  A method of secondary recovery in which water is injected into the reservoir formation to maintain or increase reservoir pressure and displace residual oil and enhance hydrocarbon recovery.

 

Working interest.  The operating interest that gives the lessees/owners the right to drill, produce and conduct operating activities on the property, and to receive a share of the production revenue, subject to all royalties, overriding royalties and other burdens, all development costs, and all risks in connection therewith.

 

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Part I

 

Items 1 and 2. BUSINESS AND PROPERTIES

 

Lilis Energy, Inc. (NASDAQ: LLEX) (“we,” “us,” “our,” “Lilis Energy,” “Lilis,” or the “Company”) is a Denver-based upstream independent oil and gas company engaged in the acquisition, drilling and production of oil and natural gas properties and prospects.  We were incorporated in August of 2007 in the State of Nevada as Universal Holdings, Inc.  In October 2009, we changed our name to Recovery Energy, Inc. and in December 2013, we changed our name to Lilis Energy, Inc.

 

Our current operating activities are focused on the Denver-Julesburg Basin (“DJ Basin”) in Colorado, Wyoming and Nebraska.  Our business strategy is designed to maximize shareholder value by leveraging the knowledge, expertise and experience of our management team and via the future exploration and development of the approximately 65,000 net acres of developed and undeveloped acreage that are currently held by us, primarily in the northern DJ Basin.

 

Recent Developments

 

As previously disclosed, we had significant developments in 2014 through the date of this report, including substantial management changes, the consummation of private placement transactions in January and May of 2014 and the conveyance of the Hexagon Collateral (discussed below) to our primary lender Hexagon, LLC (“Hexagon”) in exchange for extinguishment of all outstanding debt and accrued interest obligations owed to Hexagon in September of 2014. Additionally, we successfully completed a conversion of more than half of our outstanding 8% Senior Secured Convertible Debentures (the “Debentures”) in January of 2014. The Debentures (as previously amended) mature on January 15, 2015; however, in connection with our entry into the Credit Agreement (discussed below) in January 2015, we entered into an extension agreement with the holders of the Debentures, which extends the maturity date of the outstanding Debentures until January 8, 2018. The maturity date now coincides with the maturity date of the Credit Agreement. For further discussion of our capital raising transactions, see Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations—Overview of 2014 and Recent Developments, and the notes to our financial statements.

 

Heartland Bank Credit Agreement

 

On January 8, 2015, we 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 $3.0 million, which principal amount may be increased to a maximum principal amount of $50.0 million at the request of us, subject to certain conditions, pursuant to an accordion advance provision in the Credit Agreement. The availability of additional funds is subject to the discretion of the lenders, and is generally based on the value of the Company’s proved developed producing (“PDP”) and proved undeveloped (“PUD”) reserves. We intends to use proceeds borrowed under the Credit Agreement to fund producing property acquisitions in North America, drill wells in the core of our lease positions and to fund working capital.

 

Overview of Our Business and Strategy

 

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 December 31, 2014 we owned interests in 8 economically producing wells and 67,000 gross (65,000 net) leasehold acres, of which 59,000 gross (57,000 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 with 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 through acquisitions of producing assets and the development of our inventory of low and controlled-risk conventional and unconventional properties, while maintaining a low cost structure, and to acquire companies and production or producing properties (typically with accompanying prospective development opportunity) 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 with funds borrowed under the Credit Agreement and equity to be accessed in capital markets transactions.

 

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Pursuing the initial development of our Greater Wattenberg Field unconventional assets We plan to drill several horizontal wells on our South Wattenberg property during 2015. Drilling activities will target the well established Niobrara and Codell formations.  Subject to the securing of additional capital, we expect to drill and operate up to 8 wells, with an expected investment of approximately $18.0 million.

 

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 exploration 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.  

 

Retain Operational Control and Significant Working Interest.  In our principal development targets, we typically seek to maintain operational control of our development and drilling activities.   As operator, we retain more control over the timing, selection and process of drilling prospects and completion design, which enhances our ability to maximize our return on invested capital and gives us greater control over the timing, allocation and amounts of capital expenditures.  However, due to our recent liquidity difficulties, a significant amount of our current drilling activity on wells in which we own an interest is not operated by us. 

 

Leasing of Prospective Acreage.  In the course of our business, we identify drilling opportunities on properties that have not yet been leased.  Subject to securing additional capital, we may take the initiative to lease prospective acreage and we may sell all or any portion of the leased acreage to other companies that want to participate in the drilling and development of the prospect acreage.

 

Hedging. 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. As such, 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.

 

Acreage. Currently, our inventory of developed and undeveloped acreage includes approximately 8,000 net acres that are held by production, approximately, 49,000, 2,000, 5,000 and 1,000 net acres that expire in the years 2015, 2016, 2017, and thereafter, respectively. Approximately 88% of our inventory of undeveloped acreage provides for extension of lease terms from two to five years, at the option of us, via payment of varying, but typically nominal, extension amounts. We’re currently evaluating the 2015 lease expirations to determine if this acreage is a focus for future development. If determined to be a focus for future development, we plan to re-lease if available. If not a focus, we plan to let the acreage expire. We plan to borrow additional funds under the Credit Agreement to acquire additional bolt-on properties, acquire other properties throughout North America, or drill wells on our core properties to hold the property by production.

 

Capital Raising. 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 companies 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. We will need to raise additional capital to fund our exploration and development, and operating, budget. We plan to 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.

 

Outsourcing. We intend to continue 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. 

 

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Principal Oil and Gas Interests

 

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

 

As of December 31, 2014 we owned interests in approximately 67,000 gross (65,000 net) leasehold acres, of which 59,000 gross (57,000 net) acres are classified as undeveloped acreage and all of which are located in Colorado, Wyoming and Nebraska within the DJ Basin.  Our primary targets within the DJ Basin are the conventional Dakota and Muddy “J” formations, and the developing unconventional Niobrara shale play.   Additional horizons include the Codell, Greenhorn and other potential resource formations.    

 

Effective as of December 31, 2014, we completed an assessment of our inventory of unevaluated acreage, which resulted in a transfer of $9.90 million from unevaluated acreage to evaluated properties.   In assessing the unevaluated acreage, we analyzed the expiration dates during the years ended December 31, 2014 and 2015 of leases that are not otherwise renewable, and transferred such acreage in the amount of $6.99 million.  In addition to the transfer of near and intermediate term expirations, we assessed carrying value of our remaining acreage, and concluded that an additional transfer of $2.91 million was necessary. No proved reserves were associated with the transferred acreage.

 

During 2014, we made minimal capital expenditures on our oil and gas properties due to capital constraints.

 

On September 2, 2014, we entered into a Final Settlement Agreement (defined below) to convey its interest in 31,725 evaluated and unevaluated net acres located in the DJ Basin and the associated oil and natural gas (the “Hexagon Collateral”) to its primary lender, Hexagon in exchange for extinguishment of all outstanding debt and accrued interest obligations owed to Hexagon aggregating to $15.1 million. 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 Final Settlement Agreement, we also issued to Hexagon $2.0 million in 6% Conditionally Redeemable Preferred Stock valued at $1.69 million and considered as temporary equity for reporting purposes. See Item 7 Management Discussion and Analysis of Financial Condition and Results of Operations—Overview of 2014 and Recent Developments —Hexagon Settlement and —Results of Operations—Loss on Conveyance of oil and gas properties.

 

Reserves

 

The table below presents summary information with respect to the estimates of our proved oil and gas reserves for the year ended December 31, 2014. We engaged Ralph E. Davis Associates, Inc. (“RE Davis”) to audit internal engineering estimates for 100 percent of our proved reserves at year-end 2014.  The prices used in the calculation of proved reserve estimates as of December 31, 2014, were $81.71 per Bbl and $5.34 per MCF; as of December 31, 2013, were $89.57 per Bbl and $4.74 per MCF and as of December 31, 2012, were $87.37 per Bbl and $2.75 per MCF for oil and natural gas, respectively.  The prices were adjusted for basis differentials, pipeline adjustments, and BTU content.

 

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We emphasize that reserve estimates are inherently imprecise and that estimates of all new discoveries and undeveloped locations are more imprecise than estimates of established producing oil and gas properties.  Accordingly, these estimates are expected to change as new information becomes available.  The PV-10 values shown in the following table are not intended to represent the current market value of the estimated proved oil and gas reserves owned by us.  Neither prices nor costs have been escalated (or reduced).  The following table should be read along with the section entitled “Risk Factors — Risks Related to Our Company”.  The actual quantities and present values of our proved oil and natural gas reserves may be less than we have estimated.  

 

   As of December 31, 
   2014   2013   2012 
Reserve data:    
Proved developed            
Oil (MBbl)   50    171    213 
Gas (MMcf)   197    313    186 
Total (MBOE)(1)   83    223    244 
Proved undeveloped               
Oil (MBbl)   850    672    138 
Gas (MMcf)   4,040    2,251    221 
Total (MBOE)(1)   1,523    1,047    175 
Total Proved               
Oil (MBbl)   900    843    351 
Gas (MMcf)   4,237    2,564    407 
Total (MBOE)(1)   1,606    1,270    419 
Proved developed reserves %   5%   18%   58%
Proved undeveloped reserves %   95%   82%   42%
                
Reserve value data (in thousands):               
Proved developed PV-10  $2,340   $7,675   $9,743 
Proved undeveloped PV-10  $20,914   $15,667   $5,679 
Total proved PV-10 (2)  $23,254   $23,342   $15,422 
Standardized measure of discounted future cash flows  $23,254   $23,342   $15,422 
Reserve life (years)   39.25    33.25    42.42 

 

(1) BOE is determined using the ratio of six MCF of natural gas to one Bbl of crude oil, condensate or natural gas.
(2) As we currently do not expect to pay income taxes in the near future, there is no difference between the PV-10 value and the standardized measure of discounted future net cash flows.  Please see the definitions of standardized measure of discounted future net cash flows and PV-10 value in the “Glossary.”

 

Changes in Proved Undeveloped Reserves

 

The 476 MBOE or 45% increase of proved undeveloped reserves to 1,523 MBOE at year end 2014 from 1,047 MBOE at year end 2013 reflects, in part, additional proved undeveloped locations, partially offset by the 347 MBOE conveyed to Hexagon described in detail above. An acreage block owned by us was determined to be proved undeveloped based on offset successful drilling activity of other operators. We did not incur any cost on our proved undeveloped acreage in 2014. 

 

Effective as of December 31, 2014, we completed an assessment of our inventory of unevaluated acreage, which resulted in a transfer of $9.90 million to evaluated properties.   In assessing the unevaluated acreage, we analyzed its expiration dates during the years ended December 31, 2014 and 2015, which are not otherwise renewable, and transferred such acreage in the amount of $6.99 million.  In addition to the transfer of near and intermediate term expirations, we assessed the carrying value of our remaining acreage, and concluded that an additional transfer of $2.91 million was necessary. No proved reserves were associated with the transferred acreage.

 

At December 31, 2014, we have no proved undeveloped reserves that are scheduled for development five years or more beyond the date the reserves were initially recorded.

 

Internal Controls over Reserves Estimate

 

Our policy regarding internal controls over the recording of reserves is structured to objectively and accurately estimate our oil and gas reserve quantities and values in compliance with the regulations of the SEC.  Responsibility for compliance in reserve bookings is delegated to our Chief Financial Officer with assistance from our senior geologist consultant, principal accounting officer, and a senior reserve engineering consultant.

 

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Technical reviews are performed throughout the year by our senior reserve engineering consultant and our geologist and other consultants who evaluate all available geological and engineering data, under the guidance of the Chief Financial Officer.  This data, in conjunction with economic data and ownership information, is used in making a determination of estimated proved reserve quantities.  The 2014 reserve process was overseen by Kent Lina, our senior reserve engineering consultant.  Mr. Lina was previously employed by us from October 2010 through December 2012, and prior to that employed by Delta Petroleum Corporation from March 2002 to September 2010 in various operations and reservoir engineering capacities culminating as the Senior V.P. of Corporate Engineering.  Mr. Lina received a Bachelor of Science degree in Civil Engineering from University of Missouri at Rolla in 1981.  Mr. Lina currently serves various industry clients as a senior reserve engineering consultant.

 

Third-party Reserves Study

 

An independent third-party reserve study as of December 31, 2014 was performed by RE Davis using its own engineering assumptions and other economic data provided by us.  One hundred percent of our total calculated proved reserve PV-10 value was audited by RE Davis.  RE Davis is an independent petroleum engineering consulting firm that has been providing petroleum engineering consulting services for over 20 years.  The individual at RE Davis primarily responsible for overseeing our reserve audit is Allen C. Barron, the President and CEO, who received a Bachelor of Science degree in Chemical and Petroleum Engineering from the University of Houston and is a registered Professional Engineer in the States of Texas.  He is also a member of the Society of Petroleum Engineers.  The RE Davis report dated March 10, 2015, is filed as Exhibit 99.1 to this Annual Report.

 

Oil and gas reserves and the estimates of the present value of future net cash flows therefrom were determined based on prices and costs as prescribed by the SEC and Financial Accounting Standards Board (“FASB”) guidelines.  Reserve calculations involve the estimate of future net recoverable reserves of oil and gas and the timing and amount of future net cash flows to be received therefrom. Such estimates are not precise and are based on assumptions regarding a variety of factors, many of which are variable and uncertain.  Proved reserves were estimated in accordance with guidelines established by the SEC and the FASB, which require that reserve estimates be prepared under existing economic and operating conditions with no provision for price and cost escalations except by contractual arrangements.  For the year ended December 31, 2014, commodity prices over the prior 12-month period and year end costs were used in estimating net cash flows in accordance with SEC guidelines.

 

In addition to a third party reserve study, our reserves and the corresponding report are reviewed by our Chief Financial Officer, geologist and principal accounting officer and the Audit Committee of our Board of Directors.   Our Chief Financial Officer is responsible for reviewing and verifying that the estimate of proved reserves is reasonable, complete, and accurate.  The Audit Committee reviews the final reserves estimate in conjunction with RE Davis’ audit letter. 

 

Production

 

The following table summarizes the average volumes and realized prices, excluding the effects of our economic hedges, of oil and gas produced from properties in which we held an interest during the periods indicated.  Also presented is a production cost per BOE summary: 

 

   For the Year Ended December 31, 
   2014   2013   2012 
Product            
Oil (Bbl.)   33,508    51,705    68.207 
Oil (Bbls)-average price (1)  $77.05   $83.40   $86.48 
                
Natural Gas (MCF)-volume   77,954    64,845    182,160 
Natural Gas  (MCF)-average price (2)  $4.68   $5.25   $2.23 
                
Barrels of oil equivalent (BOE)   46,500    62,512    98,567 
Average daily net production (BOE)   127    171    270 
Average Price per BOE (1)  $63.36   $74.43   $63.96 

 

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

 

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Oil and gas production costs, production taxes, depreciation, depletion, and amortization

 

Average Price per BOE (1)  $63.36   $74.43   $63.96 
                
Production costs per BOE  $20.52   $19.48   $14.42 
Production taxes per BOE  $5.80   $4.21   $2.31 
Depreciation, depletion, and amortization per BOE  $28.76   $38.21   $46.15 
Total operating costs per BOE (2)  $55.08   $61.90   $62.88 
                
Gross margin per BOE (2)  $8.28   $12.53   $1.08 
                
Gross margin percentage   13%   17%   2%

 

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

(2)    Does not include the loss on conveyance

 

Productive Wells

 

As of December 31, 2014, after the conveyance on September 2, 2014, we had working interests in 6 gross (1.27 net) productive oil wells, and 2 gross (.14 net) productive gas wells.  Productive wells are either wells producing in commercial quantities or wells capable of commercial production although currently shut-in.  Multiple completions in the same wellbore are counted as one well.  A well is categorized under state reporting regulations as an oil well or a gas well based on the ratio of gas to oil produced when it first commenced production, and such designation may not be indicative of current production.

 

Acreage

 

As of December 31, 2014 we owned 8 producing wells in Wyoming, Nebraska and Colorado within the DJ Basin, as well as approximately 67,000 gross (65,000 net) acres, of which 59,000 gross (57,000 net) acres were classified as undeveloped acreage. Our primary assets included acreage located in Laramie and Goshen Counties in Wyoming; Banner, Kimball, and Scotts Bluff Counties in Nebraska; and Weld, Arapahoe and Elbert Counties in Colorado.  

 

The following table sets forth certain information with respect to our developed and undeveloped acreage as of December 31, 2014.

 

   Undeveloped   Developed 
   Gross   Net   Gross   Net 
DJ Basin   59,000    57,000    8,000    8,000 
                     
Total   59,000    57,000    8,000    8,000 

  

At December 31, 2014, our inventory of developed and undeveloped acreage includes approximately 8,000 net acres that are held by production, approximately, 49,000, 2,000 and 5,000 and 1,000 net acres that expire in the years 2015, 2016, 2017, and thereafter, respectively. Approximately 89% of our inventory of undeveloped acreage provides for extension of lease terms from two to five years, at the option of us, via payment of varying, but typically nominal, extension amounts. We’re currently evaluating the 2015 lease expirations to determine if this acreage is a focus for future development. If determined to be a focus for future development, we plan to re-lease if available. If not a focus, we plan to let the acreage expire. We plan to borrow additional funds under the Credit Agreement and to seek additional debt or equity capital, if available, to acquire additional bolt-on properties, acquire other properties throughout North America, or drill wells on our core properties to hold the property by production.

 

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Drilling Activity

 

The following table describes the development and exploratory wells we drilled from 2012 through 2014:

 

   For the Year Ended December 31, 
   2014   2013   2012 
   Gross   Net   Gross   Net   Gross   Net 
Development:                        
Productive wells   -    -    2    1    5    3 
Dry wells   -    -    -    -    1    1 
    -    -    2    1    6    4 
Exploratory:                              
Productive wells   -    -    -    -    -    - 
Dry wells   -    -    -    -    -    - 
                               
                               
Total development and exploratory   -    -    2    1    6    4 

 

The number of wells drilled refers to the number of wells completed at any time during the respective year, regardless of when drilling was initiated.  As of December 31, 2014, we had no drilling activities on-going.

  

Title to Properties

 

Substantially all of our leasehold interests are held pursuant to leases from third parties. The majority of our producing properties are subject to mortgages securing indebtedness under our Credit Agreement and Debentures, which we believe do not materially interfere with the use of, or affect the value of, such properties.

 

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 eight operated 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 to the ability to secure additional capital through equity placement, utilizing borrowings under the Credit Agreement with Heartland Bank and additional debt instruments and funds contemplated by the agreement with Heartland Bank to acquire production in North America.

 

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, 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.

 

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

  

The dispute relates to our interest in certain producing wells and the well operator’s assertion that the Company’s interest was reduced and/or eliminated as a result of a default or a farm-out agreement. Underlying the dispute is a Joint Operating agreement (“JOA”), which provides the parties with various rights and obligations.

 

On March 6, 2015, the Company filed a lawsuit against the operator.  In its complaint, we seek monetary damages and declaratory relief on claims of breach of contract, breach of the implied covenant of good faith and fair dealing, tortious breach of the implied covenant of good faith and fair dealing, unjust enrichment, conversion and declaratory judgment related to the JOA. The operator has not yet responded to the complaint.

 

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Marketing and Pricing

 

We derive revenue and cash flow 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 other cash requirements 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 natural gas and crude oil.  Historically, the prices received for oil and natural gas have fluctuated widely.  Among the factors that can cause these fluctuations are:

 

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

  

Furthermore, regional natural gas, condensate, oil and NGL prices may move independently of broad industry price trends. Because some of our operations are located outside major markets, we are directly impacted by regional prices regardless of Henry Hub, WTI or other major market pricing.

 

From time to time, we enter into derivative contracts. These contracts economically hedge 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 counterparty 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.

 

As of December 31, 2014, we had no hedging agreements in place.

 

Major Customers

 

We have one major customer, Shell Trading (US), which accounted for approximately 63% and 83% of our revenues for the years ended December 31, 2014 and 2013, respectively.  PDC Energy, a new customer in 2014, accounted for 13% of our revenue for the year ended December 31, 2014.

 

However, we does not believe that the loss of a single purchaser, including Shell Trading (US) and PDC Energy, would materially affect our business because there are numerous other purchasers in the area in which we sell our production.

 

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Seasonality

 

Generally, but not always, the demand and price levels for natural gas increase during colder winter months and decrease during warmer summer months. To lessen seasonal demand fluctuations, pipelines, utilities, local distribution companies, and industrial users utilize natural gas storage facilities and forward purchase some of their anticipated winter requirements during the summer.  However, increased summertime demand for electricity has placed increased demand on storage volumes.  Demand for crude oil and heating oil is also generally higher in the winter and the summer driving season, although oil prices are much more driven by global supply and demand.  Seasonal anomalies, such as mild winters, sometimes lessen these fluctuations.  The impact of seasonality on crude oil has been somewhat magnified by overall supply and demand economics attributable to the narrow margin of production capacity in excess of existing worldwide demand for crude oil.

 

Competition

 

The oil and gas industry is intensely competitive, particularly with respect to acquiring prospective oil and natural gas properties.  We believe our leasehold position provides a solid foundation for an economically robust exploration program and our future growth.  Our success and growth also depends on our geological, geophysical, and engineering expertise, design and planning, and our financial resources.  We believe the location of our acreage, our technical expertise, available technologies, our financial resources and expertise, and the experience and knowledge of our management enables us to compete effectively in our core operating areas.  However, we face intense competition from a substantial number of major and independent oil and gas companies, which have larger technical staffs and greater financial and operational resources than we do.  Many of these companies not only engage in the acquisition, exploration, development, and production of oil and natural gas reserves, but also have refining operations, market refined products, own drilling rigs, and generate electricity.

 

We also compete with other oil and gas companies in attempting to secure drilling rigs and other equipment and services necessary for the drilling, completion, production, processing and maintenance of wells.  Consequently, we may face shortages or delays in securing these services from time to time.  The oil and gas industry also faces competition from alternative fuel sources, including other fossil fuels such as coal and imported liquefied natural gas.  Competitive conditions may also be affected by future new energy, climate-related, financial, and other policies, legislation, and regulations.

 

In addition, we compete for people, including experienced geologists, geophysicists, engineers, and other professionals and consultants.  Throughout the oil and gas industry, the need to attract and retain talented people has grown at a time when the number of talented people available is constrained.  We are not insulated from this resource constraint, and we must compete effectively in this market in order to be successful.

 

Government Regulations

 

General. Our operations covering the exploration, production and sale of oil and natural gas are subject to various types of federal, state and local laws and regulations.  The failure to comply with these laws and regulations can result in substantial penalties. These laws and regulations materially impact our operations and can affect our profitability. However, we do not believe that these laws and regulations affect us in a manner significantly different than our competitors. Matters regulated include permits for drilling operations, drilling and abandonment bonds, reports concerning operations, the spacing of wells and unitization and pooling of properties, restoration of surface areas, plugging and abandonment of wells, requirements for the operation of wells, production and processing facilities, land use, subsurface injection, air emissions,  and taxation of production, etc.  At various times, regulatory agencies have imposed price controls and limitations on production.  In order to conserve supplies of oil and natural gas, these agencies have restricted the rates of flow of oil and natural gas wells below actual production capacity, generally prohibit the venting or flaring of natural gas and impose certain requirements regarding production. Federal, state and local laws regulate production, handling, storage, transportation and disposal of oil and natural gas, by-products from oil and natural gas and other substances and materials produced or used in connection with oil and natural gas operations.  While we believe we will be able to substantially comply with all applicable laws and regulations via our strict attention to regulatory compliance, the requirements of such laws and regulations are frequently changed.  We cannot predict the ultimate cost of compliance with these requirements or their effect on our actual operations.

 

Federal Income Tax. Federal income tax laws significantly affect our operations.  The principal provisions that affect us are those that permit us, subject to certain limitations, to deduct as incurred, rather than to capitalize and amortize/depreciate, our domestic “intangible drilling and development costs” and to claim depletion on a portion of our domestic oil and natural gas properties based on 15% of our oil and natural gas gross income from such properties (up to an aggregate of 1,000 barrels per day of domestic crude oil and/or equivalent units of domestic natural gas). 

 

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Environmental, Health, and Safety Regulations.  Our operations are subject to stringent federal, state, and local laws and regulations relating to the protection of the environment and human health and safety (“EHS”). We are committed to strict compliance with these regulations and the utmost attention to EHS issues.  Environmental laws and regulations may require that permits be obtained before drilling commences or facilities are commissioned, restrict the types, quantities, and concentration of various substances that can be released into the environment in connection with drilling and production activities, govern the handling and disposal of waste material, and limit or prohibit drilling and exploitation activities on certain lands lying within wilderness, wetlands, and other protected areas, including areas containing threatened or endangered animal species.  As a result, these laws and regulations may substantially increase the costs of exploring for, developing, or producing oil and gas and may prevent or delay the commencement or continuation of certain projects.  In addition, these laws and regulations may impose substantial clean-up, remediation, and other obligations in the event of any discharges or emissions in violation of these laws and regulations.  Further, legislative and regulatory initiatives related to global warming or climate change could have an adverse effect on our operations and the demand for oil and natural gas.  See “Risk Factors — Risks Related to the Oil and Gas Industry — Legislative and regulatory initiatives related to global warming and climate change could have an adverse effect on our operations and the demand for oil and natural gas.”

  

Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons, particularly natural gas, from tight unconventional formations.  For additional information about hydraulic fracturing and related regulatory matters, see “Risk Factors— Risks Relating to the Oil and Gas Industry.”  Federal and state legislation and regulatory initiatives related to hydraulic fracturing could result in increased costs and additional operating restrictions or delays /cancellations in the completion of oil and gas wells.

 

Federal and state occupational safety and health laws require us to organize and maintain information about hazardous materials used, released, or produced in our operations.  Some of this information must be provided to our employees, state and local governmental authorities, and local citizens.  We are also subject to the requirements and reporting framework set forth in the federal workplace standards.

 

The discharge of oil, gas or other pollutants into the air, soil or water may give rise to liabilities to the government and third parties and may require us to incur costs to remedy discharges.  Natural gas, oil or other pollutants, including salt water brine, may be discharged in many ways, including from a well or drilling equipment at a drill site, leakage from pipelines or other gathering and transportation facilities, leakage from storage tanks and sudden discharges from damage or explosion at natural gas facilities of oil and gas wells.  Discharged hydrocarbons may migrate through soil to fresh water aquifers or adjoining property, giving rise to additional liabilities.

 

A variety of federal and state laws and regulations govern the environmental aspects of natural gas and oil production, transportation and processing. These laws and regulations may impose liability in the event of discharges, including for accidental discharges, failure to notify the proper authorities of a discharge, and other noncompliance.  Compliance with such laws and regulations may increase the cost of oil and gas exploration, development and production; although we do not anticipate that compliance will have a material adverse effect on our capital expenditures or earnings.  Failure to comply with the requirements of the applicable laws and regulations could subject us to substantial civil and/or criminal penalties and to the temporary or permanent curtailment or cessation of all or a portion of our operations.

 

The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), also known as the “superfund law,” imposes liability, regardless of fault or the legality of the original conduct, on some classes of persons that are considered to have contributed to the release of a “hazardous substance” into the environment. These persons include the owner or operator of a disposal site or sites where the release occurred and companies that transport, dispose, or arrange for disposal of the hazardous substance(s) released.  Persons who are or were responsible for releases of hazardous substances under CERCLA may be jointly and severally liable for the costs of cleaning up the hazardous substances and for damages to natural resources. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment.  We could be subject to liability under CERCLA, including for jointly owned drilling and production activities that generate relatively small amounts of liquid and solid waste that may be subject to classification as hazardous substances under CERCLA.

 

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The Resource Conservation and Recovery Act of 1976, as amended (“RCRA”) is the principal federal statute governing the treatment, storage and disposal of solid and hazardous wastes.  RCRA imposes stringent operating requirements, and liability for failure to meet such requirements, on a person who is either a “generator” or “transporter” of hazardous waste or an “owner” or “operator” of a hazardous waste treatment, storage or disposal facility.  At present, RCRA includes an exemption that allows certain oil and natural gas exploration and production waste to be classified as nonhazardous waste.  A similar exemption is contained in many of the state counterparts to RCRA. As a result, we are not required to comply with a substantial portion of RCRA’s hazardous waste requirements.  At various times in the past, proposals have been made to amend RCRA to rescind the exemption that excludes oil and natural gas exploration and production wastes from regulation as hazardous waste. For example, in 2010 a petition was filed by the Natural Resources Defense Council with the Environmental Protection Agency (“EPA”) requesting that the agency reassess its prior determination that certain E&P wastes are not subject to the RCRA hazardous waste requirements. EPA has not yet acted on the petition and it remains pending. Repeal or modification of the exemption by administrative, legislative or judicial process, or modification of similar exemptions in applicable state statutes, would increase the volume of hazardous waste we are required to manage and dispose of and would cause us to incur, perhaps significantly, increased operating expenses.

 

The Oil Pollution Act of 1990 (“OPA”), and regulations thereunder impose a variety of regulations on “responsible parties” related to the prevention of oil spills and liability for damages resulting from such spills in United States waters.  The OPA assigns liability to each responsible party for oil removal costs and a variety of public and private damages, including natural resource damages.  While liability limits apply in some circumstances, a party cannot take advantage of liability limits if the spill was caused by gross negligence or willful misconduct or resulted from violation of federal safety, construction or operating regulations.  Few defenses exist to the liability imposed by OPA. In addition, to the extent we acquire offshore leases and those operations affect state waters, we may be subject to additional state and local clean-up requirements or incur liability under state and local laws.  OPA also imposes ongoing requirements on responsible parties, including proof of financial responsibility to cover at least some costs in a potential spill.  We cannot predict whether the financial responsibility requirements under the OPA amendments will adversely restrict our proposed operations or impose substantial additional annual costs to us or otherwise materially adversely affect us.  The impact, however, should not be any more adverse to us than it will be to other similarly situated owners or operators.

 

The Endangered Species Act (“ESA”) restricts activities that may affect federally identified endangered and threatened species or their habitats through the implementation of operating restrictions or a temporary, seasonal, or permanent ban in affected areas. Additionally, significant federal decisions, such as the issuance of federal permits or authorizations for certain oil and gas exploration and production activities may be subject to the National Environmental Policy Act (“NEPA”). NEPA requires federal agencies, including the Department of Interior, to evaluate major federal agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an environmental assessment that assesses the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed Environmental Impact Statement that may be made available for public review and comment. This process has the potential to delay oil and gas development projects.

 

The federal Clean Water Act (the “Clean Water Act”), imposes restrictions and controls on the discharge of produced waters and other oil and natural gas wastes into navigable waters.  Permits must be obtained to discharge pollutants into state and federal waters and to discharge fill and pollutants into regulated waters and wetlands. Uncertainty regarding regulatory jurisdiction over wetlands and other regulated waters of the United States has complicated, and will continue to complicate and increase the cost of, obtaining such permits or other approvals. Certain state regulations and the general permits issued under the Federal National Pollutant Discharge Elimination System (“NPDES”) program prohibit the discharge of produced waters and sand, drilling fluids, drill cuttings and certain other substances related to the crude oil and natural gas industry into certain coastal and offshore waters.  Further, the EPA, has adopted regulations requiring certain crude oil and natural gas exploration and production facilities to obtain permits for storm water discharges.  Costs may be associated with the treatment of wastewater or developing and implementing storm water pollution prevention plans.  Spill Prevention, Control, and Countermeasure ("SPCC") requirements of the CWA require appropriate secondary containment loadout controls, piping controls, berms and other measures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon spill, rupture or leak. The EPA and U.S. Army Corps of Engineers released a Connectivity Report in September 2013, which determined that virtually all tributary streams, wetlands, open water in floodplains and riparian areas are connected. This report supported the drafting of proposed rules providing updated standards for what will be considered jurisdictional waters of the U.S. The proposed rules have been submitted for public comment, and are expected to be finalized in 2015. The Clean Water Act and comparable state statutes provide for civil, criminal and administrative penalties for unauthorized discharges of crude oil and other pollutants and impose liability on parties responsible for those discharges for the costs of cleaning up any environmental damage caused by the release and for natural resource damages resulting from the release.  We believe that our operations comply in all material respects with the requirements of the Clean Water Act and state statutes enacted to control water pollution.

 

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The Safe Drinking Water Act of 1974, as amended, establishes a regulatory framework for the underground injection of a variety of wastes, including bring produced and separated from crude oil and natural gas production, with the main goal being the protection of usable aquifers. The primary objective of injection well operating permits and requirements is to ensure the mechanical integrity of the wellbore and to prevent migration of fluids from the injection zone into underground sources of drinking water. Class II underground injection wells, a predominant storage method for crude oil and natural gas wastewater, are strictly controlled, and certain wastes, absent an exemption, cannot be injected into such wells.  Failure to abide by our permits could subject us to civil or criminal enforcement.  We believe that we are in compliance in all material respects with the requirements of applicable state underground injection control programs and our permits.

 

The federal Clean Air Act (the “Clean Air Act”) and comparable state and local air pollution laws adopted to fulfill its mandate provide a framework for national, state and local efforts to protect air quality.  Our operations utilize equipment that emits air pollutants which may be subject to federal and state air pollution control laws.  These laws generally require utilization of air emissions control equipment to achieve prescribed emissions limitations and ambient air quality standards, as well as operating permits for existing equipment and construction permits for new and modified equipment.  We believe that we are in compliance in all material respects with the requirements of applicable federal and state air pollution control laws.  Over the next several years, we may be required to incur capital expenditures for air pollution control equipment or other air emissions-related issues.  EPA promulgated significant New Source Performance Standards (“NSPS OOOO”) in 2012, as amended in 2013 and 2014, which have added administrative and operational costs. EPA is reconsidering portions of NSPS OOOO and this process may result in additional federal control requirements. Colorado adopted NSPS OOOO in 2014. In addition, Colorado adopted new air regulations for the oil and gas industry effective April 14, 2014, that impose control and other requirements more stringent than NSPS OOOO. These new Colorado oil and natural gas air rules will likely increase our administrative and operational costs.

 

On December 17, 2014, the EPA proposed to revise and lower the existing 75 ppb national ambient air quality standard (“NAAQS”) for ozone under the federal Clean Air Act to a range within 65-70 ppb. EPA is also taking public comment on whether the ozone NAAQS should be revised as low as 60 ppb. A lowered ozone NAAQS in a range of 60-70 ppb could result in a significant expansion of ozone nonattainment areas across the United States, including areas in which we operate. Oil and natural gas operations in ozone nonattainment areas would likely be subject to increase regulatory burdens in the form of more stringent emission controls, emission offset requirements, and increased permitting delays and costs.

 

There are numerous state laws and regulations in the states in which we operate which relate to the environmental aspects of our business. These state laws and regulations generally relate to requirements to remediate spills of deleterious substances associated with oil and gas activities, the conduct of salt water disposal operations, and the methods of plugging and abandonment of oil and gas wells which have been unproductive.  Numerous state laws and regulations also relate to air and water quality.

 

In 2014, Colorado Governor Hickenlooper created the Task Force on State and Local Regulation of Oil and Gas Operations (“Task Force”) to provide recommendations regarding the state and local regulation of oil and gas operations. The Task Force provided its final recommendations on February 27, 2015, which include recommendations for future Colorado rulemakings or legislation to address, among others, local government collaboration with oil and gas operators, operator registration requirements with local governments and submission of operational information for incorporation into local comprehensive plans, and creation of an oil and gas information clearinghouse. We cannot predict the ultimate outcome of the Task Force’s recommendations.

 

Additionally, the Colorado Oil and Gas Conservation Act was amended in 2014 to increase the potential sanctions for violating the Act or its implementing regulations, orders, or permits. These amendments increase the maximum penalty per violation per day from $1,000 to $15,000; eliminate a $10,000 maximum penalty for violations that do not result in significant waste of oil and gas resources, damage to correlative rights, or adverse impact to public health, safety, or welfare; require the Colorado Oil and Gas Conservation Commission (“COGCC”) to assess a penalty for each day there is evidence of a violation; and authorize the COGCC to prohibit the issuance of new permits and suspend certificates of clearance for egregious violations resulting from gross negligence or knowing and willful misconduct. In 2015, the COGCC, consistent with the amendments to the Act, amended its regulations governing enforcement and penalties. We cannot predict how such regulatory amendments will ultimately affect the penalties assessed by the COGCC in future enforcement cases involving us.

 

We do not believe that our environmental risks will be materially different from those of comparable companies in the oil and gas industry.  We believe our present activities substantially comply, in all material respects, with existing environmental laws and regulations.  Nevertheless, we cannot assure you that environmental laws will not result in a curtailment of production or material increase in the cost of production, development or exploration or otherwise adversely affect our financial condition and results of operations.  Although we maintain liability insurance coverage for liabilities from pollution, environmental risks, generally are not fully insurable.

 

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In addition, because we have acquired and may acquire interests in properties that have been operated in the past by others, we may be liable for environmental damage, including historical contamination, caused by such former operators.  Additional liabilities could also arise from continuing violations or contamination not discovered during our assessment of the acquired properties.

  

Federal Leases.  For those operations on federal oil and gas leases, such operations must comply with numerous regulatory restrictions, including various non-discrimination statutes, and certain of such operations must be conducted pursuant to certain on-site security regulations and other permits issued by various federal agencies.  In addition, on federal lands in the United States, the Office of Natural Resources Revenue (“ONRR”) prescribes or severely limits the types of costs that are deductible transportation costs for purposes of royalty valuation of production sold off the lease.  In particular, ONRR prohibits deduction of costs associated with marketer fees, cash out and other pipeline imbalance penalties, or long-term storage fees.  Further, the ONRR has been engaged in a process of promulgating new rules and procedures for determining the value of crude oil produced from federal lands for purposes of calculating royalties owed to the government.  The natural gas and crude oil industry as a whole has resisted the proposed rules under an assumption that royalty burdens will substantially increase.  We cannot predict what, if any, effect any new rule will have on our operations.

 

Some of our operations are conducted on federal lands pursuant to oil and gas leases administered by the Bureau of Land Management (“BLM”).  These leases contain relatively standardized terms and require compliance with detailed regulations and orders, which are subject to change.  In addition to permits required from other regulatory agencies, lessees must obtain a permit from the BLM before drilling and comply with regulations governing, among other things, engineering and construction specifications for production facilities, safety procedures, the valuation of production and payment of royalties, the removal of facilities, and the posting of bonds to ensure that lessee obligations are met.  Under certain circumstances, the BLM may require our operations on federal leases to be suspended or terminated.

  

In May 2010, the BLM adopted changes to its oil and gas leasing program that require, among other things, a more detailed environmental review prior to leasing oil and natural gas resources, increased public engagement in the development of master leasing and development plans prior to leasing areas where intensive new oil and gas development is anticipated, and a comprehensive parcel review process.  These changes have increased the amount of time and regulatory costs necessary to obtain oil and gas leases administered by the BLM. In addition, the BLM, on March 20, 2015, issued its final regulations for hydraulic fracturing on federal and tribal lands. The new regulations require, among other things, disclosure of chemicals, annulus pressure monitoring, flow back and produced water management and storage, and more stringent well integrity measures associated with hydraulic fracturing operations on public land. The new regulations become effective on June 24, 2015. BLM has also announced its intention to conduct a separate rulemaking to address venting and flaring of natural gas from oil and gas operations on public land. These hydraulic fracturing-related rulemakings may adversely affect our operations conducted on federal lands.

 

Other Laws and Regulations.  Various laws and regulations require permits for drilling wells and also cover spacing of wells, the prevention of waste of natural gas and oil including maintenance of certain gas/oil ratios, rates of production and other matters.  The effect of these laws and regulations, as well as other regulations that could be promulgated by the jurisdictions, in which we have production, could be to limit the number of wells that could be drilled on our properties and to limit the allowable production from the successful wells completed on our properties, thereby limiting our revenues.

 

To date we have not experienced any material adverse effect on our operations from obligations under environmental, health, and safety laws and regulations.  We believe that we are in substantial compliance with currently applicable environmental, health, and safety laws and regulations, and that continued compliance with existing requirements will not have a materially adverse impact on us.

 

Employees

 

As of December 31, 2014, we had three full-time employees and no part-time employees.  Subsequent to year end, we added two employees, including Kevin Nanke as Chief Financial Officer and Ariella Fuchs as General Counsel. For the foreseeable future, we intend to only add additional personnel as our operational requirements grow.  In the interim, we plan to continue to leverage the use of independent consultants and contractors to provide various professional services, including land, legal, engineering, geology, environmental and tax services.  We believe that by limiting our management and employee costs, we are able to better control total costs and retain flexibility in terms of project management.

 

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Executive Officers of the Company

 

Our executive officers of the Company at the time of this filing are as follows:

 

Name   Age   Office (1)   First Elected to Present Office
Abraham “Avi” Mirman   45   Chief Executive Officer (2)   April 21, 2014
Kevin Nanke   50   Executive Vice President and Chief Financial Officer (3)   March 6, 2015
Eric Ulwelling   36   Principal Accounting Officer and Controller (4)   February 1, 2012
Ariella Fuchs   33   General Counsel (5)   March 16, 2015

 

(1)Executive officers are elected for one-year terms at the annual organizational meeting of the Board of Directors (the “Board”), which follows the annual meeting of stockholders.

 

(2)Mr. Mirman currently serves as our Chief Executive Officer, and has held that position since April 21, 2014. Prior to being appointed to his current position of Chief Executive Officer, Mr. Mirman served as our President beginning in September 2013. Mr. Mirman served as the Managing Director, Investment Banking at TR Winston from April 2013 until September 2014. Between 2012 and February 2013, he served as Head of Investment Banking at John Thomas Financial, and between 2011 and 2012, he served as Head of Investment Banking at BMA Securities. Between 2006 and 2011, Mr. Mirman served as Chairman of the Board of Cresta Capital Strategies LLC. Mr. Mirman has extensive experience in financial and securities matters, including in obtaining financing for and providing financial advisory services to micro-cap public companies, including oil and gas and other energy companies. Mr. Mirman graduated from the State University of New York at Buffalo with a B.S. in Political Science.

 

(3)On March 6, 2015, the Board appointed Kevin Nanke to the position of Executive Vice President and Chief Financial Officer, effective immediately. Mr. Nanke, age 50, served as the President of KN Consulting, Inc., a consulting firm focused on the energy, real estate and restaurant industries, from 2012 to 2015. Previously, Mr. Nanke served as the Treasurer and Chief Financial Officer of Delta Petroleum Corporation (“Delta”) from 1999 to 2012, and as its Controller from 1995 to 1999. At the same time, Mr. Nanke served as Treasurer and Chief Financial Officer of Amber Resources, an exploration and production (“E&P”) subsidiary of Delta, and as Treasurer, Chief Financial Officer and Director of DHS Drilling Company, a drilling company that was 50% owned by Delta. Prior to joining Delta, Mr. Nanke was employed by KPMG LLP, a global audit, tax and advisory firm. Mr. Nanke received a Bachelor of Arts degree in Accounting from the University of Northern Iowa in 1989 and is a Certified Public Accountant (inactive).

 

(4)Eric Ulwelling, who served as our Chief Financial Officer prior to the appointment of Mr. Nanke, ceased to serve in that role but continues on to serve as our’s Principal Accounting Officer and Controller. Mr. Ulwelling was appointed by the Board to the position of Chief Financial Officer in October 2014. Mr. Ulwelling joined us in 2012, serving as our Controller and Principal Accounting Officer until he was appointed to the position of Acting Chief Financial Officer in May 2014. From 2009-2011, Mr. Ulwelling served as a controller with Applied Natural Gas Fuels, Inc. From 2006 to 2009, he worked as an auditor with Singer Lewak, servicing publicly traded companies, and prior to that worked as an auditor with Pannell Kerr Forster. Mr. Ulwelling received a Bachelor of Science in Accounting from California State University of Fullerton, in 2002.

 

(5)Ariella Fuchs was most recently an associate with Baker Botts L.L.P. from April 2013 to February 2015, specializing in securities transactions and corporate governance. Prior to joining Baker Botts L.L.P, she served as an associate at White & Case LLP and Dewey and LeBoeuf LLP from January 2010 to March 2013 in their mergers and acquisitions groups. Ms. Fuchs received a J.D. degree from New York Law School and a B.A. degree in Political Science from Tufts University.

 

Available Information

 

Our executive offices are located at 216 16th Street, Suite 1350, Denver, Colorado 80202, and our telephone number is (303) 893-9000. Our web site is www.lilisenergy.com. Additional information that may be obtained through our web site does not constitute part of this annual report on Form 10-K. Our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports are accessible free of charge at our website. The SEC also maintains an internet site that contains reports, proxy and information statements and other information regarding our filings at www.sec.gov.

 

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Item 1A. Risk Factors

 

Investing in our shares involves significant risks, including the potential loss of all or part of your investment.  These risks could materially affect our business, financial condition and results of operations and cause a decline in the market price of our shares.  You should carefully consider all of the risks described in this annual report, in addition to the other information contained in this annual report, before you make an investment in our shares.  In addition to other matters identified or described by us from time to time in filings with the SEC, there are several important factors that could cause our future results to differ materially from historical results or trends, results anticipated or planned by us, or results that are reflected from time to time in any forward-looking statement. Some of these important factors, but not necessarily all important factors, include the following:

 

Risks Related to Our Company

 

Our level of indebtedness could adversely affect our ability to raise additional capital to fund our operations, limit our ability to react to changes in the economy or our industry and prevent us from meeting our obligations under our indebtedness. As of December 31, 2014, our total outstanding debt under our convertible debentures equaled $6.84 million. We currently have a three-year senior secured term loan in an initial aggregate principal amount of $3.0 million. We also have a $2.0 million mandatory redeemable preferred stock currently valued at $1.69 million. While transactions in 2014 have significantly reduced our debt, our degree of leverage could have important consequences, including the following:

 

  it may limit our ability to obtain additional debt or equity financing for working capital, capital expenditures, further exploration, debt service requirements, acquisitions and general corporate or other purposes;
  a substantial portion of our cash flows from operations will be dedicated to the payment of principal and interest on our indebtedness and will not be available for other purposes, including our operations, capital expenditures and future business opportunities;
  the debt service requirements of other indebtedness in the future could make it more difficult for us to satisfy our financial obligations;
  as we have pledged most of our oil and natural gas properties and the related equipment, inventory, accounts and proceeds as collateral for the borrowings under our credit facility, they may not be pledged as collateral for other borrowings and would be at risk in the event of a default thereunder;
  it may limit our ability to adjust to changing market conditions and place us at a competitive disadvantage compared to our competitors that have less debt;
  we are vulnerable in the present downturn in general economic conditions and in our business, and we will likely be unable to carry out capital spending and exploration activities that are currently planned; and
  we may from time to time be out of compliance with covenants under our term loan agreements, which will require us to seek waivers from our lenders, which may be difficult to obtain.

 

We may incur additional debt, including secured indebtedness, or issue preferred stock in order to maintain adequate liquidity and develop our properties to the extent desired. A higher level of indebtedness and/or preferred stock increases the risk that we may default on our obligations. Our ability to meet our debt obligations and to reduce our level of indebtedness depends on our future performance. General economic conditions, natural gas and oil prices and financial, business and other factors affect our operations and our future performance. Many of these factors are beyond our control. Factors that will affect our ability to raise cash through an offering of our capital stock or a refinancing of our debt include financial market conditions, the value of our assets, the number of shares of capital stock we have authorized, unissued and unreserved and our performance at the time we need capital.

 

Our inability to access additional capital in significant amounts as needed, may result in our inability to develop our current prospects and properties, cause us to forfeit our interest in certain prospects and inhibit our ability to develop our business. We plan to seek to obtain additional capital through the sale of our equity or debt securities, the successful deployment of our cash on hand, bank lines of credit, joint ventures, and project financing. Consequently, there can be no assurance we will be able to obtain continued access to capital as and when needed or, if so, that the terms of any available financing will be commercially reasonable. Currently, a significant portion of our revenue after field level operating expenses is required to be paid to our lenders as debt service. If we are unable to access additional capital in significant amounts as needed, we may not be able to develop our current prospects and properties, may have to forfeit our interest in certain prospects and may not otherwise be able to develop our business. In such an event, our stock price could be materially adversely affected.

 

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We have historically incurred losses and cannot assure investors as to future profitability. We have historically incurred losses from operations during our history in the oil and natural gas business.  We had a cumulative deficit of approximately $147.82 million and $115.53 million as of December 31, 2014 and 2013, respectively.  Many of our properties are in the exploration stage, and to date we have established a limited volume of proved reserves on our properties.  Our ability to be profitable in the future will depend on successfully addressing our near-term capital need to refinance our term loan indebtedness and fund our 2015 capital budget, and implementing our acquisition, exploration, development and production activities, all of which are subject to many risks beyond our control.  Even if we become profitable on an annual basis, we cannot assure you that our profitability will be sustainable or increase on a periodic basis.

 

We will require additional capital in order to achieve commercial success and, if necessary, to finance future losses from operations as we endeavor to build revenue, but we do not have any commitments to obtain such capital and we cannot assure you that we will be able to obtain adequate capital as and when required.  The business of oil and gas acquisition, drilling and development is capital intensive and the level of operations attainable by an oil and gas company is directly linked to and limited by the amount of available capital.  We believe that our ability to achieve commercial success and our continued growth will be dependent on our continued access to capital either through the additional sale of our equity or debt securities, bank lines of credit, project financing, joint ventures, sale or lease of undeveloped acreage, or cash generated from oil and gas operations. We will seek to obtain additional capital through the sale of our equity or debt securities, the successful deployment of our cash on hand, bank lines of credit, joint ventures, and project financing.  Consequently, there can be no assurance we will be able to obtain continued access to capital as and when needed or, if so, that the terms of any available financing will be commercially reasonable.  If we are unable to access additional capital in significant amounts as needed, we may not be able to develop our current prospects and properties, may have to forfeit our interest in certain prospects and may not otherwise be able to develop our business. In such an event, our stock price could be materially adversely affected.  

 

We have limited management and staff and will be dependent upon partnering arrangements. We had three employees at the end of December 31, 2014.  Subsequent to year end, we hired Kevin Nanke as our Chief Financial Officer and Ariella Fuchs as our General Counsel. We leverage the services of independent consultants and contractors to perform various professional services, including engineering, oil and gas well planning and supervision, and land, legal, environmental and tax services. We also pursue alliances with partners in the areas of geological and geophysical services and prospect generation, evaluation and prospect leasing. Our dependence on third party consultants and service providers creates a number of risks, including but not limited to:

  the possibility that such third parties may not be available to us as and when needed; and
  the risk that we may not be able to properly control the timing and quality of work conducted with respect to our projects.

 

If we experience significant delays in obtaining the services of such third parties or poor performance by such parties, our results of operations and stock price could be materially adversely affected.

 

The loss of our Chief Executive Officer or Chief Financial Officer could adversely affect us. We are dependent on the experience of our executive officers to guide the implementation of our operational objectives and growth strategy.  The loss of the services of any of these individuals could have a negative impact on our operations and our ability to implement our strategy. Our executive employment contracts include long term incentives to retain key personnel but retention of personnel is not guaranteed.

 

Our disclosure controls and procedures and internal controls over financial reporting may not detect errors or potential acts of fraud. Our management, including our chief executive officer and chief financial officer, does not expect that our disclosure controls and procedure and internal controls will prevent all possible errors and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are being met. In addition, the design of a control system must reflect the fact that there are resource constraints, and the benefit of controls are evaluated relative to their costs. Because of the inherent limitations in all control systems, no evaluation of our controls can provide absolute assurance that all control issues and instances of fraud, if any, have been detected. The design of any system of controls is based in part upon the likelihood of future events, and there can be no assurance that any design will succeed in achieving its intended goals under all potential future conditions. Over time, a control may become inadequate because of changes in conditions, or the degree of compliance with its policies or procedures may deteriorate. Because of inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur without detection.

 

Failure to maintain an effective system of internal control over financial reporting may have an adverse effect on our stock price. Pursuant to Section 404 of the Sarbanes-Oxley Act of 2002, and the rules and regulations promulgated by the Securities and Exchange Commission, or the SEC, to implement Section 404, we are required to furnish a report by our management to include in our annual report on Form 10-K regarding the effectiveness of our internal control over financial reporting. The report includes, among other things, an assessment of the effectiveness of our internal control over financial reporting as of the end of our fiscal year, including a statement as to whether or not our internal control over financial reporting is effective. This assessment must include disclosure of any material weaknesses in our internal control over financial reporting identified by management.

 

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We may discover areas of our internal control over financial reporting which may require improvement. If we are unable to assert that our internal control over financial reporting is effective now or in any future period, or if our auditors are unable to express an opinion on the effectiveness of our internal controls, we could lose investor confidence in the accuracy and completeness of our financial reports, which could have an adverse effect on our stock price.

 

In addition to acquiring producing properties, we expect to also attempt to grow our business through the acquisition and development of exploratory oil and gas prospects, which is the riskiest method of establishing oil and gas reserves.  In addition to acquiring producing properties, we expect to acquire, drill and develop exploratory oil and gas prospects that may or may not be profitable to produce.  Developing exploratory oil and gas properties requires significant capital expenditures and involves a high degree of financial, technical and operational risk.  The budgeted costs of drilling, completing, and operating exploratory wells are often exceeded due to subsurface uncertainties and can increase significantly when market drilling costs rise.  Drilling may be unsuccessful for many reasons, including unexpected geological issues, poor reservoir quality, title problems, weather, cost overruns, equipment shortages, and operational/mechanical difficulties.  Moreover, the successful drilling or completion of an exploratory oil or gas well does not ensure a profit on investment.  Exploratory wells bear a much greater investment and operational risk than development wells.  We cannot assure you that our exploration, exploitation and development activities will result in profitable operations.  If we are unable to successfully identify, acquire and develop commercial, exploratory oil and gas prospects, our results of operations, financial condition and stock price may be materially adversely affected

 

If oil or natural gas prices decrease or exploration and development efforts are unsuccessful, wells in progress are deemed unsuccessful, or major tracts of undeveloped acreage expire, or other similar adverse events occur, we may be required to write-down the carrying value of our developed properties. 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 wells, completing productive wells, or plugging and abandoning non-productive wells, costs related to expired leases, or leases underlying  producing and non-producing wells, and overhead charges directly related to acquisition and exploration activities.  Under the full cost method of accounting, capitalized oil and natural gas property that comprise the full cost pool, 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.  This ceiling test is performed at least quarterly.  Should the capitalized costs of the full cost pool exceed this ceiling, we would recognize impairment expense.  During the year ended December 31, 2014, we did not recognize an impairment charge.  Future write-downs could occur for numerous reasons, including, but not limited to reductions in oil and gas prices that lower the estimate of future net revenues from proved oil and natural gas reserves, revisions to reserve estimates, or from the addition of non-productive capitalized costs to the full cost pool that do not result in corresponding increase in oil and gas reserves.  Impairments of undeveloped acreage and plugging and abandonment of wells in progress are other areas where costs may be capitalized into the full cost pool, without any corresponding increase in reserve values; as such, these situations could result in future additional impairment expenses.

 

If commodity prices stay at current early 2015 levels or decline further, we will incur full cost ceiling impairments in future quarters. Because the ceiling calculation uses rolling 12-month average commodity prices, the effect of lower quarter-over-quarter prices in 2015 compared to 2014 is a lower ceiling value each quarter. This will result in ongoing impairments each quarter until prices stabilize or improve. Impairment charges would not affect cash flow from operating activities, but would adversely affect our net income and stockholders’ equity.

 

Hedging transactions may limit our potential gains or result in losses. In order to manage our exposure to price risks in the marketing of our oil and natural gas, from time to time, we may enter into derivative contracts that economically hedge our oil and gas price on a portion of our production.  These contracts may limit our potential gains if oil and natural gas prices were to rise substantially over the price established by the contract.  In addition, such transactions may expose us to the risk of financial loss in certain circumstances, including instances in which: 

 

  there is a change in the expected differential between the underlying price in the hedging agreement and actual prices received;
  our production and/or sales of oil or 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 other party to the hedging contract defaults on its contract obligations.

 

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Hedging transactions we may enter into may not adequately protect us from declines in the prices of oil and natural gas.  In addition, the counterparties under our derivatives contracts may fail to fulfill their contractual obligations to us. 

 

As of December 31, 2014, we had no hedging agreements in place.

 

Our large inventory of undeveloped acreage and large percentage of undeveloped proved reserves may create additional economic risk.  Our success is largely dependent upon our ability to develop our large inventory of future drilling locations, undeveloped acreage and undeveloped reserves. As of December 31, 2014, approximately 95% of our total proved reserves and 88% of our total acreage were undeveloped.  To the extent our drilling results are not as successful as we anticipate, natural gas and oil prices decline, or sufficient funds are not available to drill these locations and reserves, we may not capture the expected or projected value of these properties. As previously disclosed, 49,000 of our 57,000 undeveloped acres are subject to lease expirations in 2015. We are currently evaluating the 2015 lease expirations to determine if this acreage is a focus for future development. If determined to be a focus for future development, we plan to re-lease if available. If not a focus, we plan to let the acreage expire. In addition, delays in the development of our reserves or increases in costs to drill and develop such reserves will reduce the economic PV-10 value of and delay cash flow from our estimated proved undeveloped reserves and future net revenues estimated for such reserves and may result in some projects becoming uneconomic.

We may have difficulty managing growth in our business, which could adversely affect our financial condition and results of operations.  Significant growth in the size and scope of our operations would place a strain on our financial, technical, operational and management resources.  The failure to continue to upgrade our technical, administrative, operating and financial staff and control systems or the occurrences of unexpected expansion difficulties, including the failure to recruit and retain experienced managers, geologists, engineers and other professionals in the oil and gas industry could have a material adverse effect on our business, financial condition and results of operations and our ability to timely execute our business plan.

The actual quantities and present value of our proved reserves may be lower than we have estimated. In addition, the present value of future net cash flow from our proved reserves will not necessarily be the same as the current market value of our estimated proved oil and natural gas reserves. This annual report contains estimates of our proved oil and natural gas reserves and the estimated future net revenues from these reserves contained in our filings with the SEC. The reserve estimate included in this annual report was prepared by our current reserve engineer consultant, reviewed by our Chief Financial Officer and Principal Accounting Officer/Controller and audited by RE Davis. The process of estimating oil and natural gas reserves is complex and requires significant decisions and assumptions in the evaluation of available geological, geophysical, engineering, cost basis, commodity pricing and economic data for each reservoir. Accordingly, these estimates are inherently imprecise. Actual future production, oil and natural gas prices, revenues, taxes, development and operating expenses, and quantities of recoverable oil and natural gas reserves most likely will vary from these estimates and vary over time. Such variations may be significant and could materially affect the estimated quantities and present value of our proved reserves. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development drilling, results of secondary and tertiary recovery applications, prevailing oil and natural gas prices and other factors, many of which are beyond our control. You should also not assume that our initial rates of production of our wells are representative of future overall production from other wells or over the life of the wells, or that early results suggesting lack of reservoir continuity will prove to be accurate.

 

You should not assume that the present value of future net cash flow referred to in this annual report is the current market value of our estimated oil and natural gas reserves.  In accordance with SEC requirements, the estimated discounted future net cash flows from proved reserves are generally based on the un-weighted average of the closing prices during the first day of each of the year preceding the end of the fiscal year.  Actual future prices and costs may be materially higher or lower than the prices and costs as of the date of the estimate.  Any change in global markets consumption by oil or natural gas purchasers or in governmental regulations or taxation will also affect actual future net cash flows.  The timing of both the production and the expenses from the development and production of our oil and natural gas properties will affect the timing of actual future net cash flows from proved reserves and their present value.  In addition, the 10% discount factor, which is required by the SEC to be used in calculating discounted future net cash flows for reporting purposes, is not necessarily the most appropriate discount factor nor does it necessarily reflect discount factors used in the marketplace to assess asset values for the purchase and sale of oil and natural gas.

 

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Properties that we acquire may not produce oil or natural gas as projected, and we may be unable to determine reserve potential, identify liabilities associated with the properties or obtain protection from sellers against them, which could cause us to incur losses.   One of our growth strategies is to pursue selective acquisitions of undeveloped acreage potentially containing oil and natural gas reserves.  If we choose to pursue an acquisition, we will perform a review of the target properties; however, these reviews are inherently incomplete as they are based on the quality, availability and interpretation of the reviewed data, the acumen and the assumptions of the evaluation personnel.  Generally, it is not feasible to review in depth every individual property, well, facility and/or file involved in each acquisition.  Even a detailed review of records and properties may not necessarily reveal existing or potential problems, nor will it permit a buyer to become sufficiently familiar with the properties to assess fully their deficiencies and potential.  We may not perform an inspection on every well, and environmental problems, such as groundwater contamination, are not necessarily observable even when an inspection is undertaken.  Even when problems are identified, we may not be able to obtain effective contractual protection against all or part of those problems, and we may assume environmental and other risks and liabilities in connection with the acquired properties.

  

All of our producing properties and operations are located in the DJ Basin region, making us vulnerable to risks associated with operating in one major geographic area.  All of our estimated proved reserves at December 31, 2014, and all of our 2014 and 2013 sales were generated in the DJ Basin in southeastern Wyoming, northeastern Colorado and southwestern Nebraska.  Although the area is a well-established oilfield infrastructure, as a result, we may be disproportionately exposed to the impact of delays or interruptions of production from these wells caused by transportation capacity constraints, curtailment of production, availability of equipment, facilities, personnel or services, significant governmental regulation, natural disasters, adverse weather conditions, plant closures for scheduled maintenance or interruption of transportation of oil or natural gas produced from the wells in this area.  In addition, the effect of fluctuations on supply and demand may become more pronounced within specific geographic oil and gas producing areas such as the DJ Basin, which may cause these conditions to occur with greater frequency or magnify the effect of these conditions.  Due to the concentrated nature of our portfolio of properties, a number of our properties could experience any of the same conditions at the same time, resulting in a relatively greater impact on our results of operations than they might have on other companies that have a more diversified portfolio of properties.  Such delays or interruptions could have a material adverse effect on our financial condition and results of operations.

 

The marketability of our production is dependent upon transportation and processing facilities over which we may have no control. The marketability of our production depends in part upon the availability, proximity and capacity of pipelines, natural gas gathering systems, rail service, and processing facilities in addition to competing oil and gas production available to 3rd party purchasers. We deliver crude oil and natural gas produced from these areas through trucking, gathering systems and pipelines, some of which we do not own. The lack of availability of capacity on third-party systems and facilities could reduce the price offered for our production or result in the shut-in of producing wells or the delay or discontinuance of development plans for properties. Although we have some contractual control over the transportation of our production through firm transportation arrangements, third-party systems and facilities may be temporarily unavailable due to market conditions or mechanical reliability or other reasons, including adverse weather conditions or work-loads. Activist or other efforts may delay or halt the construction of additional pipelines or facilities. Third-party systems and facilities may not be available to us in the future at a price that is acceptable to us. Any significant change in market factors or other conditions affecting these infrastructure systems and facilities, as well as any delays in constructing new infrastructure systems and facilities, could delay production, thereby harming our business and, in turn, our results of operations, cash flows, and financial condition.

 

Our ability to produce crude oil and natural gas economically and in commercial quantities could be impaired if we are unable to acquire adequate supplies of water for our drilling and completion operations. Drilling and completion activities require the use of water. For example, the hydraulic fracturing process requires the use and disposal of significant quantities of water. In certain areas, there may be insufficient local aquifer capacity to provide a source of water for drilling activities. Water must be obtained from other sources and transported to the drilling site. Our inability to secure sufficient amounts of water, or to dispose of or recycle the water used in our operations, could adversely impact our operations in certain areas.

 

Our success is influenced by oil, natural gas, and NGL prices in the specific areas where we operate, and these prices may be lower than prices at major markets.  Regional natural gas, condensate, oil and NGLs prices may move independently of broad industry price trends. Because some of our operations are located outside major markets, we are directly impacted by regional prices regardless of Henry Hub, WTI or other major market pricing.

 

Unless we find new oil and gas reserves to replace actual production, our reserves and production will decline, which would materially and adversely affect our business, financial condition and results of operations. Producing oil and gas reservoirs generally are characterized by declining production rates and depletion that vary depending upon reservoir characteristics subsurface and surface pressures and other factors. Thus, our future oil and gas reserves and production and, therefore, our cash flow and revenue are highly dependent on our success in efficiently obtaining additional reserves. We may not be able to develop, find or acquire reserves to replace our current and future production at costs or other terms acceptable to us, or at all, in which case our business, financial condition and results of operations would be materially and adversely affected.

 

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Part of our strategy involves drilling in existing or emerging unconventional shale plays using available horizontal drilling and completion techniques. The results of our planned exploratory and development drilling in these plays are subject to drilling and completion execution risks and drilling results may not meet our economic expectations for reserves or production. As a result, we may incur material write-downs and the value of our undeveloped acreage could decline if drilling results are unsuccessful.  Unconventional operations involve utilizing drilling and completion techniques as developed by ourselves and our service providers.  Risks that we face while drilling include, but are not limited to, not reaching the desired objective due to drilling problems, not landing our wellbore in the desired drilling zone or specific target, staying in the desired drilling zone while drilling horizontally through the formation, running our casing the entire length of the wellbore and being able to run tools and other equipment consistently through the horizontal wellbore.  Risks that we face while completing our wells include, but are not limited to, mechanical integrity, being able to fracture stimulate the planned number of stages, being able to run tools the entire length of the wellbore during completion operations, proper design and engineering vs. reservoir parameters, and successfully cleaning out the wellbore after completion of the final fracture stimulation stage.

 

Our experience with horizontal well applications utilizing the latest drilling and completion techniques specifically in the Niobrara and/or Codell formations is limited; however, we contract local experts in the area to design, plan and conduct our drilling and completion operations.  Ultimately, the success of these drilling and completion techniques can only be developed over time as more wells are drilled and production profiles are established over a sufficiently long time period. If our drilling results are less than anticipated or we are unable to execute our drilling program because of capital constraints, lease expirations, access to gathering systems and limited takeaway capacity or otherwise, and/or natural gas and oil prices decline, the return on our investment in these areas may not be as attractive as we anticipate and we could incur material write-downs of undeveloped properties and the value of our undeveloped acreage could decline in the future.

 

The unavailability or high cost of drilling rigs, equipment supplies or personnel could adversely affect our ability to execute our exploration and development plans.  The oil and gas industry is cyclical and, from time to time, there are shortages of drilling rigs, equipment, supplies or qualified personnel.  During these periods, the costs of and demand for rigs, equipment and supplies may increase substantially and their availability may be limited.  In addition, the demand for, and wage rates of, qualified personnel, including drilling rig crews, may rise as the number of rigs in service increases.  The higher prices of oil and gas during the last several years have increased activity which has resulted in shortages of drilling rigs, equipment and personnel, which have resulted in increased costs and delays in the areas where we operate. If drilling rigs, equipment, supplies or qualified personnel are unavailable to us due to excessive costs or demand or otherwise, our ability to execute our exploration and development plans could be materially and adversely affected and, as a result, our financial condition and results of operations could be materially and adversely affected.

 

Covenants in our Credit Agreement impose significant restrictions and requirements on us.  Our Credit Agreement contains a number of covenants imposing significant restrictions on us, including the maximum monthly payment requirement, restrictions on our repurchase of, and payment of dividends on, our capital stock and limitations on our ability to incur additional indebtedness, make investments, engage in transactions with affiliates, sell assets and create liens on our assets. These restrictions may affect our ability to operate our business, to take advantage of potential business opportunities as they arise and, in turn, may materially and adversely affect our business, financial conditions and results of operations.

 

We could be required to pay liquidated damages to some of our investors due to our failure to maintain the effectiveness of a prior registration statement.  We could accrue liquidated damages under registration rights agreements covering a significant amount of shares of Common Stock if our investors declare a default, due to our failure to maintain the effectiveness of a prior registration statement as required in the agreements.  In such case, we would be required to pay monthly liquidated damages. If we do not make a monthly payment within seven days after the date payable, we are required to pay interest at an annual rate of 18% on the unpaid amount. If our investors declare a default under the registration rights agreement and accrue liquidated damages, we could be required to either raise additional outside funds through financing or curtail operations.

 

We are exposed to operating hazards and uninsured risks.  Our operations are subject to the risks inherent in the oil and natural gas industry, including the risks of:

 

  fire, explosions and blowouts;
  negligence of personnel,
  Weather
  pipe or equipment failure;
  abnormally pressured formations; and
  environmental accidents such as oil spills, natural gas leaks, ruptures or discharges of toxic gases, brine or well fluids into the environment (including groundwater contamination).

 

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These events may result in substantial losses to us from: 

 

  injury or loss of life;
  significantly increased costs;
  severe damage to or destruction of property, natural resources and equipment;
  pollution or other environmental damage;
  clean-up responsibilities;
  regulatory investigation;
  penalties and suspension of operations; or
  attorney's fees and other expenses incurred in the prosecution or defense of litigation.

 

We maintain insurance against some, but not all, of these risks.  We cannot assure you that our insurance will be adequate to cover these losses or liabilities.  We do not carry business interruption insurance. Losses and liabilities arising from uninsured or underinsured events may have a material adverse effect on our financial condition and operations.

  

The producing wells in which we have an interest occasionally experience reduced or terminated production.  These curtailments can result from mechanical failures, contract terms, pipeline and processing plant interruptions, market conditions,  operator priorities, and weather conditions, etc. and weather conditions.  These curtailments can last from a few days to many months.

 

Failure to adequately protect critical data and technology systems could materially affect our operations. Information technology solution failures, network disruptions and breaches of data security could disrupt our operations by causing delays or cancellation of customer orders, impeding processing of transactions and reporting financial results, resulting in the unintentional disclosure of customer, employee or our information, or damage to our reputation. There can be no assurance that a system failure or data security breach will not have a material adverse effect on our financial condition, results of operations or cash flows.

 

We may be subject to risks in connection with acquisitions, and the integration of significant acquisitions may be difficult.  We periodically evaluate acquisitions of reserves, properties, prospects and leaseholds and other strategic transactions that appear to fit within our overall business strategy.  The successful acquisition of producing properties requires an assessment of several factors, including:

 

  recoverable reserves;
  future oil and natural gas prices and their appropriate differentials;
  well and facility integrity;
  development and operating costs;
  regulatory constraints and plans; and
  potential environmental and other liabilities.

 

The accuracy of these assessments is inherently uncertain.  In connection with these assessments, we perform a review of the subject properties.  Our review will not reveal all existing or potential problems nor will it permit us to become sufficiently familiar with the properties to fully assess their deficiencies and potential recoverable reserves. Inspections may not always be performed on every well, and environmental problems are not necessarily observable even when an inspection is undertaken.  Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of the problems.  We often are not entitled to contractual indemnification for environmental liabilities and acquire properties on an "as is" basis.

 

Significant acquisitions and other strategic transactions may involve other risks, including:

 

  diversion of our management's attention to evaluating, negotiating and integrating significant acquisitions and strategic transactions;
  challenge and cost of integrating acquired operations, information management and other technology systems and business cultures with those of ours while carrying on our ongoing business;
  difficulty associated with coordinating geographically separate organizations;
  challenge of attracting and retaining capable personnel associated with acquired operations; and
  failure to realize the full benefit that we expect in estimated proved reserves, production volume, cost savings from operating synergies or other benefits anticipated from an acquisition, or to realize these benefits within the expected time frame.

 

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The process of integrating operations could cause an interruption of, or loss of momentum in, the activities of our business.  Members of our senior management and other staff may be required to devote considerable amounts of time to this integration process, which will decrease the time they will have to manage our business.   If our senior management and staff are not able to effectively manage the integration process, or if any significant business activities are interrupted as a result of the integration process, our business could suffer.

 

Prospects in which we decide to participate may not yield oil or natural gas in commercially viable quantities or quantities sufficient to meet our targeted rate of return.  A prospect is a property in which we own an interest and contains what we believe, based on available reservoir, seismic and/or geological information, to be indications of commercial oil or natural gas.  Our prospects are in various stages of evaluation, ranging from a prospect that is ready to be drilled to a prospect that will require substantial additional technical assessment, data acquisition and/or seismic data processing and interpretation.  There is no definitive method to predict in advance of drilling and testing and wider-scale development whether any particular prospect will yield oil or natural gas in sufficient quantities to be economically viable.  The use of reservoir, geologic and seismic data and other technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling whether oil or natural gas will be present or, if present, whether oil or natural gas will be present in commercial quantities.  We cannot assure you that the analysis we perform using data from other wells, more fully explored prospects or producing fields will be useful in predicting the characteristics and potential reserves associated with our drilling prospects.

 

Our reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in our reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves. The process of estimating oil and natural gas reserves is complex.  It requires interpretations of available technical data and many assumptions, including assumptions ranging from subsurface parameters to economic/market factors. Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities and the calculation of the present value of reserves shown in these reports.

 

In order to prepare reserve estimates in its reports, our independent petroleum consultant projected production rates and timing of development expenditures.  Our independent petroleum consultant also analyzed available geological, geophysical, production and engineering data.  The extent, quality and reliability of this data can vary and may not be in our control.  The process also requires economic assumptions about matters such as oil and natural gas prices, drilling and operating expenses, capital expenditures, infrastructure, taxes and availability of funds.  Therefore, estimates of oil and natural gas reserves are inherently imprecise.

 

Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves will most likely vary from our estimates.  Any significant variance could materially affect the estimated quantities and present value of our reserves.  In addition, our independent petroleum consultant may adjust estimates of proved reserves to reflect production history, drilling results, prevailing oil and natural gas prices and other factors, many of which are beyond our control due in-part to SEC guidelines. 

 

Risks Relating to the Oil and Gas Industry

 

Oil and natural gas prices are highly volatile, and our revenue, profitability, cash flow, future growth and ability to borrow funds or obtain additional capital, as well as the carrying value of our properties, are substantially dependent on prevailing prices of oil and natural gas.  Historically, the markets for oil and natural gas have been volatile.  These markets will likely continue to be volatile in the future.  The prices we receive for our production and the levels of our production depend on numerous factors beyond our control. These factors include the following: 

 

  changes in global supply and demand for oil and natural gas;
  the actions of the Organization of Petroleum Exporting Countries (“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;
  the price and availability of alternative fuels; and
  market concerns about global warming or changes in governmental policies and regulations due to climate change initiatives.

 

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Volatile oil and natural gas prices make it difficult to estimate the value of producing properties for acquisition and often cause disruption in the market for oil and natural gas producing properties, as buyers and sellers have difficulty agreeing on such value.  Price volatility also makes it difficult to budget for and project the return on acquisitions and development and exploitation projects.

 

Our revenues, operating results, profitability and future rate of growth depend primarily upon the prices we receive for oil and, to a lesser extent, natural gas that we sell.  Prices also affect the amount of cash flow available for capital expenditures and our ability to borrow money or raise additional capital.  In addition, we may need to record asset carrying value write-downs if prices fall.  A significant decline in the prices of natural gas or oil could adversely affect our financial position, financial results, cash flows, access to capital and ability to grow.

 

Our industry is highly competitive, which may adversely affect our performance, including our ability to participate in ready to drill prospects in our core areas.  We operate in a highly competitive environment. In addition to capital, the principle resources necessary for the exploration and production of oil and natural gas are: 

 

  leasehold prospects under which oil and natural gas reserves may be discovered;
  drilling rigs and related equipment to explore for such reserves; and
  knowledgeable personnel to conduct all phases of oil and natural gas operations.

 

We must compete for such resources with both major oil and natural gas companies and independent operators. Virtually all of these competitors have financial and other resources substantially greater than ours.  We cannot assure you that such capital, materials and resources will be available when needed.  If we are unable to access capital, material and resources when needed, we risk suffering a number of adverse consequences, including:

  

  the breach of our obligations under the oil and gas leases by which we hold our prospects and the potential loss of those leasehold interests;
  loss of reputation in the oil and gas community;
  inability to retain staff;
  inability to attract capital;
  a general slowdown in our operations and decline in revenue; and
  decline in market price of our common shares.

 

We may face difficulties in securing and operating under authorizations and permits to drill, complete or operate our wells. The recent growth in oil and gas exploration in the United States has drawn intense scrutiny from environmental and community interest groups, regulatory agencies and other governmental entities. As a result, we may face significant opposition to, or increased regulation of, our operations that may make it difficult or impossible to obtain permits and other needed authorizations to drill, complete or operate, result in operational delays, or otherwise make oil and gas exploration more costly or difficult than in other countries.

 

Legislative and regulatory initiatives related to global warming and climate change could have an adverse effect on our operations and the demand for oil and natural gas.   In December 2009, the EPA determined that emissions of carbon dioxide, methane and other “greenhouse gases” present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes.  Based on these findings, the EPA has begun adopting and implementing regulations to restrict emissions of greenhouse gases under existing provisions of the CAA.  The EPA recently adopted two sets of rules regulating greenhouse gas emissions under the CAA, one of which requires a reduction in emissions of greenhouse gases from motor vehicles and the other of which regulates emissions of greenhouse gases from certain large stationary sources.  The EPA has also adopted rules requiring the reporting of greenhouse gas emissions from specified large greenhouse gas emission sources in the United States on an annual basis, including petroleum refineries, as well as certain onshore oil and natural gas production facilities.

 

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EPA is also considering direct regulation of methane emissions from oil and gas facilities. On January 14, 2015, the White House and EPA indicated that they plan to amend 40 C.F.R Part 60, Subpart OOOO (Subpart OOOO) standards to achieve additional methane and volatile organic compound reductions from the oil and natural gas industry. These potential amendments to Subpart OOOO could result in additional regulatory requirements and standards for completions of hydraulically fractured oil wells, pneumatic pumps, and leaks from new and modified oil and gas exploration, production, and gathering facilities. A proposed rule is expected in 2015, with a final rule expected in 2016.

 

In June 2014, the United States Supreme Court’s holding in Utility Air Regulatory Group v. EPA upheld a portion of EPA’s GHG stationary source permitting program, but also invalidated a portion of it. The Court held that stationary sources already subject to the Prevention of Significant Deterioration (“PSD”) or Title V permitting programs for non-GHG criteria pollutants remain subject to GHG Best Available Control Technology (“BACT”) and major source permitting requirements, but ruled that sources cannot be subject to the PSD or Title V major source permitting programs based solely on GHG emission levels. Upon remand, EPA is considering how to implement the Court’s decision. The Court’s holding does not prevent states from considering and adopting state-only major source permitting requirements based solely on GHG emission levels.

 

In addition, the United States Congress has from time to time considered adopting legislation to reduce emissions of greenhouse gases and almost one-half of the states have already taken legal measures to reduce emissions of greenhouse gases, primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs.  Most of these cap and trade programs work by requiring major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and gas processing plants, to acquire and surrender emission allowances.  The number of allowances available for purchase is reduced each year in an effort to achieve the overall greenhouse gas emission reduction goal.

 

The adoption of legislation or regulatory programs to reduce emissions of greenhouse gases could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or comply with new regulatory or reporting requirements.  Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, the oil, NGLs, and natural gas we produce.  Consequently, legislation and regulatory programs to reduce emissions of greenhouse gases could have an adverse effect on our business, financial condition and results of operations.  Finally, it should be noted that some scientists have concluded that increasing concentrations of greenhouse gases in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climatic events.  If any such effects were to occur, they could have an adverse effect on our financial condition and results of operations.

 

Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays in the completion of oil and natural gas wells.

 

Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas and/or oil from dense subsurface rock formations.  The process involves the injection of water, sand and chemicals under pressure into the formation to fracture the surrounding rock and stimulate production by providing and linking up induced flow paths for the oil and/or gas contained in the rocks.  We routinely use hydraulic fracturing techniques in many of our drilling and completion programs.  The process is typically regulated by state oil and natural gas commissions, but the EPA has asserted federal regulatory authority over certain hydraulic fracturing activities involving diesel fuel under the federal Safe Drinking Water Act.  In addition, legislation has been introduced before Congress to provide for federal regulation of hydraulic fracturing under the Safe Drinking Water Act and to require disclosure of the chemicals used in the hydraulic fracturing process.  Under the proposed legislation, this information would be available to the public via the internet, which could make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater.   As discussed above, the BLM, on March 20, 2015, issued its final regulations for hydraulic fracturing on federal and tribal lands. The new regulations require, among other things, disclosure of chemicals, annulus pressure monitoring, flow back and produced water management and storage, and more stringent well integrity measures associated with hydraulic fracturing operations on public land. The new regulations become effective on June 24, 2015. In addition, EPA intends to propose regulations in 2015 under the federal Clean Water Act to develop standards for wastewater discharges from hydraulic fracturing and other natural gas production activities. At the state level, some states have adopted, and other states are considering adopting legal requirements that could impose more stringent permitting, public disclosure or well construction requirements on hydraulic fracturing activities.  Some counties in Colorado, for instance, have amended their land use regulations to impose new requirements on oil and gas development, while other local governments have entered memoranda of agreement with oil and gas producers to accomplish the same objective. Beyond that, in 2012, Longmont, Colorado prohibited the use of hydraulic fracturing. The oil and gas industry filed a lawsuit challenging that ban in court. The industry prevailed on summary judgment against Longmont and the environmental intervenors. That decision is currently on appeal. In November 2013, four other Colorado cities and counties passed voter initiatives either placing a moratorium on hydraulic fracturing or banning new oil and gas development. These initiatives too are the subject of pending legal challenge or appeal. While these initiatives cover areas with little recent or ongoing oil and gas development, they could lead opponents of hydraulic fracturing to push for statewide referendums, especially in Colorado. If new or more stringent federal, state, or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from drilling wells.

 

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The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices and a committee of the U.S. House of Representatives has conducted an investigation of hydraulic fracturing practices. Furthermore, a number of federal agencies are analyzing, or have been requested to review, environmental issues associated with hydraulic fracturing. The EPA has commenced a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater, with draft results expected by 2015.. These ongoing studies, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the Safe Drinking Water Act or other regulatory mechanisms.

 

EPA has also issued an advance notice of proposed rulemaking and initiated a public participation process under the Toxic Substances Control Act (“TSCA”) to seek comment on the information that should be reported or disclosed for hydraulic fracturing chemical substances and mixtures and the mechanisms for obtaining this information. Additionally, on January 7, 2015, several national environmental advocacy groups filed a lawsuit requesting that EPA add the oil and gas extraction industry to the list of industries required to report releases of certain “toxic chemicals” under the Emergency Planning and Community Right-to-Know Act’s (“EPCRA”) Toxics Release Inventory (“TRI”) program. 

 

We are subject to numerous laws and regulations that can adversely affect the cost, manner or feasibility of doing business.  Our operations are subject to extensive federal, state and local laws and regulations relating to the exploration, production and sale of oil and natural gas, and operating safety.  Future laws or regulations, any adverse change in the interpretation of existing laws and regulations or our failure to comply with existing legal requirements may result in substantial penalties and harm to our business, results of operations and financial condition.  We may be required to make large and unanticipated capital expenditures to comply with governmental regulations, such as: 

 

  land use restrictions;
  lease permit restrictions;
  drilling bonds and other financial responsibility requirements, such as plugging and abandonment bonds;
  spacing of wells;
  unitization and pooling of properties;
  safety precautions;
  operational reporting; and
  taxation.

 

Under these laws and regulations, we could be liable for:

 

  personal injuries;
  property and natural resource damages;
  well reclamation cost; and
  governmental sanctions, such as fines and penalties.

 

Our operations could be significantly delayed or curtailed and our cost of operations could significantly increase as a result of regulatory requirements or restrictions.  We are unable to predict the ultimate cost of compliance with these requirements or their effect on our operations.  It is also possible that a portion of our oil and gas properties could be subject to eminent domain proceedings or other government takings for which we may not be adequately compensated. See “Business and Properties—Government Regulations” for a more detailed description of our regulatory risks.

  

Our operations may incur substantial expenses and resulting liabilities from compliance with environmental laws and regulations.  Our oil and natural gas operations are subject to stringent federal, state and local laws and regulations relating to the release or disposal of materials into the environment or otherwise relating to environmental protection. These laws and regulations: 

 

  require the acquisition of a permit before drilling  or facility mobilization and commissioning, or injection or disposal commences;

 

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  restrict the types, quantities and concentration of substances that can be released into the environment in connection with drilling and production and processing activities, including new environmental regulations governing the withdrawal, storage and use of surface water or groundwater necessary for hydraulic fracturing of wells;
  limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas; and
  impose substantial liabilities for pollution resulting from our operations.

 

Failure to comply with these laws and regulations may result in:

 

  the assessment of administrative, civil and criminal penalties;
  incurrence of investigatory or remedial obligations; and
  the imposition of injunctive relief.

 

Changes in environmental laws and regulations occur frequently and any changes that result in more stringent or costly waste handling, storage, transport, disposal or cleanup requirements could require us to make significant expenditures to reach and maintain compliance and may otherwise have a material adverse effect on our industry in general and on our own results of operations, competitive position or financial condition.  Under these environmental laws and regulations, we could be held strictly liable for the removal or remediation of previously released materials or property contamination regardless of whether we were responsible for the release or contamination or if our operations met previous standards in the industry at the time they were performed.  Our permits require that we report any incidents that cause or could cause environmental damages. See “Business and Properties—Government Regulations” for a more detailed description of our environmental risks.

 

Risks Relating to Our Common Stock

 

There is a limited public market for our shares and we cannot assure you that an active trading market or a specific share price will be established or maintained. Our Common Stock trades on the Nasdaq Global Market, generally in small volumes each day.  The value of our Common Stock could be affected by:

 

  actual or anticipated variations in our operating results;
  changes in the market valuations of other oil and gas companies;
  announcements by us or our competitors of significant acquisitions, strategic partnerships, joint ventures or capital commitments;
  adoption of new accounting standards affecting our industry;
  additions or departures of key personnel;
  sales of our Common Stock or other securities in the open market;
  actions taken by our lenders or the holders of our convertible debentures;
  changes in financial estimates by securities analysts;
  conditions or trends in the market in which we operate;
  changes in earnings estimates and recommendations by financial analysts;
  our failure to meet financial analysts’ performance expectations; and
  other events or factors, many of which are beyond our control.

 

In a volatile market, you may experience wide fluctuations in the market price of our Common Stock.  These fluctuations may have an extremely negative effect on the market price of our Common Stock and may prevent you from obtaining a market price equal to your purchase price when you attempt to sell our Common Stock in the open market.  In these situations, you may be required either to sell at a market price which is lower than your purchase price, or to hold our Common Stock for a longer period of time than you planned.  An inactive market may also impair our ability to raise capital by selling shares of capital stock and may impair our ability to acquire other companies or oil and gas properties by using Common Stock as consideration.

 

We may not satisfy the NASDAQ Capital Market’s requirements for continued listing. If we cannot satisfy these requirements, NASDAQ could delist our Common Stock. Our Common Stock is listed on the NASDAQ Capital Market, under the symbol LLEX. To continue to be listed on NASDAQ, we are required to satisfy a number of conditions. In past years, we defaulted on several of these requirements and regained compliance only after we carried out capital-raising and other transactions. We cannot assure you that we will be able to satisfy the NASDAQ listing requirements in the future. If we are delisted from NASDAQ, trading in our Common Stock may be conducted, if available, on the “OTC Bulletin Board Service” or, if available, via another market. In the event of such delisting, an investor would likely find it significantly more difficult to dispose of, or to obtain accurate quotations as to the value of our Common Stock, and our ability to raise future capital through the sale of our Common Stock or other securities convertible into our Common Stock could be severely limited. In addition, if our Common Stock were delisted from NASDAQ, our Common Stock could be considered a “penny stock” under the U.S. federal securities laws. Additional regulatory requirements apply to trading by broker-dealers of penny stocks that could result in the loss of an effective trading market for our Common Stock.

 

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Our Common Stock may be subject to penny stock rules which limit the market for our Common Stock.  The SEC has adopted Rule 15g-9 which establishes the definition of a “penny stock,” for the purposes relevant to us, as any equity security that has a market price of less than $5.00 per share or with an exercise price of less than $5.00 per share, subject to certain exceptions. For any transaction involving a penny stock, unless exempt, the rules require:

 

  that a broker or dealer approve a person’s account for transactions in penny stocks; and
  that broker or dealer receives from the investor a written agreement to the transaction, setting forth the identity and quantity of the penny stock to be purchased.

 

In order to approve a person’s account for transactions in penny stocks, the broker or dealer must:

 

  obtain financial information and investment experience objectives of the person; and
  make a reasonable determination that the transactions in penny stocks are suitable for that person and the person has sufficient knowledge and experience in financial matters to be capable of evaluating the risks of transactions in penny stocks.

 

The broker or dealer must also deliver, prior to any transaction in a penny stock, a disclosure schedule prescribed by the SEC relating to the penny stock market, which, in highlight form:

 

  sets forth the basis on which the broker or dealer made the suitability determination; and
  that the broker or dealer received a signed, written agreement from the investor prior to the transaction.

 

Disclosure also has to be made about the risks of investing in penny stocks in both public offerings and in secondary trading and about the commissions payable to both the broker-dealer and the registered representative, current quotations for the securities and the rights and remedies available to an investor in cases of fraud in penny stock transactions. Finally, monthly statements have to be sent disclosing recent price information for the penny stock held in the account and information on the limited market in penny stocks.

 

Generally, brokers may be less willing to execute transactions in securities subject to the “penny stock” rules. This may make it more difficult for investors to dispose of our Common Stock and cause a decline in the market value of our stock.

 

Sales of a substantial number of shares of our Common Stock, or the perception that such sales might occur, could have an adverse effect on the price of our Common Stock. As of December 31, 2014, six investors each hold more than 5% beneficial ownership of our Common Stock, and together, hold beneficial ownership of approximately 75% of our Common Stock. Thus, any sales by our large investors of a substantial number of shares of our Common Stock into the public market, or the perception that such sales might occur, could have an adverse effect on the price of our Common Stock.

 

We may issue shares of preferred stock with greater rights than our Common Stock. Our articles of incorporation authorize our board of directors to issue one or more series of preferred stock and set the terms of the preferred stock without seeking any further approval from our stockholders. Any preferred stock that is issued may rank ahead of our Common Stock, in terms of dividends, liquidation rights and voting rights. We currently have two series of preferred stock issued and outstanding, both of which provide its holders with a liquidation preference and prohibit the payment of dividends on junior securities, including our Common Stock, amongst other preferences and rights.

 

There may be future dilution of our Common Stock. If we sell additional equity or convertible debt securities, such sales could result in increased dilution to our existing stockholders and cause the price of our outstanding securities to decline. To the extent outstanding warrants or options to purchase Common Stock under our employee and director stock option plans are exercised, the price vesting triggers under the performance shares granted to our executive officers are satisfied, or additional shares of restricted stock are issued to our employees, holders of our Common Stock will experience dilution.

 

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We do not expect to pay dividends on our Common Stock. We have never paid dividends with respect to our Common Stock, and we do not expect to pay any dividends, in cash or otherwise, in the foreseeable future. We intend to retain any earnings for use in our business. In addition, the credit agreement relating to our credit facility prohibits us from paying any dividends and the indenture governing our senior notes restricts our ability to pay dividends. In the future, we may agree to further restrictions.

 

Our Common Stock is an unsecured equity interest in our Company. As an equity interest, our Common Stock is not secured by any of our assets. Therefore, in the event we are liquidated, the holders of the Common Stock will receive a distribution only after all of our secured and unsecured creditors have been paid in full. There can be no assurance that we will have sufficient assets after paying our secured and unsecured creditors to make any distribution to the holders of the Common Stock.

 

Securities analysts may not initiate coverage of our shares or may issue negative reports, which may adversely affect the trading price of the shares. We cannot assure you that securities analysts will cover our company. If securities analysts do not cover our company, this lack of coverage may adversely affect the trading price of our shares. The trading market for our shares will rely in part on the research and reports that securities analysts publish about us and our business.  If one or more of the analysts who cover our company downgrades our shares, the trading price of our shares may decline. If one or more of these analysts ceases to cover our company, we could lose visibility in the market, which, in turn, could also cause the trading price of our shares to decline.  Further, because of our small market capitalization, it may be difficult for us to attract securities analysts to cover our company, which could significantly and adversely affect the trading price of our shares.

 

Item 1B. Unresolved Staff Comments

 

Not applicable.

 

Item 3. 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. 13-011301 EEB) against the Company and Roger Parker in connection with the personal bankruptcy proceedings of Roger Parker, alleging that the Company improperly failed to remit to Tracinda certain property in connection with a writs of garnishment issued by the Denver District Court (discussed above). The Company filed an answer to this complaint on July 10, 2013. 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.

 

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Lilis Energy, Inc. v. Great Western Operating Company LLC, Eighth Judicial District Court for Clark County, Nevada, Case No. A-15-714879-B. On March 6, 2015, the Company filed a lawsuit against the operator.  The dispute relates to the Company’s interest in certain producing wells and the well operator’s assertion that the Company’s interest was reduced and/or eliminated as a result of a default or a farm-out agreement. Underlying the dispute is the JOA which provides the parties with various rights and obligations. In its complaint, the Company seeks monetary damages and declaratory relief on claims of breach of contract, breach of the implied covenant of good faith and fair dealing, tortious breach of the implied covenant of good faith and fair dealing, unjust enrichment, conversion and declaratory judgment related to the JOA. The operator has not yet responded to the complaint.

 

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.

 

Item 4. MINE SAFETY DISCLOSURES

 

Not applicable.

 

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Part II

 

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

 

Recent Market Prices

 

On November 2, 2011 our Common Stock began trading on the Nasdaq Global Market under the symbol "RECV."  Between September 25, 2009 and November 1, 2011 our stock traded on the OTC Bulletin Board under the symbol "RECV.OB." On December 1, 2013, in connection with our name changes our Common Stock began trading on the Nasdaq Global Market under the symbol "LLEX." 

 

The following table shows the high and low reported sales prices of our Common Stock for the periods indicated. 

 

   High   Low 
   2014 
         
Fourth Quarter  $2.20   $0.62 
Third Quarter  $2.48   $1.02 
Second Quarter  $3.30   $1.73 
First Quarter  $3.58   $2.06 

 

   2013 
         
Fourth Quarter  $2.74   $1.64 
Third Quarter  $2.55   $1.42 
Second Quarter  $1.88   $1.34 
First Quarter  $2.35   $1.52 

 

On April 13, 2015, there were approximately 84 owners of record of our Common Stock.

 

Dividend Policy

 

We have never paid any cash dividends on our Common Stock and do not anticipate paying any dividends in the foreseeable future. Our current business plan is to retain any future earnings to finance the expansion and development of our business.  Any future determination to pay cash dividends will be at the discretion of our Board, and will be dependent upon our financial condition, results of operations, capital requirements and other factors as our board may deem relevant at that time.

 

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. 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.

 

Furthermore, the terms of the Debentures provide that at any time when the Debentures remain outstanding, the Company shall not pay cash dividends or distributions on any equity securities of the Company without the consent of holders of at least 67% in principal amount of the then outstanding Debentures.

 

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Restrictions under the Credit Agreement

 

As discussed above, on January 8, 2015 we entered into the Credit Agreement with Heartland Bank. Pursuant to the Credit Agreement, we’re subject to certain customary working capital restrictions and limitations upon the payment of dividends. For example, we’re 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 as Exhibit 10.1 to our Current Report on Form 8-K, filed on January 13, 2015.

 

In addition, the terms of some of our outstanding warrants prohibit or restrict the payment of dividends.

 

Recent Sales of Unregistered Securities

 

We have previously disclosed by way of quarterly reports on Form 10-Q and current reports on Form 8-K filed with the SEC all sales by us of our unregistered securities during 2014.

 

Item 6. Selected Financial Data

 

Not applicable.  

 

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

 

The following discussion should be read in conjunction with our financial statements included in Part IV of this annual report. 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 Part I “Item 1A. Risk Factors.”

 

General

 

Lilis Energy, Inc. (NASDAQ: LLEX) (“we,” “us,” “our,” “Lilis Energy,” “Lilis,” or the “Company”) is a Denver-based upstream independent oil and gas company engaged in the acquisition, drilling and production of oil and natural gas properties and prospects.  We were incorporated in August of 2007 in the State of Nevada as Universal Holdings, Inc.  In October 2009, we changed our name to Recovery Energy, Inc. and in December 2013, we changed our name to Lilis Energy, Inc.

 

Our current operating activities are focused on the Denver-Julesburg Basin (“DJ Basin”) in Colorado, Wyoming and Nebraska.  Our business strategy is designed to maximize shareholder value by leveraging the knowledge, expertise and experience of our management team and via the future exploration and development of the approximately 65,000 net acres of developed and undeveloped acreage that are currently held by us, primarily in the northern DJ Basin.

 

Overview of 2014 and Recent Developments

 

January 2014 Private Placement

 

On January 22, 2014, we entered into and closed a series of subscription agreements with accredited investors in a private placement transaction, pursuant to which we issued an aggregate of 2,959,125 units, with each unit consisting of (i) one share of our common stock, par value $0.0001 (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 $5.92 million (the “January Private Placement”).  In conjunction with the January Private Placement, certain of our current and former officers and directors agreed to purchase an additional $1.425 million of Units subject to receipt of shareholder approval as required by NASDAQ’s continued listing requirements. However, due to attrition of certain parties who entered into those commitments, we do not expect to collect on the full amount. The warrants issued in the private placement were not exercisable for six months following the closing of the January Private Placement.

 

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May 2014 Private Placement

 

On May 30, 2014, we closed a private placement (the “May Private Placement”) of our Series A 8% Convertible Preferred Stock (“Preferred Stock”) with accredited investors, pursuant to which we issued $7.50 million of Preferred Stock. The Preferred Stock provides for a dividend of 8% per annum, payable quarterly in arrears, which can be paid in cash or in shares of Common Stock if certain conditions are met. Each investor in the Preferred Stock was also granted a three-year warrant to purchase Common Stock equal to 50% of the number of shares that would be issuable upon full conversion of the Preferred Stock at the initial conversion price of $2.89. We have the right to convert the Preferred Stock to Common Stock if the Common Stock is traded at $7.50 per share for ten consecutive trading days and the underlying shares of Common Stock are registered for resale. T.R. Winston & Company, LLC (“TR Winston”) was the placement agent for the transaction and was paid a fee equal to 8% of the proceeds plus an additional 1% of the proceeds plus $25,000 in expenses. Of the $600,000 fee, the placement agent paid $94,150 in commissions to selected dealers and invested $454,000, or 76%, in the May Private Placement for its own account. The Company used $5.0 million of the proceeds of the May Private Placement to make the first cash payment in connection with the Hexagon settlement (discussed below), and used the remaining proceeds to fund its oil and gas development projects and for general administrative expenses.

 

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

 

Debenture Conversion and Extension

 

On January 31, 2014, we entered into a Debenture Conversion Agreement (the “Conversion Agreement”), with all of the holders of our 8% Senior Secured Convertible Debentures (the “Debentures”). Under the terms of the Conversion Agreement, $9.0 million of the approximately $15.6 million in Debentures then outstanding immediately converted to Common Stock at a price of $2.00 per share of Common Stock. The balance of the Debentures may be converted to Common Stock at the election of its holders, subject to receipt of shareholder approval as required by the NASDAQ continued listing requirements. As additional inducement for the conversions, we issued to the converting Debenture holders warrants to purchase one share of Common Stock, at an exercise price equal to $2.50 per share, for each share of Common Stock issued upon conversion of the Debentures.

 

At December 31, 2014, we had $6.84 million, net, outstanding under our Debentures. The Debentures (as previously amended) were to mature on January 15, 2015; however, in connection with our entry into the Credit Agreement (discussed below) in January 2015, as of the date of the report, we have 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 (discussed below).

 

Hexagon Settlement

 

On September 2, 2014, we entered into an agreement with Hexagon, LLC (the “Final Settlement Agreement”) to settle all amounts payable by us pursuant to existing credit agreements with Hexagon, LLC (“Hexagon”) that were secured by mortgages against several of our oil and gas properties (the “Hexagon Collateral”). Pursuant to the Final Settlement Agreement, in exchange for full extinguishment of all amounts payable ($15.1 million in principal and interest) pursuant to the credit agreements and related promissory notes, we agreed to assign to Hexagon all of the Hexagon Collateral, and issued to Hexagon $2.0 million in a new series of 6% Redeemable Preferred Stock. The Final Settlement Agreement also prohibits Hexagon from selling or otherwise disposing of any shares of Common Stock held by Hexagon until February 29, 2016. In addition, pursuant to the Final Settlement Agreement, Hexagon and us each mutually released and discharged all known and unknown claims against the other and their respective representatives that they had or may have, including claims relating to the credit agreements.

 

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Heartland Bank Credit Agreement

 

On January 8, 2015, we 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 $3.0 million, which principal amount may be increased to a maximum principal amount of $50.0 million at the request of us, subject to certain conditions, pursuant to an accordion advance provision in the Credit Agreement. The availability of additional funds is subject to the discretion of the lenders, and is generally based on the value of our proved developed producing (“PDP”) and proved undeveloped (“PUD”) reserves. We intend to use proceeds borrowed under the Credit Agreement to fund producing property acquisitions in North America, drill wells in the core of our lease positions and to fund working capital. 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.

 

Financial Condition and Liquidity

  

Information about our year-end financial position is presented in the following table (in thousands):

 

   Year ended December 31, 
   2014   2013 
        (Restated)   
Financial Position Summary        
Cash and cash equivalents  $510   $165 
Working capital (deficit)  $(6,560)  $(12,696)
Balance outstanding on convertible debentures payable and term loan  $6,840   $33,499 
Shareholders’ equity  $14,067   $5,924 

  

As of December 31, 2014, we had a negative working capital balance and a cash balance of approximately $6.56 million and $510,000, respectively. Also as of December 31, 2014, we had $6.84 million, net, outstanding under the Debentures. The Debentures (as previously amended) were to mature on January 15, 2015; however, in connection with our entry into the Credit Agreement in January 2015 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 and the Debentures were classified as a long-term liability as of December 31, 2014. Additionally, we had $5.73 million of accrued drilling activity that is currently in dispute. The Company will either pay the accrued costs and start receiving associated oil and gas revenue or not owe this obligation.

 

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

 

Cash Flows

 

Cash used in operating activities during the year ended December 31, 2014 was $7.31 million. Cash used in operating activities coupled with the $507,000 used in investing activities offset by the $8.16 million provided by financing activities, resulted in an increase in cash of $344,000 during the year.  

 

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The following table compares cash flow items during the year ended December 31, 2014 to December 31, 2013 (in thousands):

 

   Year ended December 31, 
   2014   2013 
       (Restated) 
Cash provided by (used in):        
Operating activities  $(7,306)  $(1,218)
Investing activities   (507)   (1,204)
Financing activities   8,157    1,617 
Net change in cash  $344   $(805)

 

During the year ended December 31, 2014, net cash used in operating activities was $7.31 million, compared to $1.22 million during the year ended December 31, 2013, an increase of cash used in operating activities of $6.09 million, or 499%.  The primary changes in operating cash during the year ended December 31, 2014 was from a reduction of oil and gas revenues and operating fees of $1.67 million which was offset by a decrease in operating expenses of $257,000 for a net decrease in operating income of $1.41 million, $1.00 million in placement fees paid to TR Winston which was ultimately paid to Mr. Mirman.  Additionally, we had increased salaries of $475,000, paid $343,000 for the due diligence of a potential acquisition which did not take place, $250,000 for additional investment banking firms, $650,000 in additional legal fees and approximately $670,000 of other professional fees for acquisitions and additional support during the year.

 

During the year ended December 31, 2014, net cash used in investing activities was $507,000, compared to net cash used in investing activity of $1.2 million during the year ended December 31, 2013, a decrease of cash used in investing activities of $693,000, or 58%. During 2014, we invested $305,000 to obtain certain undeveloped leases and $190,000 on well development and equipment. During 2013, we invested $1.40 million of cost associated with acquisition of undeveloped leaseholds and development of assets throughout Wattenberg and the Silo field offset by an increase in cash of $640,000 related to our sale of oil and gas properties. 

 

During the year ended December 31, 2014, net cash provided by financing activities was $8.16 million, compared to net cash provided by financing activities of $1.62 million during the year ended December 31, 2013, an increase of $6.54 million, or 403%. In 2014, we received cash proceeds from two private placements. We issued common stock and warrants in January 2014 for $5.24 million and issued Series A Preferred Stock in May 2014 for $6.79 million, offset by cash repayment of debt of $3.71 million, and a payment of dividends of 162,000. In 2013, we issued additional convertible debt of $2.18 million offset by cash repayment of debt of $562,000.

 

Capital Resources and 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 to the securing additional capital through equity placement, utilizing the Credit Agreement from Heartland Bank and additional debt instruments and funds contemplated by the Credit Agreement to acquire production in North America. Some of the proceeds from the initial borrowing under the Credit Agreement 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.

 

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As of December 31, 2014 and December 31, 2013, we had $6.04 million and $1.15 million of wells in progress, respectively. Wells in progress are related to certain wells in our core development program within the Northern Wattenberg field. We capitalized and accrued approximately $5.73 million of costs through December 31, 2014 associated with these wells, which are currently in dispute.

 

The dispute relates to our ownership in certain wells being reduced and or eliminated from a possible farm-out.  The operator of the producing wells claims we entered into a farm-out which will reduce our ownership in the wells. Per the terms of the JOA, if we do not generate enough capital from equity or debt raises, then we 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 us a Notice of Non-Consent and a penalty of up to 300% may be imposed in order to buy-back working interest in the newly drilled wells.

 

On March 6, 2015, we filed a lawsuit against the operator.  In our complaint, we seek monetary damages and declaratory relief on claims of breach of contract, breach of the implied covenant of good faith and fair dealing, tortious breach of the implied covenant of good faith and fair dealing, unjust enrichment, conversion and declaratory judgment related to the JOA between us and the operator for tortious actions against us.

 

Results of Operations

 

Year ended December 31, 2014 compared to the year ended December 31, 2013

 

The following table compares operating data for the fiscal year ended December 31, 2014 to December 31, 2013:

 

   Year Ended December 31, 
   2014   2013 
       (Restated) 
Revenue:        
Oil sales  $2,581,689   $4,312,325 
Gas sales   364,732    340,609 
Operating fees   182,773    148,474 
Realized gain (loss) on commodity price derivatives   11,143    (17,572)
Unrealized gain on commodity price derivatives   -    2,475 
Total revenues   3,140,337    4,786,311 
           
Costs and expenses:          
Production costs   954,347    1,217,853 
Production taxes   269,823    263,437 
General and administrative   10,325,842    4,965,279 
Depreciation, depletion and amortization   1,337,662    2,388,871 
Total costs and expenses   12,887,675    8,835,440 
           
Loss from operations before conveyance   (9,747,338)   (4,049,129)
Loss on conveyance of oil and gas properties   (2,269,760)   - 
Loss from operations   (12,017,098)   (4,049,129)
           
Other income (expenses):          
Other income   32,444    11,062 
Inducement expense   (6,661,275)   - 
Convertible notes conversion derivative gain (loss)   (5,526,945)   163,935 
Bristol price protection derivative loss   571,228    - 
Interest expense   (4,837,025)   (6,136,842)
Net Loss  $(28,438,671)  $(10,010,974)

 

42
 

 

Total revenues

 

Total revenues were $3.14 million for the year ended December 31, 2014, compared to $4.79 million for the year ended December 31, 2013, a decrease of $1.65 million, or 34%. The decrease in revenues was primarily due to the reduction in oil and gas revenue associated with 32,000 acres and 17 operated wells we conveyed to Hexagon pursuant to the Final Settlement Agreement, discussed above.

 

During the year ended December 31, 2014 and 2013, production amounts were 46,500 and 62,512 BOE, respectively, a decrease of 16,012 BOE, or 26%. In addition to the conveyance, production declined due to significant downtime on unsuccessful workovers. The differential between the price per BOE received by us and the NYMEX crude price averaged $13.55 for 2014 compared to $7.64 for 2013, an increase of 77% due to the excess supply of oil in the area.

 

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

 

   For the Year Ended 
December 31,
 
   2014   2013 
Product        
Oil (Bbl.)   33,508    51,705 
Oil (Bbls)-average price (1)  $77.05   $83.40 
           
Natural Gas (MCF)-volume   77,954    64,845 
Natural Gas  (MCF)-average price (2)  $4.68   $5.25 
           
Barrels of oil equivalent (BOE)   46,500    62,512 
Average daily net production (BOE)   127    171 
Average Price per BOE (1)  $63.36   $74.43 

 

(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

 

Production costs per BOE   20.52    19.48 
Production taxes per BOE   5.80    4.21 
Depreciation, depletion, and amortization per BOE   28.76    38.21 
Total operating costs per BOE (1)  $55.08   $61.90 
Gross margin per BOE (1)  $8.28   $12.53 
Gross margin percentage   13%   17%

 

(1) Does not include the loss on conveyance

 

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 December 31, 2014, we did not maintain any active commodity swaps.

 

43
 

 

During 2014, we held one commodity swap which matured on January 31, 2014. Commodity price derivative realized gains were $11,000 for the year ended December 31, 2014, compared to a realized loss of $18,000 during the year ended December 31, 2013.  Commodity price derivative unrealized gains was $2,000 for the year ended December 31, 2013.

 

Production costs

 

Production costs were $954,000 during the year ended December 31, 2014, compared to $1.22 million for the year ended December 31, 2013, a decrease of $266,000, or 22%. Decrease in production costs in 2014 was from a decrease in operated wells related to the Hexagon conveyance of properties described above. Production costs per BOE increased to $20.52 for the year ended December 31, 2014 from $19.48 in 2013, an increase of $1.04 per BOE, or 5%, primarily as a result of increased volumes of BOE in 2014 and high well work frequency. During the first nine months of 2014, work-over rigs had limited availability due to high industry activity within our operating area and the fact that we performed an in-depth analysis of production and started to reduce the amount of on-time that the wells pumped.  As a result, we had idled wells for regular scheduled well maintenance or other repairs.

 

Production taxes

 

Production taxes were $270,000 for the year ended December 31, 2014, compared to $263,000 for the year ended December 31, 2013, an increase of $7,000, or 2%.  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 increased to $5.80 during the year ended December 31, 2014 from $4.21 in 2013, an increase of $1.59 or 38%. The increase in production tax is a result of the change in product mix by state. We produced more oil and natural gas from higher taxed states and counties in 2014 compared to 2013.  

 

General and administrative

 

General and administrative expenses were $10.33 million during the year ended December 31, 2014, compared to $4.97 million during the year ended December 31, 2013, an increase of $5.36 million, or 108%.  Non-cash general and administrative items for the year ended December 31, 2014 were $4.43 million compared to $1.73 million during the year ended December 31, 2013, an increase of $2.70 million, or 156%.  The increase in non-cash general and administrative expenses was due to an increase of $686,000 in fees associated with completing the January Private Placement; increased stock based compensation of $754,000 for compensation to employees, directors, consultants compared to prior year, $965,000 Bristol warrant liability (described below) and increase in reserve for bad debt of $30,000. Cash general and administrative expenses were $5.90 million during the year ended December 31, 2014, compared to $1.83 million during the year ended December 31, 2013, an increase of $4.07 million, or 222%.  The increase in cash general and administrative expenses was largely due to a $1.00 million in placement fees paid to TR Winston which was ultimately paid to Mr. Mirman. In connection with the appointment of Mr. Mirman, Chief Executive Officer, the Company and TR Winston amended the investment banking agreement in place between the Company an TR Winston at that time to provide that, upon the receipt by the Company of gross cash proceeds or drawing availability of at least $30 million, measured on a cumulative basis and including certain restructuring transactions, subject to the Company’s continued employment of Mr. Mirman, TR Winston would receive from the Company a lump sum payment of $1 million. Mr. Mirman’s compensation arrangements with TR Winston provided that upon TR Winston’s receipt from the Company of the lump sum payment, TR Winston would make a payment of $1 million to Mr. Mirman. The Board determined in September 2014 that the criteria for the lump sum payment had been met.  Additionally, the Company had increased salaries of $475,000, paid $343,000 for the due diligence of a potential acquisition which did not take place, $250,000 for additional investment banking firms, $650,000 in additional legal fees and approximately $670,000 of other professional fees for acquisitions and additional support during the year.

 

Depreciation, depletion, and amortization

 

Depreciation, depletion, and amortization were $1.34 million during the year ended December 31, 2014, compared to $2.39 million during the year ended December 31, 2013, a decrease of $1.05 million, or 44%.  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 year ended December 31, 2014 and 2013, production amounts were 46,500 and 62,512 BOE, respectively, a decrease of 16,012 BOE, or 26%.

 

Inducement expense

 

In January 2014, the Company incurred an inducement expense of $6.66 million. The Company entered into the Conversion Agreement with all of the holders of our 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, 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 and arrived at a fair value of $6.66 million for the Warrants. 

 

44
 

 

Loss on conveyance of oil and gas properties

 

On September 2, 2014, we entered into the Final Settlement Agreement to settle all amounts payable by the Company pursuant to existing credit agreements with Hexagon (described above). The transaction was accounted for under the full cost method of accounting for oil and natural gas operations. 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 gas attributable to the cost center. The transfer to Hexagon represents greater than 25 percent of the Company’s proved reserves of oil and gas attributable to the full cost pool and thus we incurred a loss on the conveyance. Following this methodology, the following table represents an allocation of the transaction.

 

Payment of debt and accrued interest payable  $15,063,289 
Add: disposition of asset retirement obligations   973,132 
Total disposition of liabilities  $16,036,421 
      
Proved oil and natural gas properties  $32,574,603 
Accumulated depletion   (22,148,686)
Unproved oil and natural gas properties   6,194,162 
Redeemable Preferred Stock at fair value   1,686,102 
Total conveyance of assets and preferred stock   18,306,181 
Loss on conveyance  $(2,269,760)

 

Impairment of developed properties

 

During the year ended December 31, 2014 and 2013, the Company did not impair any of its evaluated properties.

 

If commodity prices stay at current early 2015 levels or decline further, we will incur full cost ceiling impairments in future quarters. Because the ceiling calculation uses rolling 12-month average commodity prices, the effect of lower quarter-over-quarter prices in 2015 compared to 2014 is a lower ceiling value each quarter. This will result in ongoing impairments each quarter until prices stabilize or improve. Impairment charges would not affect cash flow from operating activities, but would adversely affect our net income and stockholders’ equity.

 

Interest Expense

 

For the years ended December 31, 2014 and 2013, the Company incurred interest expense of approximately $4.84 million and $6.14 million, respectively, of which approximately $2.42 million and $1.68 million is classified as non-cash interest expense, respectively. The details of the non-cash interest expense for the year ended December 31, 2014 are as follows: (i) Hexagon non-payment penalty of $1 million (ii) amortization of the deferred financing costs of $235,000, (iii) accretion of the convertible debentures payable discount of $849,000, (iv) Common Stock issued for interest of $1.19 million, (v) accrued interest to convertible debenture of $7,000, and (vi) amortization of forbearance fees of $250,000. The details of the non-cash interest expense for the year ended December 31, 2013 are as follows: (i) amortization of the deferred financing costs of $680,000, (ii) accretion of the convertible debentures payable discount of $2.14 million, (iii) common stock issued for interest of $1.17 million and (iv) accrued interest of convertible debentures of $160,000. Cash interest for 2014 was $1.09 million compared to $2.09 million in 2013.

 

45
 

 

Change in Bristol warrant liability

 

During 2014, we entered into a consulting agreement with Bristol. As a part of the agreement, we issued 1 million warrants/options with an exercise price of $2.00 a share. The warrant/ option will automatically ratchet down to its new price if we issue securities under another consulting agreement with a lower exercise price. The change in fair value of this warrant provision was $571,000 for the year ended December 31. 2014.

 

Change in derivative liability of convertible debentures

 

For the years ended December 31, 2014 and 2013, we incurred a change in the fair value of the derivative liability related to the convertible debentures of approximately $5.53 million and ($164,000) respectively. During the year ended December 31, 2014, we reduced the conversion price from $4.25 to $2.00, consistent with the January Private Placement. The conversion resulted in a reduction of the convertible debenture liability by $5.69 million and an increase in additional paid in capital.

 

Off-Balance Sheet Arrangements

 

We do not have any off-balance sheet arrangements.

 

Critical Accounting Policies and Estimates

 

The preparation of our consolidated financial statements in conformity with generally accepted accounting principles in the United States, or GAAP, requires our management to make assumptions and estimates that affect the reported amounts of assets, liabilities, revenues and expenses, as well as the disclosure of contingent assets and liabilities at the date of our financial statements and the reported amounts of revenues and expenses during the reporting period.  The following is a summary of the significant accounting policies and related estimates that affect our financial disclosures.

 

Critical accounting policies are defined as those significant accounting policies that are most critical to an understanding of a company’s financial condition and results of operation. We consider an accounting estimate or judgment to be critical if (i) it requires assumptions to be made that were uncertain at the time the estimate was made, and (ii) changes in the estimate or different estimates that could have been selected could have a material impact on our results of operations or financial condition.

 

Use of Estimates

 

The financial statements included herein were prepared from 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.  

 

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 gas reserves, assessments of impairment imbedded in the carrying value of undeveloped acreage and proven properties, as well as the valuation of Common Stock, options and warrants, and estimated derivative liabilities.

 

46
 

 

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, 2014, using the average, first-day-of-the-month price during the 12-month period ended December 31, 2014.

 

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 among 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.

 

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.

 

47
 

 

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, 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 employee 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.

 

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

 

Not applicable.

 

Item 8. Financial Statements and Supplementary Data

 

Our financial statements appear immediately after the signature page of this report. See Index to Financial Statements included in this report.

 

48
 

 

Item 9. Changes in and disagreements with Accountants on Accounting and Financial Disclosure

 

On November 7, 2014, we were notified by our independent registered public accounting firm, Hein & Associates LLP (“Hein”) that it did not wish to stand for re-election.   On November 25, 2014, the Company engaged Marcum LLP as the Company’s independent registered public accounting firm, which was approved by our Board. The reports of Hein on the consolidated financial statements of the Company as of and for the fiscal years ended December 31, 2013 and December 31, 2012, did not contain an adverse opinion or disclaimer of opinion and were not qualified or modified as to uncertainty, audit scope, or accounting principles. During the two most recent fiscal years ended December 31, 2013 and December 31, 2012, there were no disagreements between the Company and Hein on any matter of accounting principles or practices, financial statement disclosures, or auditing scope or procedures, which disagreements, if not resolved to the satisfaction of Hein would have caused them to make reference thereto in their reports on the Company’s financial statements for such years. For more information on the change in accountants, please see our Form 8-Ks filed with the Securities and Exchange Commission on November 13, 2014 and December 2, 2014.

 

Item 9A. 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) and 15d-15(e) under the Securities Exchange Act of 1934, as amended, (the “Exchange Act”)) as of December 31, 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 December 31, 2014, the Company’s internal 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 December 31, 2014, the Company’s internal controls and procedures were not effective.

 

A material weakness is a control deficiency, or combination of control deficiencies, that results in more than a remote likelihood that a material misstatement of the annual or interim financial statements will not be prevented or detected. In connection with management’s assessment of our internal control over financial reporting, conducted based on the Internal Control—Integrated Framework issued by COSO (1992), we identified the following material weaknesses in our internal control over financial reporting as of December 31, 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 13, 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.

 

49
 

 

Restatement of Previously Issued Financial Statements

 

As discussed below in Note 3—Summary of Significant Accounting Policies and Estimates— Restatement and Reclassification, in February 2015, the Company discovered an error in the valuation of the conversion derivative liability of the Company’s Debentures for the periods ended December 31, 2011, December 31, 2012, December 31, 2013, March 31, 2014 and June 30, 2014 (together, the “Relevant Periods”). Specifically, the calculation of the conversion liability included in the Company’s financial statements for the Relevant Periods only included the value of the price protection (anti-dilution) feature, when it should have included both the conversion option and the price protection embedded in the Debentures. The changes in the value of the derivative resulted in 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 herein, 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 December 31, 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 and Estimates— 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 December 31, 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 December 31, 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 have hired and expect to hire additional employees to assist with strengthening the segregation of duties and control activities in journal entry processing and complex accounting issues such as those related to our convertible debentures. We also expect to hire an external expert to help with the valuation of convertible debentures. Additionally, we have begun to perform an analysis of all automated and manual procedures to strengthen the effectiveness of our segregation of duties and control environment. At any time, if it appears any control can be implemented to mitigate risks, it is immediately implemented.

 

In the fourth quarter of 2014, we implemented a new extensive Travel and Expense 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.

 

In March 2015, we appointed Kevin Nanke Chief Financial Officer. Mr. Nanke will bring additional oversight in financial reporting and strengthen the segregation of duties.

 

Management believes through their appointment of a new Chief Financial Officer and the implementation of the foregoing policies, they 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 fourth quarter of the year ended December 31, 2014 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting. 

 

Item 9B. Other Information

 

None.

 

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Part III

 

Item 10. Directors, Executive Officers and Corporate Governance

 

Information relating to this item will be included in an amendment to this report or in the proxy statement for our 2015 annual shareholders meeting and is incorporated by reference in this report.

 

Item 11. Executive Compensation

 

Information relating to this item will be included in an amendment to this report or in the proxy statement for our 2015 annual shareholders meeting and is incorporated by reference in this report.

 

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

 

Information relating to this item will be included in an amendment to this report or in the proxy statement for our 2015 annual shareholders meeting and is incorporated by reference in this report.

 

Item 13. Certain Relationships and Related Transactions, and Director Independence

 

Information relating to this item will be included in an amendment to this report or in the proxy statement for our 2015 annual shareholders meeting and is incorporated by reference in this report.

 

Item 14. Principal Accountant Fees and Services

 

Information relating to this item will be included in an amendment to this report or in the proxy statement for our 2015 annual shareholders meeting and is incorporated by reference in this report.

 

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Part IV

 

Item 15. Exhibits and Financial Statement Schedules

 

INDEX TO FINANCIAL STATEMENTS

 

a)

 

Reports of Independent Registered Public Accounting Firms F-1 and F-2
Balance Sheet as of December 31, 2014 and Restated Balance Sheet as of December 31, 2013 F-3 and F-4
Statement of Operations for the year ended December 31, 2014 and Restated Statement of Operations for the year ended December 31, 2013 F-5
Statement of Stockholders’ Equity for the years ended December 31, 2014 and 2013. F-6
Statement of Cash Flows for the year ended December 31, 2014 and Restated Statement of Cash Flows for the year ended 2013 F-7
Notes to Financial Statements F-8

 

b) Financial statement schedules

 

Not applicable.

 

c) Exhibits

 

The information required by this Item is set forth on the exhibit index that follows the signature page to this Annual Report on Form 10-K.

 

52
 

 

SIGNATURES

 

Pursuant to the requirements of Section 13 or 15(d) 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.

 

  LILIS ENERGY, INC.
     
Date: April 15, 2015 By: /s/ Abraham Mirman
    Abraham Mirman
   

Chief Executive Officer

(Authorized Signatory)

 

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

 

Signature   Title   Date
         
/s/ Abraham Mirman   Chief Executive Officer, Director   April 15, 2015
Abraham Mirman   (Principal Executive Officer)    
         
/s/ Kevin K. Nanke   Executive Vice President and Chief Financial Officer   April 15, 2015
Kevin Nanke   (Principal Financial Officer)    
         
/s/ Eric Ulwelling   Principal Accounting Officer and Controller   April 15, 2015
Eric Ulwelling        
         
/s/ Nuno Brandolini   Chairman of the Board   April 15, 2015
Nuno Brandolini        
         
/s/ General Merrill McPeak   Director   April 15, 2015
General Merrill McPeak        
         
/s/ Ronald D. Ormand   Director   April 15, 2015
Ronald D. Ormand        
         
/s/ G. Tyler Runnels   Director   April 15, 2015
G. Tyler Runnels        

 

53
 

 

Exhibit Index

 

The following exhibits are either filed herewith or incorporated herein by reference:

 

3.1 Amended and Restated Articles of Incorporation (incorporated herein by reference to Exhibit 3.1 from the Company’s current report on Form 8-K filed on October 20, 2011).
3.2 Certificate of Amendment to the Articles of Incorporation of Recovery Energy, Inc. (incorporated herein by reference to Exhibit 3.1 from the Company’s current report on Form 8-K filed on November 19, 2013).
3.3 Amended and Restated Bylaws (incorporated herein by reference to Exhibit 3.2 to the Company’s current report on Form 8-K filed on June 18, 2010).
3.4 Certificate of Designation of Preferences, Rights, and Limitations, dated May 30, 2014 (incorporated herein by reference to Exhibit 3.1 from the Company’s current report on Form 8-K filed on June 4, 2014).
3.5 Amendment to Certificate of Designations of Preferences, Rights, and Limitations, dated June 12, 2014 (incorporated herein by reference to Exhibit 3.1 from the Company’s quarterly report on Form 10-Q for the quarter ended March 31, 2014, filed on June 17, 2014).
3.6 Certificate of Designation of 6% Redeemable Preferred Stock, dated August 29, 2014 (incorporated by reference to Exhibit 3.3 to the Company’s quarterly report on Form 10-Q for the period ended June 30, 2014, filed on November 26, 2014).
4.1 Form of Warrant Issued in Private Placement (incorporated herein by reference to Exhibit 4.1 to the Company’s current report on Form 8-K filed on June 4, 2010).
4.2 Warrant to Purchase Common Stock of Recovery Energy, Inc. issued to Hexagon Investments, LLC dated May 28, 2010 (incorporated herein by reference to Exhibit 4.2 to the Company’s current report on Form 8-K filed on June 4, 2010).
4.3 Five Year Warrant to Market Development Consulting Group, Inc. (incorporated herein by reference to Exhibit 10.2 to the Company’s current report on Form 8-K filed on June 18, 2010).
4.4 Form of $2.20 Warrant Issued to Persons Exercising $1.50 Warrants (incorporated herein by reference to Exhibit 4.1 to the Company’s current report on Form 8-K filed on October 8, 2010).
4.5 Warrant Issued to Hexagon Investments, LLC on January 1, 2011 (incorporated herein by reference to Exhibit 4.1 to the Company’s current report on Form 8-K filed on January 4, 2011).
4.6 Form of Warrant (incorporated by reference to Exhibit 4.1 to the Company’s current report on Form 8-K filed on January 28, 2014).
4.7 Form of Warrant (incorporated by reference to Exhibit 4.1 to the Company’s current report on Form 8-K filed on February 6, 2014).
4.8 Five Year Warrant to David Castaneda dated January 17, 2014 (incorporated herein by reference to Exhibit 4.1 to the Company’s quarterly report on Form 10-Q for the period ended March 31, 2014, filed on June 17, 2014).
4.9 Five Year Warrant (Anniversary Warrant) to David Castaneda dated January 17, 2014 (incorporated herein by reference to Exhibit 4.2 to the Company’s quarterly report on Form 10-Q for the period ended March 31, 2014, filed on June 17, 2014).
4.10 Form of Warrant dated May 30, 2014 (incorporated herein by reference to Exhibit 10.2 from the Company’s current report on Form 8-K filed on June 4, 2014).
4.11 Warrant to Purchase Common Stock issued to Bristol Capital (incorporated herein by reference to Exhibit 4.3 to the Company’s quarterly report on Form 10-Q for the period ended June 30, 2014, filed on November 26, 2014).
4.12 Warrant to Purchase Common Stock issued to Heartland Bank (incorporated herein by reference to Exhibit 4.3 to the Company’s quarterly report on Form 10-Q, filed on February 26, 2015).
10.1 Credit Agreement with Hexagon Investments, LLC dated effective as of January 29, 2010 (incorporated herein by reference to Exhibit 10.12 to the Company’s current report on Form 8-K filed on March 4, 2010).
10.2 Promissory Note for financing with Hexagon Investments, LLC dated as of January 29, 2010 (incorporated herein by reference to Exhibit 10.13 to the Company’s current report on Form 8-K filed on March 4, 2010).
10.3 Nebraska Mortgage to Hexagon Investments, LLC dated as of January 29, 2010 (incorporated herein by reference to Exhibit 10.14 to the Company’s current report on Form 8-K filed on March 4, 2010).
10.4 Colorado Mortgage to Hexagon Investments, LLC dated as of January 29, 2010 (incorporated herein by reference to Exhibit 10.15 to the Company’s current report on Form 8-K filed on March 4, 2010).

 

54
 

 

10.5 Credit Agreement with Hexagon Investments, LLC dated effective as of March 25, 2010 (incorporated herein by reference to Exhibit 10.17 to the Company’s current report on Form 8-K filed on March 25, 2010).
10.6 Promissory Note for financing with Hexagon Investments, LLC dated as of March 25, 2010 (incorporated herein by reference to Exhibit 10.18 to the Company’s current report on Form 8-K filed on March 25, 2010).
10.7 Nebraska Mortgage to Hexagon Investments, LLC dated as of March 25, 2010 (incorporated herein by reference to Exhibit 10.19 to the Company’s current report on Form 8-K filed on March 25, 2010).
10.8 Wyoming Mortgage to Hexagon Investments, LLC dated as of March 25, 2010 (incorporated herein by reference to Exhibit 10.20 to the Company’s current report on Form 8-K filed on March 25, 2010).
10.9 Credit Agreement with Hexagon Investments, LLC dated as of April 14, 2010 (incorporated herein by reference to Exhibit 10.2 to the Company’s current report on Form 8-K filed on April 20, 2010).
10.10 Promissory Note with Hexagon Investments, LLC dated April 14, 2010 (incorporated herein by reference to Exhibit 10.3 to the Company’s current report on Form 8-K filed on April 20, 2010).
10.11 Letter Agreement with Hexagon Investments, LLC (incorporated herein by reference to Exhibit 10.4 to the Company’s current report on Form 8-K filed on June 4, 2010).
10.12 Wyoming Mortgage to Hexagon Investments, LLC dated April 14, 2010 (incorporated herein by reference to Exhibit 10.5 to the Company’s current report on Form 8-K filed on April 20, 2010).
10.13 Registration Rights Agreement with Hexagon Investments, Inc. (incorporated herein by reference to Exhibit 10.5 to the Company’s current report on Form 8-K filed on June 18, 2010).
10.14 Stockholders Agreement with Hexagon Investments Incorporated (incorporated herein by reference to Exhibit 10.1 to the Company’s current report on Form 8-K filed on June 29, 2010).
10.15 Amendments to Hexagon Investments, LLC Promissory Notes dated December 29, 2010 (incorporated herein by reference to Exhibit 10.2 to the Company’s current report on Form 8-K filed on January 4, 2011).
10.16 Amendments to three Credit Agreements with Hexagon, LLC, dated March 15, 2012 (incorporated herein by reference to Exhibit 10.55 to the Company’s annual report on Form 10-K for the period ended December 31, 2011, filed on March 21, 2012).
10.17 Second Amendments to three Credit Agreements with Hexagon, LLC, dated July 31, 2012 (incorporated herein by reference to Exhibit 10.1 to the Company’s current report on Form 8-K filed on August 2, 2012).
10.18 Third Amendment to Credit Agreement (First Credit Agreement), dated November 8, 2012 (incorporated herein by reference to Exhibit 10.18 to the Company’s annual report on Form 10-K for the year ended December 31, 2013, filed on June 11, 2014).
10.19 Third Amendment to Credit Agreement (Second Credit Agreement), dated November 8, 2012 (incorporated herein by reference to Exhibit 10.19 to the Company’s annual report on Form 10-K for the year ended December 31, 2013, filed on June 11, 2014).
10.20 Third Amendment to Credit Agreement (Third Credit Agreement), dated November 8, 2012 (incorporated herein by reference to Exhibit 10.20 to the Company’s annual report on Form 10-K for the year ended December 31, 2013, filed on June 11, 2014).
10.21 Fourth Amendment to Credit Agreement (First Credit Agreement), dated April 15, 2013 (incorporated herein by reference to Exhibit 10.57 to the Company’s annual report on Form 10-K for the year ended December 31, 2012, filed on April 17, 2013).
10.22 Fourth Amendment to Credit Agreement (Second Credit Agreement), dated April 15, 2013 (incorporated herein by reference to Exhibit 10.58 to the Company’s annual report on Form 10-K for the year ended December 31, 2012, filed on April 17, 2013).
10.23 Fourth Amendment to Credit Agreement (Third Credit Agreement), dated April 15, 2013 (incorporated herein by reference to Exhibit 10.59 to the Company’s annual report on Form 10-K for the year ended December 31, 2012, filed on April 17, 2013).
10.24 First Amendment to Nebraska Mortgage to Hexagon, LLC, dated March 1, 2013 (incorporated herein by reference to Exhibit 10.24 to the Company’s annual report on Form 10-K for the year ended December 31, 2013, filed on June 11, 2014).

 

55
 

 

10.25 Wyoming Mortgage to Hexagon, LLC, dated March 1, 2013 (incorporated herein by reference to Exhibit 10.25 to the Company’s annual report on Form 10-K for the year ended December 31, 2013, filed on June 11, 2014).
10.26 Form of Securities Purchase Agreement (incorporated herein by reference to Exhibit 10.1 to the Company’s current report on Form 8-K filed on June 4, 2010).
10.27 Form of Registration Rights Agreement (incorporated herein by reference to Exhibit 10.2 to the Company’s current report on Form 8-K filed on June 4, 2010).
10.28 Form of Convertible Debenture Securities Purchase Agreement dated February 2, 2011 (incorporated herein by reference to Exhibit 10.1 to the Company’s current report on Form 8-K filed on February 3, 2011). 
10.29 Form of Convertible Debenture (incorporated herein by reference to Exhibit 10.2 to the Company’s current report on Form 8-K filed on February 3, 2011).
10.30 Amendment to 8% Senior Secured Convertible Debentures dated December 16, 2011 (incorporated herein by reference to Exhibit 10.1 to the Company’s current report on Form 8-K filed on December 19, 2011).
10.31 Second Amendment to 8% Senior Secured Convertible Debentures dated March 19, 2012 (incorporated herein by reference to Exhibit 10.56 to the Company’s annual report on Form 10-K for the year ended December 31, 2011, filed on March 21, 2012).
10.32 Securities Purchase Agreement for additional 8% Senior Secured Convertible Debentures dated March 19, 2012 (incorporated herein by reference to Exhibit 10.57 to the Company’s annual report on Form 10-K for the year ended December 31, 2011, filed on March 21, 2012).
10.33 Form of 8% Senior Secured Convertible Debentures dated March 19, 2012 (incorporated herein by reference to Exhibit 10.58 to the Company’s annual report on Form 10-K for the year ended December 31, 2011, filed on March 21, 2012).
10.34 Amendment to 8% Senior Secured Convertible Debenture and Waiver under Securities Purchase Agreement, dated July 23, 2012 (incorporated herein by reference to Exhibit 10.35 to the Company’s annual report on Form 10-K for the year ended December 31, 2013, filed on June 11, 2014).
10.35 Amendment to Securities Purchase Agreement dated August 7, 2012 (incorporated herein by reference to Exhibit 10.1 to the Company’s current report on Form 8-K filed on August 9, 2012).
10.36 Amendment to Securities Purchase Agreement dated August 7, 2012 (incorporated herein by reference to Exhibit 10.2 to the Company’s current report on Form 8-K filed on August 9, 2012).
10.37 Amendment to 8% Senior Secured Convertible Debentures due February 8, 2014, dated April 15, 2013 (incorporated herein by reference to Exhibit 10.56 to the Company’s annual report on Form 10-K for the year ended December 31, 2013, filed on June 11, 2014).
10.38 Letter Agreement with Debenture Holder dated April 16, 2013 (incorporated herein by reference to Exhibit 10.39 to the Company’s annual report on Form 10-K for the year ended December 31, 2013, filed on June 11, 2014).
10.39 Securities Purchase Agreement dated June 18, 2013 (incorporated herein by reference to Exhibit 10.1 to the Company’s quarterly report on Form 10-Q for the quarter ended June 30, 2013, filed on August 15, 2013).
10.40 Form of Convertible Debenture (incorporated herein by reference to Exhibit 10.2 to the Company’s quarterly report on Form 10-Q for the quarter ended June 30, 2013, filed on August 15, 2013).
10.41 Letter Agreement dated June 18, 2013 regarding 8% Senior Secured Debentures (incorporated herein by reference to Exhibit 10.3 to the Company’s quarterly report on Form 10-Q for the quarter ended June 30, 2013, filed on August 15, 2013).
10.42 Letter of Intent with Shoreline Energy Corp., dated February 4, 2014 (incorporated herein by reference to Exhibit 10.44 to the Company’s annual report on Form 10-K for the year ended December 31, 2013, filed on June 11, 2014).
10.43 Debenture Conversion Agreement, dated as of January 31, 2014 (incorporated herein by reference to Exhibit 10.1 from the Company’s current report on Form 8-K filed on February 6, 2014).
10.44 Form of Subscription Agreement, dated January 22, 2014 (incorporated herein by reference to Exhibit 10.1 to the Company’s current report on Form 8-K filed on January 28, 2014.
10.45 Form of Hexagon Replacement Note (incorporated herein by reference to Exhibit 10.4 from the Company’s current report on Form 8-K filed on June 4, 2014).
10.46 Letter Agreement dated May 19, 2014 with holders of the 8% Senior Secured Convertible Debentures (incorporated herein by reference to Exhibit 10.1 to the Company’s quarterly report on Form 10-Q for the period ended March 31, 2014, filed on June 17, 2014).

 

56
 

 

10.47 Amendment to Debentures dated June 6, 2014 (incorporated herein by reference to Exhibit 10.2 to the Company’s quarterly report on Form 10-Q for the period ended March 31, 2014, filed on June 17, 2014).
10.48 Termination of Investment Banking Agreement with T.R. Winston dated as of March 19, 2013 (incorporated herein by reference to Exhibit 10.5 to the Company’s quarterly report on Form 10-Q for the period ended March 31, 2014, filed on June 17, 2014).
10.49 Transaction Fee Agreement with T.R. Winston dated as of March 28, 2014 (incorporated herein by reference to Exhibit 10.6 to the Company’s quarterly report on Form 10-Q for the period ended March 31, 2014, filed on June 17, 2014).
10.50 Amendment to Transaction Fee Agreement with T.R. Winston dated as of April 29, 2014 (incorporated herein by reference to Exhibit 10.7 to the Company’s quarterly report on Form 10-Q for the period ended March 31, 2014, filed on June 17, 2014).
10.51 Engagement Agreement for Financial Advisory Services with MLV & Co. LLC dated as of February 21, 2014 (incorporated herein by reference to Exhibit 10.8 to the Company’s quarterly report on Form 10-Q for the period ended March 31, 2014, filed on June 17, 2014).
10.52† Consulting Agreement with Market Development Consulting Group, Inc. dated January 17, 2014 (incorporated herein by reference to Exhibit 10.28 to the Company’s annual report on Form 10-K for the year ended December 31, 2013, filed on June 11, 2014).
10.53† Market Development Consulting Group, Inc. Termination letter, dated August 1, 2014 (incorporated herein by reference to Exhibit 10.15 to the Company’s quarterly report on Form 10-Q for the period ended September 30, 2014, filed on February 26, 2015).
10.54† Consulting Agreement with Bristol Capital dated September 2, 2014 (incorporated herein by reference to Exhibit 10.11 to the Company’s quarterly report on Form 10-Q for the period ended June 30, 2014, filed on November 26, 2014).
10.55 Form of Securities Purchase Agreement dated May 30, 2014 (incorporated herein by reference to Exhibit 10.1 from the Company’s current report on Form 8-K filed on June 4, 2014).
10.56 Hexagon Settlement Agreement, dated May 30, 2014 (incorporated herein by reference to Exhibit 10.3 from the Company’s current report on Form 8-K filed on June 4, 2014).
10.57 Settlement Agreement with Hexagon dated September 2, 2014 (incorporated herein by reference to Exhibit 10.10 to the Company’s quarterly report on Form 10-Q for the period ended June 30, 2014, filed on November 26, 2014).
10.58 Letter Agreement with holders of the Company’s 8% Senior Secured Convertible Debentures, dated October 6, 2014 (incorporated herein by reference to Exhibit 99.1 from the Company’s current report on Form 8-K filed on October 7, 2014).
10.59 Credit Agreement, dated 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 the Company’s current report on Form 8-K filed on January 13, 2015).
10.60 Security Agreement, dated as of January 8, 2015, by and between Lilis Energy, Inc. and Heartland Bank, as collateral agent (incorporated herein by reference to Exhibit 10.12(a) from the Company’s quarterly report on Form 10-Q for the period ended September 30, 2014, filed on February 26, 2015).
10.61 Form of Promissory Note from Lilis Energy, Inc. as Borrower to Heartland Bank as Payee, dated as of January 8, 2015 (incorporated herein by reference to Exhibit 10.12(b) from the Company’s quarterly report on Form 10-Q for the period ended September 30, 2014, filed on February 26, 2015).
10.62 Subordination Agreement, dated as of January 8, 2015 (incorporated herein by reference to Exhibit 10.12(c) from the Company’s quarterly report on Form 10-Q for the period ended September 30, 2014, filed on February 26, 2015).
10.63 Form of Mortgage from Lilis Energy, Inc. as Mortgagor to Heartland Bank as Mortgagee (Colorado Oil and Gas Properties) (incorporated herein by reference to Exhibit 10.12(d) from the Company’s quarterly report on Form 10-Q for the period ended September 30, 2014, filed on February 26, 2015).
10.64 Form of Mortgage from Lilis Energy, Inc. as Mortgagor to Heartland Bank as Mortgagee (Nebraska Oil and Gas Properties) (incorporated herein by reference to Exhibit 10.12(e) from the Company’s quarterly report on Form 10-Q for the period ended September 30, 2014, filed on February 26, 2015).
10.65 Form of Mortgage from Lilis Energy, Inc. as Mortgagor to Heartland Bank as Mortgagee (Wyoming Oil and Gas Properties) (incorporated herein by reference to Exhibit 10.12(f) from the Company’s quarterly report on Form 10-Q for the quarter ended September 30, 2014, filed on February 26, 2015).

 

57
 

 

10.66 Letter Agreement with holders of the Company’s 8% Senior Secured Convertible Debentures (incorporated herein by reference to Exhibit 10.13 to the Company’s quarterly report on Form 10-Q for the period ended September 30, 2014, filed on February 26, 2015).
10.67† Recovery Energy, Inc. 2012 Equity Incentive Plan dated August 31, 2012, as amended on November 13, 2013 (incorporated by reference to Exhibit 10.1 to the Company’s current report on Form 8-K filed on November 19, 2013).
10.68† Employment Agreement between the Company and A. Bradley Gabbard (incorporated herein by reference to Exhibit 10.4 to the Company’s quarterly report on Form 10-Q for the quarter ended June 30, 2013, filed on August 15, 2013)
10.69† Stock Option Award Agreement with A. Bradley Gabbard dated as of June 25, 2013 (incorporated herein by reference to Exhibit 10.58 to the Company’s annual report on Form 10-K for the year ended December 31, 2013, filed on June 11, 2014).
10.70† Stock Option Award Agreement with W. Phillip Marcum dated as of June 25, 2013 (incorporated herein by reference to Exhibit 10.59 to the Company’s annual report on Form 10-K for the year ended December 31, 2013, filed on June 11, 2014).
10.71† Employment Agreement between the Company and W. Phillip Marcum (incorporated herein by reference to Exhibit 10.5 to the Company’s quarterly report on Form 10-Q for the quarter ended June 30, 2013, filed on August 15, 2013).
10.72† Separation Agreement with W. Phillip Marcum dated April 24, 2014 (incorporated herein by reference to Exhibit 10.3 to the Company’s quarterly report on Form 10-Q for the period ended March 31, 2014, filed on June 17, 2014).
10.73† Employment Agreement with Robert A. Bell dated May 1, 2014 (incorporated herein by reference to Exhibit 10.4 to the Company’s quarterly report on Form 10-Q for the period ended March 31, 2014, filed on June 17, 2014).
10.74† Independent Director Appointment Agreement with Robert A. Bell effective March 1, 2014 (incorporated herein by reference to Exhibit 10.55 to the Company’s annual report on Form 10-K for the year ended December 31, 2013, filed on June 11, 2014).
10.75† Separation Agreement with Robert A. Bell dated August 1, 2014 (incorporated herein by reference to Exhibit 10.9 to the Company’s quarterly report on Form 10-Q for the period ended June 30, 2014, filed on November 26, 2014).
10.76† Independent Director Appointment Agreement with Nuno Brandolini effective March 1, 2014 (incorporated herein by reference to Exhibit 10.55 to the Company’s annual report on Form 10-K for the year ended December 31, 2013, filed on June 11, 2014).
10.77† Option Award Agreement between the Company and Nuno Brandolini, dated as of October 1, 2014 (fully-vested) (incorporated herein by reference to Exhibit 10.5 to the Company’s quarterly report on Form 10-Q for the period ended September 30, 2014, filed on February 26, 2015).
10.78† Option Award Agreement between the Company and Nuno Brandolini, dated as of October 1, 2014 (subject to vesting) (incorporated herein by reference to Exhibit 10.6 to the Company’s quarterly report on Form 10-Q for the period ended September 30, 2014, filed on February 26, 2015).
10.79† Lilis Energy, Inc. Director Agreement with G. Tyler Runnels (incorporated herein by reference to Exhibit 10.1 from the Company’s current report on Form 8-K filed on December 2, 2014).
10.80† Employment Agreement with Eric Ulwelling, dated as of February 19, 2015 (incorporated herein by reference to Exhibit 10.14 to the Company’s quarterly report on Form 10-Q for the period ended September 30, 2014, filed on February 26, 2015).
10.81† Stock Option Award Agreement with Eric Ulwelling, dated April 14, 2015.
10.82† Employment Agreement with Kevin Nanke, dated March 6, 2015 (incorporated herein by reference to Exhibit 10.1 to the Company’s current report on Form 8-K filed on March 12, 2015).
10.83† Stock Option Award Agreement with Kevin Nanke, dated April 14, 2015.
10.84† Employment Agreement with Ariella Fuchs, dated March 16, 2015.
10.85† Stock Option Award Agreement with Ariella Fuchs, dated April 14, 2015.
10.86† Amended and Restated Employment Agreement between the Company and Abraham Mirman, dated March 30, 2015 (incorporated herein by reference to Exhibit 10.1 to the Company’s current report on Form 8-K filed on April 2, 2015).
10.87† Stock Option Award Agreement with Abraham Mirman, dated April 14, 2015.

 

58
 

 

21.1 List of subsidiaries of the registrant.
23.1 Consent of Marcum LLP.
23.2 Consent of Hein & Associates, LLP.
23.3 Consent of RE Davis.
31.1 Certifications Pursuant to Section 302 of Sarbanes Oxley Act of 2002.
31.2 Certifications Pursuant to Section 302 of Sarbanes Oxley Act of 2002.
32.1 Certifications Pursuant to Section 906 of Sarbanes Oxley Act of 2002.
32.2 Certifications Pursuant to Section 906 of Sarbanes Oxley Act of 2002.
99.1 Report of RE Davis.
101.INS XBRL Instance Document
101.SCH XBRL Taxonomy Extension Schema Document
101.CAL XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF XBRL Taxonomy Extension Definition Linkbase Document

 

 

† Indicates a management contract or any compensatory plan, contract or arrangement.

 

59
 

  

Report of Independent Registered Public Accounting Firm

 

To the Audit Committee of the 

Board of Directors and Shareholders 

of Lilis Energy, Inc.

 

We have audited the accompanying balance sheet of Lilis Energy, Inc. (the “Company”) as of December 31, 2014, and the related statements of operations, stockholders’ equity and cash flows for the year then ended. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audit.

 

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

 

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Lilis Energy, Inc., as of December 31 2014, and the results of its operations and its cash flows for the year then ended in conformity with accounting principles generally accepted in the United States of America.

 

/s/ Marcum LLP 

Marcum llp

New York, NY
April 15, 2015

 

F-1
 

  

Report of Independent Registered Public Accounting Firm

 

  

To the Board of Directors and Shareholders

Lilis Energy, Inc.

  

We have audited the accompanying consolidated balance sheet of Lilis Energy, Inc. and subsidiaries (together, the “Company”) as of December 31, 2013, and the related consolidated statements of operations, shareholders’ equity, and cash flows for the year then ended. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audit.

 

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

 

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Lilis Energy, Inc. and subsidiaries as of December 31, 2013, and the results of their operations and their cash flows for the year then ended, in conformity with U.S. generally accepted accounting principles.

 

As discussed in Note 2, the 2013 financial statements have been restated to correct a misstatement.

  

 

/s/ Hein & Associates LLP

 

Denver, Colorado

June 11, 2014, except for Note 2, as to which the date is April 15, 2015

   

F-2
 

 

LILIS ENERGY, INC.

Balance Sheets

 

   December 31,   December 31, 
   2014   2013 
       (Restated) 
Assets
Current assets:        
Cash  $509,628   $165,365 
Restricted cash   183,707    504,623 
Accounts receivable (net of allowance of $80,000 and $50,000 at December 31, 2014 and 2013, respectively)   831,706    467,337 
Prepaid assets   54,064    195,716 
Commodity price derivative receivable   -    6,679 
Total current assets   1,579,105    1,339,720 
           
Oil and gas properties (full cost method), at cost:          
Evaluated properties   46,268,756    68,213,467 
Unevaluated acreage, excluded from amortization   2,885,758    18,663,569 
Wells in progress, excluded from amortization   6,041,743    1,145,794 
Total oil and gas properties, at cost   55,196,257    88,022,830 
Less accumulated depreciation, depletion, amortization, and impairment   (24,550,217)   (45,457,637)
Oil and gas properties at cost, net   30,646,040    42,565,193 
           
Other assets:          
Office equipment net of accumulated depreciation of $107,712 and $79,558 at December 31, 2014 and 2013, respectively.   73,823    91,161 
Deferred financing costs, net   60,000    294,699 
Restricted cash and deposits   215,541    215,541 
Total other assets   349,364    601,401 
           
Total Assets  $32,574,509   $44,506,314 

 

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

 

F-3
 

 

LILIS ENERGY, INC.

BALANCE SHEETS

 

   December 31,   December 31, 
   2014   2013 
       (Restated) 
         
Liabilities, Redeemable Preferred Stock and Stockholders' Equity
Current liabilities:        
Dividends accrued on preferred stock  $180,000    - 
Accrued expenses for drilling activity   5,734,131    - 
Accounts payable   975,749    1,239,152 
Accrued expenses   1,248,995    2,133,422 
Short term notes payable   -    10,662,904 
Total current liabilities   8,138,875    14,035,478 
           
Long term liabilities:          
Asset retirement obligation   200,063    1,104,952 
Term notes payable   -    8,111,436 
Convertible debentures, net of discount   6,840,076    14,724,366 
Bristol warrant liability   393,788    - 
Convertible debentures conversion derivative liability   1,249,442    605,315 
Total long-term liabilities   8,683,369    24,546,069 
           
Total liabilities   16,822,244    38,581,547 
           
Commitments and contingencies          
           
Conditionally redeemable 6% preferred stock, $0.0001 par value: 7,000 shares authorized, 2,000 shares issued and outstanding with a liquidation preference of $2,030,000 as of December 31, 2014. No shares were outstanding as of December 31, 2013   1,686,102    - 
           
Stockholders’ equity          
Series A Preferred stock, $0.0001 par value; stated rate $1,000:10,000,000 shares authorized, 7,500 issued and outstanding with a liquidation preference of $7,650,000 as of December 31, 2014. No shares were issued as of December 31, 2013   6,794,000    - 
Common stock, $0.0001 par value: 100,000,000 shares authorized; 26,988,240 and 19,671,901 shares issued and outstanding as of December 31, 2014 and December 31, 2013, respectively   2,699    1,967 
Additional paid in capital   155,097,785    121,451,232 
Accumulated deficit   (147,828,321)   (115,528,432)
Total stockholders' equity   14,066,163    5,924,767 
           
Total Liabilities, Redeemable Preferred Stock and Stockholders’ Equity  $32,574,509   $44,506,314 


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

 

F-4
 

 

LILIS ENERGY, INC.

Statements of Operations

Years Ended December 31, 2014 and 2013

 

   2014   2013 
       (Restated) 
Revenue:        
Oil sales  $2,581,689   $4,312,325 
Gas sales   364,732    340,609 
Operating fees   182,773    148,474 
Realized gain (loss) on commodity price derivatives   11,143    (17,572)
Unrealized gain on commodity price derivatives   -    2,475 
Total revenue   3,140,337    4,786,311 
           
Costs and expenses:          
Production costs   954,347    1,217,853 
Production taxes   269,823    263,437 
General and administrative   10,325,842    4,965,279 
Depreciation, depletion and amortization   1,337,662    2,388,871 
Total costs and expenses   12,887,675    8,835,440 
           
Loss from operations before conveyance   (9,747,338)   (4,049,129)
Loss on conveyance of oil and gas properties   (2,269,760)   - 
Loss from operations   (12,017,098)   (4,049,129)
           
Other income (expenses):          
Other income   32,444    11,062 
Inducement expense   (6,661,275)   - 
(Loss) gain on change in fair value of convertible debentures conversion derivative liability   (5,526,945)   163,935 
Gain on change in fair value of Bristol warrant liability   571,228    - 
Interest expense   (4,837,025)   (6,136,842)
Total other expenses   (16,421,573)   (5,961,845)
           
Net loss  $(28,438,671)  $(10,010,974)
Dividend on preferred stock   (341,848)   - 
Deemed dividend Series A Convertible Preferred Stock   (3,519,370)   - 
Net loss attributable to common shareholders  $(32,299,889)  $(10,010,974)
           
Net loss per common share basic and diluted  $(1.23)  $(0.53)
Weighted average shares outstanding:          
Basic and diluted   26,333,161    18,990,383 

 

The accompanying notes are an integral part of these financial statements

 

F-5
 

 

LILIS ENERGY, INC.

Statements of STOCKHolders’ Equity

Years Ended December 31, 2014 and 2013

 

                   Additional         
   Preferred Stock   Common Stock   Paid-In   Accumulated     
   Shares   Amount   Shares   Amount   Capital   Deficit   Total 
                             
Balance, January 1, 2013 (Restated)  -   $-    18,394,401   $1,839   $118,296,678   $(105,517,458)  $12,781,059 
Common stock issued in connection with interest payment on convertible debt   -    -    636,282    64    1,167,933    -    1,167,997 
Common stock issued in connection with Investment Banking Agreement   -    -    100,000    10    159,990    -    160,000 
Common stock issued in connection with 2013 Executive and Board Compensation under the amended agreement   -    -    281,250    28    (28)   -    - 
Common stock issued for compensation (board and employees)   -    -    259,968    26    857,097    -    857,123 
Options issued to Executive Management and Board of Directors   -    -    -    -    455,056    -    455,056 
Warrants issued to service organizations for 2013 services   -    -    -    -    514,506    -    514,506 
Net Loss   -    -    -    -    -    (10,010,974)   (10,010,974)
                                    
Balance, December 31, 2013 (Restated)   -    -    19,671,901    1,967    121,451,232    (115,528,432)   5,924,767 
                                    
Common stock issued in connection with January 2014 private placement   -    -    2,959,125    296    3,557,107    -    3,557,403 
Fair value of warrants issued in connections with January 2014 private placement including placement warrants   -    -    -    -    1,678,596    -    1,678,596 
Common stock issued in connection with January 2014 conversion of convertible debt   -    -    4,366,726    437    8,733,001    -    8,733,438 
Common stock issued for placement fees in connection with January 2014 conversion of convertible debt   -    -    225,000    23    686,227    -    686,250 
Fair value of inducement expense in connection with debenture conversion   -    -    -    -    6,661,275     -     6,661,275 
Reclassification of conversion liability in connection with January 2014 conversion of convertible debt        -     -    -    4,882,815    -    4,882,815 
Preferred stock issued in connection with May 2014 private placement, net   7,500    6,794,000    -    -    -    -    6,794,000 
Fair value of warrant and beneficial conversion feature in connection with May 2014 private placement   -    -    -    -    3,519,370    (3,519,370)   - 
Common stock issued for interest in connection with convertible debt outstanding   -    -    1,396,129    140    1,188,299    -    1,188,439 
Common shares issued for restricted stock vested   -    -    327,901    32    (32)   -    - 
Stock based compensation for issuance of restricted stock   -    -    -    -    514,804    -    514,804 
Stock based compensation for issuance of stock options   -    -    -    -    1,242,256    -    1,242,256 
Common stock issued for professional services   -    -    90,000    9     305,040    -     305,049 
Fair value of warrants issued for professional services   -    -    -    -    677,590    -    677,590 
Adjustment for restricted stock not vested   -    -    (2,048,542)   (205)   205    -    - 
Dividend Preferred Stockholders   -    -    -    -    -    (341,848)   (341,848)
Net Loss   -    -    -    -    -    (28,438,671)   (28,438,671)
                                    
Balance, December 31, 2014  7,500   $6,794,000    26,988,240   $2,699   $155,097,785   $(147,828,321)  $14,066,163 

 

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

 

F-6
 

 LILIS ENERGY, INC.

Statements of Cash Flows

Years Ended December 31, 2014 and 2013

 

   Year ended December 31, 
   2014   2013 
         (Restated) 
           
Cash flows from operating activities:          
Net loss  $(28,438,671)  $(10,010,974)
Adjustments to reconcile net loss to net cash used in operating activities:          
Inducement expense   6,661,275    - 
Common stock issued to investment bank for fees related to conversion of convertible debentures   686,250    - 
Equity instruments issued for services and compensation   2,739,699    1,986,685 
Bristol warrant liability   965,016    - 
Reserve on bad debt expense   30,000    - 
Loss on conveyance of property   2,269,760    - 
Loss (gain) from hedge settlements   11,143    (13,359)
Change in fair value of price derivative   (4,464)   6,679 
Change in fair value of executive incentive bonus   (105,000)   - 
Amortization of deferred financing cost   234,699    680,157 
Common stock issued for convertible note interest   1,188,439    1,167,997 
Change in fair value of convertible debenture conversion derivative   5,526,945    (163,935)
Change in fair value of Bristol warrant liability   (571,228)   - 
Depreciation, depletion, amortization and accretion of asset retirement obligation   1,337,662    2,388,871 
Accretion of debt discount   849,147    2,144,367 
Changes in operating assets and liabilities:          
Accounts receivable   (394,369)   467,254 
Restricted cash   320,916    166,758 
Other assets   141,652    (182,256)
Accounts payable and other accrued expenses   (755,108)   129,967 
Net cash used in operating activities   (7,306,237)   (1,231,789)
           
Cash flows from investing activities:          
Acquisition of undeveloped acreage   (305,000)   (1,404,121)
Drilling capital expenditures   (190,786)   (398,752)
Sale of undeveloped acreage interests   -    640,000 
Additions of office equipment   (10,815)   (27,829)
Investment in operating bonds   -    (106)
Net cash used in investing activities   (506,601)   (1,190,808)
           
Cash flows from financing activities:          
Net proceeds from issuance of Common Stock   5,236,000    - 
Proceeds from issuance of debt   -    2,179,902 
Net proceeds from issuance of Series A Convertible Preferred Stock   6,794,000    - 
Dividend payments on preferred stock   (161,848)   - 
Repayment of debt   (3,711,051)   (561,975)
Net cash provided by financing activities   8,157,101    1,617,927 
           
Increase (decrease) in cash    344,263    (804,670)
Cash at beginning of year   165,365    970,035 
           
CASH AT END OF YEAR  $509,628   $165,365 
Supplemental disclosure:          
Cash paid for interest  $1,324,988   $2,096,769 
Cash paid for income taxes  $-   $- 
           
Non-cash transactions:          
Common stock issued for accrued convertible debenture interest  $1,188,439   $1,167,997 
Acquisition of oil and gas assets for accounts payable and accrued interest  $5,466,405   $- 
Transfer from derivative liability to equity  $4,882,815   $- 
Issuance of Common Stock for payment of convertible debentures  $8,733,438   $- 
Issuance of redeemable preferred stock for payment of term notes payable  $1,686,102   $- 
Conveyance of oil and gas properties for payment of term notes payable  $15,063,289   $- 
Conveyance of oil and gas properties for reduction in asset retirement obligation  $973,132   $- 
Stock and warrants issued for prepaid financial advisory fees  $-   $674,506 
Property additions for asset retirement obligation  $-   $101,510 

 

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