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 executive offices are located at 1900 Grant Street, Suite #720, Denver, Colorado 80203, and our telephone number is (303) 951-7920. 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.
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 112,000 net acres of developed and undeveloped acreage that are currently held by the Company, primarily in the northern DJ Basin.
Recent Developments
As of December 31, 2013, we had $18.77 million outstanding under our term loans and $15.58 million outstanding under our Debentures. During 2014, we consummated several transactions which reduced our term note as of June 1, 2014 to $13.77 million and our outstanding Debentures to $6.73 million. Both the debentures and term loan have extended their maturity dates.
As of December 3, 2013, we have a working capital deficit of approximately $12.70 million, and approximately $14.04 million in current liabilities. The Company secured financing and other transactions to improve the overall liquidity of the Company and to secure capital to fund our oil and gas development projects.
January 2014 Private Placement
On January 22, 2014, the Company entered into and closed a series of subscription agreements with accredited investors in a private placement transaction, pursuant to which the Company issued an aggregate of 2,959,125 units, with each unit consisting of (i) one share of the Company’s 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 $5,918,250 (the “January Private Placement”). In conjunction with the January Private Placement, certain of the Company’s current and former officers and directors agreed to purchase an additional $1,425,000 of Units subject to receipt of shareholder approval as required by NASDAQ’s continued listing requirements. The warrants issued in the private placement are not exercisable for six months following the closing of the January Private Placement.
Debenture Conversion
On January 31, 2014, the Company entered into a Debenture Conversion Agreement (the “Conversion Agreement”), with all of the holders of the Debentures. Under the terms of the Conversion Agreement, $9 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, subject to receipt of shareholder approval as required by the NASDAQ continued listing requirements. As additional inducement for the conversions, the Company 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. The shares underlying the warrants have not been registered under the Securities Act of 1933, as amended (the “Securities Act”), or any state securities laws and may not be offered or sold in the United States absent registration or an applicable exemption from registration.
The Company intends to present proposals to approve i) participation by officers and directors in the January Private Placement, and ii) the conversion of the remaining outstanding Debentures at its 2014 annual meeting of shareholders, which is expected to take place in July 2014.
Hexagon Settlement
On May 19, 2014, we received an extension from Hexagon of the maturity date under our term loans, from May 16, 2014 to August 15, 2014. On May 30, 2014, we entered into a Settlement Agreement (the “Settlement Agreement”) with Hexagon, which provides for the settlement of all amounts outstanding under the Term Loans. In connection with the execution of the Settlement Agreement, the Company made an initial cash payment of $5.0 million. The Settlement Agreement requires the Company to make an additional cash payment of $5.0 million (the “Second Cash Payment”), and at that time issue to Hexagon (i) a two-year $6.0 million unsecured note (the “Replacement Note”), bearing interest at an annual rate of 8%, and requiring principal and interest payments of $90,000 per month, matures May 30, 2016, and (ii) 943,208 shares of unregistered common stock (the “Shares”), which together will constitute full payment of the Term Loans. The parties have also agreed that if the Second Cash Payment is not made by June 30, 2014, an additional $1.0 million in principal will be added to the Replacement Note, and if the Replacement Note is not retired by December 31, 2014, the Company will issue an additional 1.0 million shares of its common stock to Hexagon. Finally, Hexagon agreed that it will not, until the earlier of June 30, 2014 or the date the Company achieves sustained average trading volume in excess of 100,000 shares per day for at least ten consecutive trading days, sell or otherwise transfer for value any shares of the Company’s common stock or any securities convertible into the Company’s common stock, and thereafter until December 31, 2014, Hexagon will not sell or otherwise transfer for value more than 10,000 shares per week of the Company’s common stock or any securities convertible into the Company’s common stock. Under the Settlement Agreement, Hexagon will release its security interest under the Term Loans once the Company has delivered the Second Cash Payment, the Replacement Note and the Shares.
Debentures Extension
On May 19, 2014, holders of the remaining Debentures agreed to extend the maturity date under the Debentures from May 16, 2014 to August 15, 2014, and to waive their right to declare an event of default in connection with the May 16, 2014 maturity date under the Debentures. On June 6, 2014, the holders of the remaining Debentures agreed to further extend the maturity date under the Debentures from August 15, 2014 to January 15, 2015.
May Private Placement
On May 30, 2014, we closed a private placement (the “May Private Placement”) of our 8% Convertible Preferred Stock (“Preferred Stock”) with accredited investors, pursuant to which we sold $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. The Company has 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 private placement for its own account. The Company used $5.00 million of the proceeds of the May Private Placement to make the first cash payment in connection with the Hexagon settlement (discussed above), and intends to use 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 effect the purchase by third parties of an additional $15 million in Preferred Stock, which transaction is to be consummated within ninety (90) days.
Senior Management Changes
In April 2014, W. Phillip Marcum, our chief executive officer and chairman of our board of directors (the “Board”), resigned to pursue other interests, and the Board appointed Abraham Mirman, formerly our president, to the position of chief executive officer. At the same time, the Board appointed Robert A. Bell to the position of president and chief operating officer. A. Bradley Gabbard, formerly our chief operating officer and chief financial officer, remained in the position of chief financial officer until his resignation in May 2014. Upon Mr. Gabbard’s resignation, the Board appointed Eric Ulwelling to the position of Acting Chief Financial Officer.
Overview of Our Business and Strategy
We have acquired and/or developed an oil and natural gas base of proved reserves, as well as a portfolio of exploration and development prospects with both conventional and unconventional reservoirs opportunities, with an emphasis on multiple producing horizons, and primary focus on the Niobrara shale and Codell unconventional resource plays. We believe these prospects offer the possibility of year-over-year, repeatable success allowing for meaningful production and reserve growth. Our acquisition, development and exploration pursuits are principally directed at oil and natural gas properties in the DJ Basin in Colorado, Nebraska, and Wyoming. Since early 2010, we have acquired and/or developed 25 producing wells. As of December 31, 2013 we owned interests in approximately 126,000 gross (112,000 net) leasehold acres, of which 114,000 gross (100,000 net) acres are classified as undeveloped acreage and all of which are located in Colorado, Wyoming and Nebraska within the DJ Basin. We intend to continue to evaluate and invest in internally generated prospects. It is our long-term goal to maximize production and reserves from our DJ Basin acreage position through the exploitation of both our conventional and Niobrara shale and Codell unconventional resource potential.
It is our belief that the oil and gas industry’s most significant value creation occurs through maximizing ultimate oil and gas recovery via the drilling of successful development wells and a prudent exploitation program. Our primary mission is to maximize shareholder value via increasing ultimate recovery with high capital efficiency while maintaining a low cost structure. To achieve this, our business strategy includes the following elements to manage risk and maximize economic returns:
Participation in development prospects in a known producing basin. We pursue prospects in the DJ Basin on both an operated and non-operated basis, where we can capitalize on our development and production expertise and proven results in the area. We intend to operate the majority of our properties and evaluate each prospect based on its exploitation potential and economic merits.
Negotiated acquisitions of properties. We acquire producing properties based on our knowledge of pricing cycles of oil and natural gas and forecast exploitation potential of proved, probable and possible reserves.
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. Due to our recent liquidity difficulties, a significant amount of our current drilling activity is not operated by us, which enables us to engage in production activities with a relatively low initial capital outlay. The majority of our acreage is contiguous, which will permit efficiencies in drilling and production operations.
Leasing of Prospective Acreage. In the course of our business, we identify drilling opportunities on properties that have not yet been leased. At times, we 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.
Controlling Costs. We seek to maximize our returns on capital employed via prudent technical evaluations, design and planning to maximize capital efficiency and minimizing our general and administrative and operating expenses. We also minimize initial capital expenditures on geological and geophysical overhead, seismic data, hardware and software by partnering with cost efficient operators that have already invested capital in such. We also outsource some of our technical functions in order to help reduce general and administrative and capital obligations.
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 base cash flow to fund our debt service costs and capital programs. From time to time, we will enter into futures contracts, collars and basis swap agreements, as well as fixed price physical delivery contracts. We intend to use hedging primarily to manage price risks and returns on certain acquisitions and drilling programs. Our policy is to consider hedging an appropriate portion of our production at commodity prices we deem attractive. In the future we may also be required by our lenders to hedge a portion of production as part of any financing.
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, 2013 we owned interests in approximately 126,000 gross (112,000 net) leasehold acres, of which 114,000 gross (100,000 net) acres are classified as undeveloped acreage and all of which are located in Colorado, Wyoming and Nebraska within the DJ Basin. Our 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.
In June 2013, the Company purchased a 50% working interest in a section in Laramie County, Wyoming for $0.60 million with an additional $0.13 million as additions to the well equipment and intangible equipment. The purchase was classified as $0.30 million into undeveloped acreage and $0.43 million into oil and gas properties.
Effective as of December 31, 2013, the Company completed an assessment of impairment related to its inventory of undeveloped acreage, which resulted in a reduction of the carrying value in the amount of $9.58 million. This impairment was recognized by a transfer of the impairment value from unevaluated acreage to evaluated properties. In assessing impairment, the Company analyzed all of its undeveloped acreage with expiration dates during the years ended December 31, 2014 and 2015, and which are not otherwise renewable, and impaired such acreage in the amount of $6.38 million. In addition to impairment related to near and intermediate term expirations, the Company assessed carrying value of its remaining acreage, and concluded that an additional impairment of $3.20 million was necessary.
In February 2013, the Company completed the sale of certain oil and gas properties for $0.64 million.
During 2013, we made capital expenditures of approximately $1.89 million, which included $0.30 million related to undeveloped acreage, $1.13 million related to wells in progress for drilling 1 gross (0.25 net) well as non-operator in our North Wattenberg prospect, $0.46 million from re-completion of a well that provided production from a new zone as well as additional reserves and other minor additions to our 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, 2013. Prior to January 2010, we did not own any reserves nor did we have any production. We engaged Ralph E. Davis Associates, Inc. (“RE Davis”) to audit internal engineering estimates for 100 percent of the PV-10 value of our proved reserves at year-end 2013. The prices used in the calculation of proved reserve estimates as of December 31, 2013, were $89.57 per Bbl and $4.747 per MCF; as of December 31, 2012, were $87.37 per Bbl and $2.75 per MCF; and as of December 31, 2011, were $88.16 per Bbl and $3.96 per MCF for oil and natural gas, respectively. The prices were adjusted for basis differentials, pipeline adjustments, and BTU content.
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. 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. No estimates of our proved reserves have been filed with or included in reports to any federal authority or agency, other than the Securities and Exchange Commission ("SEC"), since the beginning of the last fiscal year. We did not have third party engineers conduct an extensive review of probable and possible reserves or resources as of December 31, 2013.
| | | As of December 31, | |
| | | 2013 | | | 2012 | | | 2011 | |
| | | | |
| Reserve data: | | | |
| Proved developed | | | | | | | | | |
| Oil (MBbl) | | | 171 | | | | 213 | | | | 216 | |
| Gas (MMcf) | | | 313 | | | | 186 | | | | 148 | |
| MBOE(1) | | | 223 | | | | 244 | | | | 241 | |
| Proved undeveloped | | | | | | | | | | | | |
| Oil (MBbl) | | | 672 | | | | 138 | | | | 392 | |
| Gas (MMcf) | | | 2,251 | | | | 221 | | | | - | |
| MBOE (1) | | | 1047 | | | | 175 | | | | 392 | |
| Total Proved | | | | | | | | | | | | |
| Oil (MBbl) | | | 843 | | | | 351 | | | | 608 | |
| Gas (MMcf) | | | 2,564 | | | | 407 | | | | 148 | |
| MBOE | | | 1,270 | | | | 419 | | | | 633 | |
| Proved developed reserves % | | | 18 | % | | | 58 | % | | | 38 | % |
| Proved undeveloped reserves % | | | 82 | % | | | 42 | % | | | 62 | % |
| | | | | | | | | | | | | |
| Reserve value data : | | | | | | | | | | | | |
| Proved developed PV-10 | | $ | 7,675 | | | $ | 9,743 | | | $ | 10,204 | |
| Proved undeveloped PV-10 | | | 15,667 | | | | 5,679 | | | | 9,810 | |
| Total proved PV-10 (2) | | $ | 23,342 | | | $ | 15,422 | | | $ | 20,014 | |
| Standardized measure of discounted future cash flows | | $ | 23,342 | | | $ | 15,422 | | | $ | 20,014 | |
| Reserve life (years) | | | 33.25 | | | | 42.42 | | | | 22.58 | |
| | (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 increase of proved undeveloped reserves to 1,047 MBOE at year end 2013 from 175 MBOE at year end 2012, an increase of 872 MBOE or 498% reflects, in part, our uncertainty in 2012 regarding whether we would have sufficient capital to support our current development plan. Proved undeveloped reserves in 2012 were estimated under the assumption that certain farm-outs and joint venture arrangements would be require in order to finance development of such reserves. These assumptions lowered both the reserve values and capital requirements. This assumption was removed in the preparation of our 2013 reserve estimates due to our improving financial health. Proved undeveloped reserves also increased as a result of a change in the development plan for one of the Company’s major properties. The development plan was revised from a vertical to a horizontal program due principally to recent development activities in adjacent and nearby drilling units.
Effective as of December 31, 2013, the Company completed an assessment of impairment related to its inventory of undeveloped acreage, which resulted in a reduction of the carrying value in the amount of $9.58 million. This impairment was recognized by a transfer of the impairment value from undeveloped acreage to developed properties. In assessing impairment, the Company analyzed all of its undeveloped acreage with expiration dates during the years ended December 31, 2014 and 2015, and that are not otherwise renewable, and impaired such acreage in the amount of $6.38 million. In addition to impairment related to near and intermediate term expirations, the Company assessed carrying value of its remaining acreage, and concluded that an additional impairment of $3.20 million was necessary.
At December 31, 2013, 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 President / Chief Operating Officer with assistance from our internal geologist, senior geologist consultant, principal accounting officer, and a senior reserve engineering consultant.
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 President / Chief Operating Officer. This data, in conjunction with economic data and ownership information, is used in making a determination of estimated proved reserve quantities. The 2013 reserve process was overseen by Kent Lina, our senior reserve engineering consultant. Mr. Lina was previously employed by the Company from October 2010 through December 2012, and prior to that employed by Delta Petroleum Company 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, 2013 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 technical person 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 February 27, 2014 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, 2013, 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 President / Chief Operating Officer, geologist and principal accounting officer and the audit committee of our board of directors. Our President / Chief Operating 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’s 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, | |
| | 2013 | | 2012 | | 2011 | |
| Product | | | | | | | | | |
| Oil (Bbl.) | | | 51,705 | | | | 68,207 | | | | 81,433 | |
| Oil (Bbls)-average price (1) | | $ | 83.4 | | | $ | 86.48 | | | $ | 87.78 | |
| | | | | | | | | | | | | |
| Natural Gas (MCF)-volume | | | 64,845 | | | | 182,160 | | | | 248,502 | |
| Natural Gas (MCF)-average price (2) | | $ | 5.25 | | | $ | 2.23 | | | $ | 2.20 | |
| | | | | | | | | | | | | |
| Barrels of oil equivalent (BOE) | | | 62,512 | | | | 98,567 | | | | 122,850 | |
| Average daily net production (BOE) | | | 171 | | | | 270 | | | | 337 | |
| Average Price per BOE (1) | | $ | 74.43 | | | $ | 63.96 | | | $ | 62.64 | |
| (1) Does not include the realized price effects of hedges |
| (2) Includes proceeds from the sale of NGL's |
| Oil and gas production costs, production taxes, depreciation, depletion, and amortization |
| Average Price per BOE(1) | | $ | 74.43 | | | $ | 63.96 | | | $ | 62.64 | |
| | | | | | | | | | | | | |
| Production costs per BOE | | $ | 19.48 | | | $ | 14.42 | | | $ | 12.33 | |
| Production taxes per BOE | | $ | 4.21 | | | $ | 2.31 | | | $ | 6.83 | |
| Depreciation, depletion, and amortization per BOE | | $ | 38.21 | | | $ | 46.15 | | | $ | 35.39 | |
| Total operating costs per BOE | | $ | 61.90 | | | $ | 62.88 | | | $ | 54.55 | |
| | | | | | | | | | | | | |
| Gross margin per BOE | | $ | 12.53 | | | $ | 1.08 | | | $ | 8.09 | |
| | | | | | | | | | | | | |
| Gross margin percentage | | | 17 | % | | | 2 | % | | | 13 | % |
| (1) Does not include the realized price effects of hedges |
Productive Wells
As of December 31, 2013, we had working interests in 27 gross (25 net) productive oil wells, and 1 gross (1 net) productive gas well. 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, 2013 we owned 25 producing wells in Wyoming, Nebraska and Colorado within the DJ Basin, as well as approximately 126,000 gross (112,000 net) acres, of which 114,000 gross (100,000 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, 2013.
| | Undeveloped | | | Developed | |
| | Gross | | Net | | | Gross | | | Net | |
| DJ Basin | | | 114,000 | | | | 100,000 | | | | 12,000 | | | | 12,000 | |
| | | | | | | | | | | | | | | | | |
| Total | | | 114,000 | | | | 100,000 | | | | 12,000 | | | | 12,000 | |
Currently, our inventory of developed and undeveloped acreage includes approximately 12,000 net acres that are held by production, approximately 25,000 net acres, 61,000, and 14,000 net acres that expire in the years 2014, 2015 and thereafter, respectively. Approximately 75% of our inventory of undeveloped acreage provides for extension of lease terms from two to five years, at the option of the Company, via payment of varying, but typically nominal, extension amounts. However, due to our current liquidity issues, we may enter into one or more transactions to sell a significant number of leases, both developed and undeveloped, to enable us to pay down our outstanding debt or satisfy other financial obligations.
Drilling Activity
The following table describes the development and exploratory wells we drilled from 2011 through 2013:
| | For the Year Ended December 31, | |
| | 2013 | | | 2012 | | 2011 | |
| | Gross | | Net | | | Gross | | | Net | | Gross | | Net | |
| | | | | | | | | | | | | | | |
| Development: | | | | | | | | | | | | | | |
| Productive wells | | | 2 | | | | 1 | | | | 5 | | | | 3 | | | | 3 | | | | 2.25 | |
| Dry wells | | | - | | | | - | | | | 1 | | | | 1 | | | | 1 | | | | 1 | |
| | | | 2 | | | | 1 | | | | 6 | | | | 4 | | | | 4 | | | | 3.25 | |
| Exploratory: | | | | | | | | | | | | | | | | | | | | | | | | |
| Productive wells | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | |
| Dry wells | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Total | | | 2 | | | | 1 | | | | 6 | | | | 4 | | | | 4 | | | | 3.25 | |
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, 2013 we had one horizontal well in progress in our North Wattenberg prospect.
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 term loans and Debentures, which we believe do not materially interfere with the use of, or affect the value of, such properties.
2014 Capital Budget
We anticipate an approximately $50.0 million capital budget for the year ending December 31, 2014. This entire capital budget is contingent on securing adequate working capital. We anticipate that approximately $33.0 million of this budget (if available) will be allocated toward the development of two unconventional reservoirs located in the Wattenberg field within the DJ Basin that will apply horizontal drilling in the well-defined Niobrara shale and Codell formations. The remainder of our capital budget is anticipated to be directed principally toward the conventional reservoir development of certain lower risk wells offset to existing production. We also anticipate the allocation of approximately 10% of our capital budget toward higher risk exploration activities, including the procurement of seismic data.
Our capital budget is subject to various factors, including availability of capital, market conditions, oilfield services and equipment availability, working interest, acquisitions, commodity prices and drilling/ production results. Results from the wells identified in the capital budget may lead to additional adjustments to the capital budget as the cash flow from the wells could provide additional capital which we may use to increase our capital budget. We do not anticipate any significant expansion of our current DJ Basin acreage position, however, the Wattenberg field continues to be a high priority acquisition target.
Other factors that could cause us to further increase our level of activity and adjust our capital expenditure budget include, but are not limited to, a reduction in service and material costs, the formation of joint ventures with other exploration and production companies, the divestiture of non-strategic assets, a further improvement in commodity prices or well performance that exceeds our forecasts, any of which could positively impact our operating cash flow. Factors that could cause us to reduce our level of activity and adjust our capital budget include, but are not limited to, increases in service and materials costs, reductions in commodity prices or under-performance of wells relative to our forecasts, any of which could negatively impact our operating cash flow.
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; 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, 2013, we had one hedging agreement in place, an active commodity swap for 100 barrels of oil per day through January 31, 2014 at a price of $99.25 per barrel.
Major Customers
During the years ended December 31, 2013 and 2012, the Company had one primary customer, Shell Trading (US), which accounted for approximately 83 percent and 67 percent, respectively, of our revenues. The remaining earned in both 2013 and 2012 was generated from various other purchasers.
However, the Company does not believe that the loss of a single purchaser, including Shell Trading (US), would materially affect the Company’s business because there are numerous other purchasers in the area in which the Company sells its production.
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.
Employees
As of December 31, 2013 we had eight full-time employees and no part-time employees. 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.
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).
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.
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 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. 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.
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 New Source Performance Standards (“NSPS OOOO”) in 2012, 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 fully 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.
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.
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.
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 Minerals Management Service, or MMS, 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, MMS prohibits deduction of costs associated with marketer fees, cash out and other pipeline imbalance penalties, or long-term storage fees. Further, the MMS 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 is currently conducting a rulemaking that will require, among other things, disclosure of chemicals and more stringent well integrity measures associated with hydraulic fracturing operations on public land. BLM has not indicated when it will issue a final rule. BLM 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.
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, 2013, our total outstanding debt under our credit agreements and convertible debentures equaled $34.35 million, including $18.77 million outstanding under our credit agreements with Hexagon. 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.
Currently, a significant portion of our revenue after field level operating expenses is required to be paid to our lenders as debt service. Assuming we are able to consummate the restructuring contemplated by the Hexagon Settlement, the terms of the Replacement Note with Hexagon require us to pay $90,000 per month in debt service, representing a significant portion of our monthly operating cash flow. If we fail to make any such minimum payments, Hexagon may declare a default and accelerate the amounts due. In that event, all of our debt may be declared to be in default. 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 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 $115.94 million and $106.22 million as of December 31, 2013 and 2012, 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 2014 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 eight employees at the end of December 31, 2013. 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, Chief Operating Officer, President, or Interim/Acting 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.
In addition to acquiring producing properties, we may also 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 may 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, 2013, 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.
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. |
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, 2013, we had one hedging agreement in place, an active commodity swap for 100 barrels of oil per day through January 31, 2014 at a price of $99.25 per barrel.
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, 2013, approximately 82% of our total proved reserves and 89% 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. 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 Operating Officer, Interim/Acting Chief Financial Officer, and geologist, 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.
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, 2013, and all of our 2013, 2012 and 2011 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.
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 in-house 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 agreements impose significant restrictions and requirements on us. Our three credit agreements contain 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 if we fail to maintain the effectiveness of a prior registration statement. We could default and accrue liquidated damages under registration rights agreements covering approximately 3,200,000 shares of Common Stock if we fail 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 of up to $0.23 million. The maximum aggregate liquidated damages are capped at $1.37 million. 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 we 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). |
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.
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. |
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 in which 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 will 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. |
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. |
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.
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. 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 and the State are challenging that ban—and the authority of local jurisdictions to regulate oil and gas development—in court. 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. 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.
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 final results expected by 2014. In addition, the U.S. Department of Energy is conducting an investigation into practices the agency could recommend to better protect the environment from drilling using hydraulic fracturing completion methods. The U.S. Department of the Interior is conducting a rule making, likely to result in new disclosure requirements and other mandates for hydraulic fracturing on federal lands. 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.
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; |
| | ● | 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.
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, 2013, approximately 9% of our Common Stock was held by Hexagon, and 6 other investors hold more than 5% each. Sales by Hexagon or our other 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.
There may be future dilution of our Common Stock. At June 1, 2014, we had outstanding options to purchase 14,636,424 shares of Common Stock exercisable at a weighted average exercise price of $7.24, warrants to purchase 18,233,049 shares of Common Stock exercisable at a weighted average exercise price of $5.24, and Debentures currently convertible into 3,665,859 shares of our Common Stock at a $2.00 conversion price (which include a full-ratchet anti-dilution provision that provides for the adjustment of the conversion price in the event we sell additional equity or convertible securities at a price that is below the $2.00 conversion price of the Debentures). In addition, on May 30, 2014 we entered into a settlement agreement pursuant to which we are committed to issuing 943,208 shares of Common Stock to Hexagon, and on June 6, 2014, TR Winston executed a commitment to purchase or effect the purchase by third parties of an additional $15 million in Preferred Stock.
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.
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.
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.
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.
| UNRESOLVED STAFF COMMENTS |
Not applicable.
Parker v. Tracinda Corporation, Denver District Court, Case No. 2011CV561. In November 2012, the Company filed a motion to intervene in garnishment proceedings involving Roger Parker, the Company’s former Chief Executive Officer and Chairman. The Defendant has served various writs of garnishment on the Company to enforce a judgment against Mr. Parker seeking, among other things, shares of unvested restricted stock. The Company has asserted rights to lawful set-offs and deductions in connection with certain tax consequences, which may be material to the Company. As a result of bankruptcy proceedings filed by Mr. Parker, the garnishment proceedings have been stayed. At this stage, we cannot express an opinion as to the probable outcome of this matter.
In re Roger A. Parker: Tracinda Corp. v. Recovery Energy, Inc. and Roger A. Parker, United States Bankruptcy Court for the District of Colorado, Case No. 13-10897-EEB. On June 10, 2013, Tracinda Corp. (“Tracinda”) filed a complaint (Adversary No. 13-01301 EEB) against the Company and Roger Parker in connection with the personal bankruptcy proceedings of Roger Parker, alleging that the Company improperly failed to remit to Tracinda certain property in connection with a writs of garnishment issued by the Denver District Court (discussed above). The Company filed an answer to this complaint on July 10, 2013. A trial date has not been set.
There are no other material pending legal proceedings to which we or our properties are subject.
Not applicable.
| 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 | |
| | | 2013 | |
| | | | | | | |
| Fourth Quarter | | $ | 2.74 | | | $ | 1.64 | |
| Third Quarter | | $ | 2.55 | | | $ | 1.49 | |
| Second Quarter | | $ | 1.88 | | | $ | 1.34 | |
| First Quarter | | $ | 2.35 | | | $ | 1.52 | |
| | | | | | | | | |
| | | 2012 | |
| | | | | | | | | |
| Fourth Quarter | | $ | 4.95 | | | $ | 1.40 | |
| Third Quarter | | $ | 4.75 | | | $ | 1.64 | |
| Second Quarter | | $ | 3.99 | | | $ | 2.25 | |
| First Quarter | | $ | 4.90 | | | $ | 2.31 | |
On June 1, 2014, there were approximately 78 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 of directors, 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.
Recent Sales of Unregistered Securities
The following issuances of the Company’s shares were made by the Company in 2013.
| Period | | Total shares purchased (1) | | | Weighted-average price paid per share | | | Total shares purchased as part of publicly announced plans or programs | | | Maximum number of shares that may yet be purchased under the plans or programs | |
| January 1, 2013 – January 31, 2013 | | | 100,000 | | | | (1 | ) | | | — | | | | — | |
| February 1, 2013 – February 28, 2013 | | | 129,202 | (2) | | $ | 2.09 | | | | — | | | | | |
| June 1, 2013 – June 30, 2013 | | | 1,000,000 | | | | (3 | ) | | | — | | | | — | |
| July 1, 2013 –July 31, 2013 | | | 162,283 | (2) | | $ | 1.71 | | | | — | | | | — | |
| August 1, 2013 – August 30, 2013 | | | 180,235 | (2) | | $ | 1.57 | | | | — | | | | — | |
| November 1, 2013 – November 30, 2013 | | | 164,562 | (2) | | $ | 1.84 | | | | — | | | | — | |
| (1) | Represents warrants issued as compensation under consulting agreements. The warrants have a strike price of $4.24 per share of Common Stock. |
| (2) | Represents shares issued as interest under the Debentures. |
| (3) | Represents 100,000 restricted shares of our Common Stock and 900,000 warrants with a strike price of $4.25, issued in connection with an investment banking agreement. |
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 other sales by us of our unregistered securities during 2013.
Not applicable.
| 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 Item “1A. Risk Factors.”
General
Lilis Energy, Inc. is an independent oil and gas company engaged in the acquisition, drilling and production of oil and natural gas properties and prospects within the Denver-Julesburg (“DJ”) Basin. Our business strategy is designed to create shareholder value by developing our undeveloped acreage and leveraging the knowledge, expertise and experience of our management team.
We principally target low to medium risk projects that have the potential for multiple producing horizons, and offer repeatable success allowing for meaningful production and reserve growth. Our acquisition and exploration pursuits of oil and natural gas properties are principally in Colorado, Nebraska, and Wyoming within the DJ Basin and, specifically, in the Greater Wattenberg field.
During the period ended March 31, 2014, the company generated the below unaudited financial results:
| | | Three months ended March 31, 2014 | |
| Revenues | | | |
| Oil sales | | $ | 700,087 | |
| Gas sales | | | 87,666 | |
| Operating fees | | | 34,728 | |
Realized gain on commodity price derivatives | | | 11,143 | |
| Total revenues | | | 833,624 | |
| | | | | |
| Costs and expenses | | | | |
| Production costs | | | | |
| Production taxes | | | 93,680 | |
| General and administrative | | | 3,343,052 | |
| Depreciation, depletion and amortization | | | 388,635 | |
| Total costs and expenses | | | 4,241,690 | |
| | | | | |
| Loss from operations | | | (3,408,066 | ) |
| | | | | |
| Other Income (expenses) | | | | |
| Other income | | | 53 | |
| Inducement expense | | | (6,165,475 | ) |
| Convertible notes conversion derivative gain (loss) | | | 1,150,000 | |
| Interest expense | | | (1,516,331 | ) |
| Total other expenses | | | (6,531,753 | ) |
| | | | | |
| Net loss | | $ | (9,939,819 | ) |
During the period ended March 31, 2014, the Company’s production information is as follows:
| | | For the Three Months Ended March 31, | |
| Product | | | | |
| Oil (Bbl.) | | | 8,455 | |
| Oil (Bbls)-average price (1) | | $ | 82.80 | |
| | | | | |
| Natural Gas (MCF)-volume | | | 10,997 | |
| Natural Gas (MCF)-average price (2) | | $ | 7.97 | |
| | | | | |
| Barrels of oil equivalent (BOE) | | | 10,288 | |
| Average daily net production (BOE) | | | 114 | |
| Average Price per BOE (1) | | $ | 76.58 | |
| (1) Does not include the realized price effects of hedges |
| (2) Includes proceeds from the sale of NGL's |
Financial Condition and Liquidity
Information about our year-end financial position is presented in the following table (in thousands):
| | | Year ended December 31, | |
| | | 2013 | | | 2012 | |
| Financial Position Summary | | | | | | |
| Cash and cash equivalents | | $ | 165 | | | $ | 970 | |
| Working capital (deficit) | | $ | (12,696 | ) | | $ | (1,041 | ) |
| Balance outstanding on term loans and convertible debentures payable | | $ | 34,511 | | | $ | 32,736 | |
| Shareholders’ equity | | $ | 5,518 | | | $ | 12,082 | |
As of December 31, 2013, the Company had $18.77 million outstanding under its term loans with Hexagon, LLC (“Hexagon”) and $15.58 million outstanding under its 8% Senior Secured Convertible Debentures (the “Debentures”). Both the term loans and the Debentures were to mature on May 16, 2014.
Since December 31, 2013, the Company has consummated the following transactions: (i) on January 22, 2014, the Company completed a private placement of units consisting of one share of Common Stock and one three-year warrant to purchase one share of Common Stock for aggregate gross proceeds of $5,918,250, plus an additional $1,425,000 in proceeds committed by certain officers and directors of the Company, which we expect to be funded upon our receipt of the required shareholder approval; (ii) on January 31, 2014, the Company entered into a Debenture Conversion Agreement, under which $9.0 million in Debentures was immediately converted to Common Stock at a price of $2.00 per common share; (iii) on May 19, 2014, the Company received extensions from both Hexagon and the remaining Debenture holders of the maturity dates under the Company’s term loans and Debentures, respectively, from May 16, 2014 to August 15, 2014; (iv) on May 30, 2014, the Company and Hexagon entered into an agreement providing for the settlement of all amounts outstanding under the term loans, in exchange for two cash payments of $5.0 million each to be made by the Company to Hexagon, as well as the issuance to Hexagon of a two-year $6.0 million unsecured 8% note and 943,208 shares of unregistered Common Stock; (v) on May 30, 2014 the Company consummated a private placement to accredited investors of 8% Convertible Preferred Stock and three-year warrants to purchase Common Stock equal to 50% of the number of shares issuable upon full conversion of the Preferred Stock for gross proceeds of $7.50 million; (vi) on June 6, 2014, the holders of the remaining Debentures agreed to further extend the maturity date under the Debentures from August 15, 2014 to January 15, 2015; and (vii) on June 6, 2014, TR Winston executed a commitment to purchase or effect the purchase by third parties of an additional $15 million in Preferred Stock, which transaction is to be consummated within ninety (90) days. The consummation of these transactions has been partially reflected in the Company’s balance sheet via the classification of certain portions of the Hexagon term loans and Debentures as long-term debt. Absent these transactions, all such debt would have otherwise been classified as current liabilities.
The closing of these transactions provided the Company with working capital for general corporate purposes, as well as a portion of the initial capital requirements to initiate further development activities on two of its Wattenberg prospects. However, the Company will require additional capital to satisfy its obligations to Hexagon under the settlement agreement, to fund its current drilling commitments and capital budget plans, to help fund its ongoing overhead, and to provide additional capital to generally improve its working capital position. We anticipate that such additional funding will be provided by a combination of capital raising activities, including the selling of additional debt and/or equity securities, the selling of certain assets and by the development of certain of the Company’s undeveloped properties via arrangements with joint venture partners. If we are not successful in obtaining sufficient cash sources to fund the aforementioned capital requirements, we may be required to curtail our expenditures, restructure our operations, sell assets on terms which may not be deemed favorable and/or curtail other aspects of our operations, including deferring portions of capital budget. There is no assurance that any such funding will be available to the Company.
Cash Flows
Cash used in operating activities during the year ended December 31, 2013 was $1.21 million. Use of cash coupled with the cash used in investing activities, exceeded cash provided by financing activities by $0.80 million, and resulted in a corresponding decrease in cash. This net use of cash contributed to a $1.65 million decrease in working capital as of December 31, 2013, compared to working capital as of December 31, 2012.
The following table compares cash flow items during the year ended December 31, 2013 to December 31, 2012 (in thousands):
| | Year ended December 31, | |
| | 2013 | | 2012 | |
| Cash provided by (used in): | | | | |
| Operating activities | | $ | (1,218 | ) | | $ | (3,389 | ) |
| Investing activities | | | (1,204 | ) | | | (1,405 | ) |
| Financing activities | | | 1,617 | | | | 3,056 | |
| Net change in cash | | $ | (805 | ) | | $ | (1,738 | ) |
During the year ended December 31, 2013, net cash used in operating activities was $1.22 million, compared to $3.39 million during the year ended December 31, 2012, a decrease of cash used in operating activities of $2.17 million, or 63%. The primary changes in operating cash during the year ended December 31, 2013 were $9.72 million of net loss, $0.18 million in a decrease in cash for other assets, offset by an increase of cash of $0.47 million for accounts receivable, $0.17 million for restricted cash, and $0.13 million in accounts payable and accrued expenses. The cash flows from operating activities were adjusted for non-cash charges of $2.39 million of depreciation, depletion, amortization and accretion expenses, $ 2.41 million of debt discount accretion, $0.68 million of amortization of deferred financing costs, $1.17 million issuance of stock for convertible debentures interest, $1.99 million for issuance of stock for services and compensation, and offset by a decrease in cash for a non-cash change in fair value of convertible debentures conversion option of $0.72 million.
During the year ended December 31, 2013, net cash used in investing activities was $1.20 million, compared to net cash used in investing activity of $1.41 million during the year ended December 31, 2012, a decrease of cash used in investing activities of $0.21 million, or 15%. The primary changes in investing cash during the year ended December 31, 2013 were an increase in cash of $0.64 million related to our sale of oil and gas properties which was offset by a decrease in cash of $1.40 million of drilling expenditures, and $0.40 million in expenditures related to additions to oil and gas properties.
During the year ended December 31, 2013, net cash provided by financing activities was $1.62 million, compared to net cash provided by financing activities of $3.06 million during the year ended December 31, 2012, a decrease of $1.44 million, or 47%. The changes in financing cash during the year ended December 31, 2013 were primarily due to proceeds from debt issuance of $2.18 million, which was partially offset by net repayments of debt of $0.56 million.
Capital Resources
The Company will require additional capital to fund its current capital obligations, capital budget plans, to help fund its ongoing. general and administrative and operating expenses and other cash requirements, and to provide additional capital to generally improve its working capital position. We anticipate that such additional funding will be provided by a combination of capital raising activities, including the selling of additional debt and/or equity securities, the selling of certain assets and by the development of certain undeveloped properties via arrangements with joint venture partners. If we are not successful in obtaining sufficient cash resources to fund the aforementioned capital requirements, we may be required to curtail our expenditures, restructure our operations, sell assets on terms which may not be deemed favorable and/or curtail other aspects of our operations, including deferring certain capital expenditures. There is no assurance that any such funding will be available to the Company.
During the year ended December 31, 2014, The Company has been provided three Joint Venture Authorization for Expenditure cash calls totaling $5.10 million by the operator of three horizontal wells in the North Wattenberg field. Per the terms of the JOA, if the Company does not generate enough capital from equity or debt raises, then the Company may be placed in non-pay status with the operator per a Notice of Default. Should this occur, after thirty days without cure, the operator may forward the Company a Notice of Non-Consent and will be imposed up to a 300% penalty to buy-back working interest in the new drilled wells.
Results of Operations
Year ended December 31, 2013 compared to the year ended December 31, 2012
The following table compares operating data for the fiscal year ended December 31, 2013 to December 31, 2012:
| | | Year ended December 31, | |
| | | 2013 | | | 2012 | |
| Revenue | | | | | | |
| Oil sales | | $ | 4,312,325 | | | $ | 5,898,459 | |
| Gas sales | | | 340,609 | | | | 406,216 | |
| Operating fees | | | 148,474 | | | | 174,779 | |
| Realized (loss) gain on commodity price derivatives | | | (17,572 | ) | | | 780,135 | |
| Unrealized (loss) gain on commodity price derivatives | | | 2,475 | | | | - | |
| Total revenues | | | 4,786,311 | | | | 7,259,589 | |
| | | | | | | | | |
| Costs and expenses | | | | | | | | |
| Production costs | | | 1,217,853 | | | | 1,421,177 | |
| Production taxes | | | 263,437 | | | | 227,455 | |
| General and administrative | | | 4,965,279 | | | | 4,331,328 | |
| Depreciation, depletion and amortization | | | 2,388,871 | | | | 4,549,303 | |
| Bad debt expense | | | - | | | | 77,957 | |
| Impairment of developed properties | | | - | | | | 26,658,707 | |
| Total costs and expenses | | | 8,835,440 | | | | 37,265,927 | |
| | | | | | | | | |
| Loss from operations | | | (4,049,129 | ) | | | (30,006,338 | ) |
| | | | | | | | | |
| Other income | | | 11,062 | | | | 5,896 | |
| Convertible notes conversion derivative gain | | | 730,000 | | | | 320,000 | |
| Interest expense | | | (6,410,996 | ) | | | (8,056,232 | ) |
| | | | | | | | | |
| Net Loss | | $ | (9,719,063 | ) | | $ | (37,736,674 | ) |
Total revenues
Total revenues were $4.79 million for the year ended December 31, 2013, compared to $7.26 million for the year ended December 31, 2012, a decrease of $2.47 million, or 34%. The decrease in revenues was due primarily to a decrease in production volumes. During the years ended December 2013 and 2012, production amounts were 62,513 and 98,567 BOE, respectively, a decrease of 36,054, or 37%. The decrease in production amounts were from several wells having an unusual amount of downtime from extreme weather and normal decline curves. The decrease was partially offset by an increase in overall average price per BOE to $74.43 in 2013 from $63.96 in 2012, an increase of $10.47 or 16%. Additionally, in 2013 the Company had decreases in realized gains from commodity price hedges and operating fees.
The following table shows a comparison of production volumes and average prices:
| | | For the Year Ended December 31, | |
| | 2013 | | 2012 | |
| Product | | | | | | |
| Oil (Bbl.) | | | 51,705 | | | | 68,207 | |
| Oil (Bbls)-average price (1) | | $ | 83.4 | | | $ | 86.48 | |
| | | | | | | | | |
| Natural Gas (MCF)-volume | | | 64,845 | | | | 182,160 | |
| Natural Gas (MCF)-average price (2) | | $ | 5.25 | | | $ | 2.23 | |
| | | | | | | | | |
| Barrels of oil equivalent (BOE) | | | 62,512 | | | | 98,567 | |
| Average daily net production (BOE) | | | 171 | | | | 270 | |
| Average Price per BOE (1) | | $ | 74.43 | | | $ | 63.96 | |
| (1) Does not include the realized price effects of hedges |
| (2) Includes proceeds from the sale of NGL's |
| Oil and gas production costs, production taxes, depreciation, depletion, and amortization |
| | | | | | | | | |
| Average Price per BOE(1) | | $ | 74.43 | | | $ | 63.96 | |
| Production costs per BOE | | | 19.48 | | | | 14.42 | |
| Production taxes per BOE | | | 4.21 | | | | 2.31 | |
| Depreciation, depletion, and amortization per BOE | | | 38.21 | | | | 46.15 | |
| Total operating costs per BOE | | $ | 61.90 | | | $ | 62.88 | |
| Gross margin per BOE | | $ | 12.53 | | | $ | 1.08 | |
| | | | | | | | | |
| Gross margin percentage | | | 17 | % | | | 2 | % |
| (1) Does not include the realized price effects of hedges |
Commodity Price Derivative Activities
Changes in the market price of oil can significantly affect our profitability and cash flow. In the past we have entered into various commodity derivative instruments to mitigate the risk associated with downward fluctuations in oil prices. These derivative instruments consisted exclusively of swaps. The duration and size of our various derivative instruments varies, and depends on our view of market conditions, available contract prices and our operating strategy.
As of December 31, 2013, the Company maintained an active commodity swap for 100 barrels of oil per day through January 31, 2014 at a price of $99.25 per barrel. Commodity price derivative realized losses were $0.01 million for the year ended December 31, 2013, compared to a realized gain of $0.78 million during the year ended December 31, 2012, a decrease in realized gains/losses of $0.79 million or 102%. Commodity price derivative unrealized gains were $0.02 million for the year ended December 31, 2013, compared to no unrealized gains during the year ended December 31, 2012, an increase in unrealized gains of $0.02 million or 100%.
Production costs
Production costs were $1.22 million during the year ended December 31, 2013, compared to $1.42 million for the year ended December 31, 2012, a decrease of $0.20 million, or 14%. Decrease in production costs in 2013 was from a decrease in the number of work overs, property improvements, and onsite work on productive wells. Production costs per BOE increased to $19.48 in 2013 from $14.42 in 2012, an increase of $5.06 per BOE, or 35%.
Production taxes
Production taxes were $0.26 million for the year ended December 31, 2013, compared to $0.23 million for the year ended December 31, 2012, an increase of $0.03 million, or 13%. Increase in production taxes was from a change in product mix per state. Currently, ad valorem, severance and conservation taxes range from 1% to 13% based on the state and county from which production is derived. Production taxes per BOE increased to $4.21 during the year ended December 31, 2013 from $2.31 during the year ended December 31, 2012, an increase of $1.90 or 82%.
General and administrative
General and administrative expenses were $4.97 million during the year ended December 31, 2013, compared to $4.33 million during the year ended December 31, 2012, an increase of $0.64 million, or 15%. Non-cash general and administrative items for the year ended December 31, 2013 were $2.09 million compared to income of $0.40 million during the year ended December 31, 2012, an increase in non-cash expense of $2.49 million, or 623%. In 2012, general and administrative included an adjustment to non-cash compensation expenses for our previous CEO for a net reduction in general and administrative expenses (non-cash compensation expense) of $3.16 million. The non-cash salary amount was offset by a decrease in non-cash consulting of $0.50 million and non-cash severance of $0.23 million. The cash general and administrative expenses were $2.88 million during the year ended December 31, 2013, compared to cash general and administrative expense of $4.47 million during the year ended December 31, 2012 a decrease of $1.59 million, or a decrease of 36%. The decrease in cash general and administrative expense was primarily a result of a reduction of employee count.
On November 15, 2012, Roger Parker retired from the Company as its Chief Executive Officer. At the time of his retirement, Mr. Parker had 1,350,000 shares of unvested Common Stock outstanding. As a result of his separation from the Company, it was deemed improbable that these shares would vest to Mr. Parker in his capacity as an employee of the Company due to the termination of employment; however, it was deemed probable that these shares will vest under his separation agreement. As a result, the Company reversed all of the compensation expense, in the amount of $6.75 million, associated with stock grants to Mr. Parker during his tenure as an employee. In conjunction with Mr. Parker’s retirement, the Company and Mr. Parker entered into a separation agreement that provided, in part, for the payment of severance equal to one year of Mr. Parker’s salary. Pursuant to the termination agreement, the 1,350,000 shares of unvested restricted stock that would otherwise have been forfeited upon his termination where scheduled to vest in two tranches, 675,000 on May 15, 2013, and the remaining 675,000 on November 15, 2013, subject to Mr. Parker’s execution of a mutual release, and Mr. Parker’s availability to the Company for a minimum of 10 hours per week during the severance period on a consulting basis. Thus, the Company recorded a consulting expense (in the amount of $3.59 million) related to the shares of stock that we expected to vest during the severance period of the separation agreement. The net difference of these two amounts resulted in a reduction in 2012 general and administrative expenses (non-cash compensation expense) of $3.16 million. Currently, the shares are still considered unvested, pending, among other things, the conclusion of the legal proceedings discussed in Part I, Item 3, “Legal Proceedings.”
Depreciation, depletion, and amortization
Depreciation, depletion, and amortization were $2.39 million during the year ended December 31, 2013, compared to $4.55 million during the year ended December 31, 2012, a decrease of $2.19 million, or 48%. Decrease in depreciation, depletion, and amortization was from our total proved undeveloped reserves increasing in 2013 to 1,047 MBOE from 175 MBOE in 2012. This increase of 872 MBOE or 498% reflects the current change in our expectations regarding whether we will have sufficient capital to support our current development plan. As a result of this change, the proved undeveloped reserves that were recorded on a promoted basis in 2012 were restored to normal levels in 2013 with additional horizontal drilling. The increase in reserves was also affected by a decrease in production to 62,513 BOE in 2013, from 98,567 BOE in 2012, a decrease of 36,054, or 37%. Depreciation, depletion, and amortization per BOE decreased to $38.21 from $46.15, respectively, for the years ended December 31, 2013 and 2012, a decrease of $7.94, or 17%.
Impairment of developed properties
During the year ended December 31, 2013, the Company did not impair any of its evaluated properties.
During the year ended December 31, 2012, the Company impaired evaluated properties of $26.66 million. The 2012 impairment was a result of capitalized costs exceeding the standardized measure of reserve values, and in particular was related to the impairment of undeveloped acreage and wells in progress related to the Company's Chugwater prospect, in the total amount of $17.09 million, which were transferred to the full cost pool. As a result of the Company’s review for impairment in its undeveloped acreage, the Company also transferred $5.94 million of undeveloped acreage costs relating principally to leases that have terms that expire throughout 2015 which the Company determined not to extend. Furthermore, the Company reduced the PV-10 of the proved undeveloped reserve acreage pursuant to an assumption that certain farm-outs and joint ventures arrangements would be required in order to finance development of certain reserve, which reduced the production amounts for such reserves to 25% of the Company’s 100% ownership. As a result, the ceiling test performed by the Company yielded an increased impairment. The combination of these impairments and the respective transfers to the full cost pool resulted in a total 2012 impairment expense of $26.66 million.
Interest Expense
Interest expense was $6.41 million during the year ended December 31, 2013, compared to $8.06 million during the year ended December 31, 2012, a decrease of $1.65 million, or 20%. Interest expense during December 31, 2013 and 2012, includes non-cash interest expense and amortization of the deferred financing costs, accretion of the convertible debentures payable discount, and convertible debentures interest paid in Common Stock of $4.04 million and $4.85 million, respectively. Cash interest expense was $2.37 million, during the year ended December 31, 2013, compared to cash interest expense of $3.2 million, during the year ended December 31, 2012, remained consistent due to the level of debt.
Off-Balance Sheet Arrangements
We do not have any off-balance sheet arrangements.
Capital Budget
We anticipate an approximate $50.0 million capital budget for the period that runs through the end of 2014. This entire capital budget is subject to the securing of adequate capital. Although we secured approximately $5.0 million via the January Private Placement and an additional $7.50 million via the May Private Placement, some of the proceeds from these transactions were applied to the payment and servicing of our debt. We anticipate that approximately $33.0 million of this budget will be allocated toward the exploitation of two unconventional reservoirs located in the Wattenberg field within the DJ Basin that will apply horizontal drilling in the Niobrara shale and Codell formations. The balance of our capital budget is anticipated to be directed principally toward the conventional reservoir developments including lower risk offset wells to existing production and higher risk exploration activities, which includes the procurement of seismic data.
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 as the cash flow from the wells could provide additional capital which we may use to increase our capital budget.
Other factors that could impact our level of activity and capital expenditure budget include, but are not limited to, a reduction or increase in service and material costs, the formation of joint ventures with other exploration and production companies, the divestiture of non-strategic assets. We do not anticipate any significant expansion of our current DJ Basin acreage position in the near term; however, we are targeting attractive Wattenberg acquisitions.
Overview of Our Business, Strategy, and Plan of Operations
We have acquired and developed a producing base of oil and natural gas proved reserves, as well as a portfolio of exploration and other undeveloped assets with conventional and non-conventional reservoir opportunities, with an emphasis on those with multiple producing horizons, in particular the Muddy “J” conventional reservoirs and the Niobrara shale and Codell resource plays. We believe these assets offer the possibility of repeatable year-over-year success and significant and cost-effective production and reserve growth. Our acquisition, development and exploration pursuits are principally directed at oil and natural gas properties in the DJ Basin in Colorado, Nebraska, and Wyoming. Since early 2010, we have acquired and/or developed 25 producing wells. As of December 31, 2013 we owned interests in approximately 126,000 gross (112,000 net) leasehold acres, of which 114,000 gross (100,000 net) acres are classified as undeveloped acreage and all of which are located in Colorado, Wyoming and Nebraska within the DJ Basin. We are primarily focused on our Wattenberg North and South Wattenberg Field assets which include attractive unconventional reservoir drilling opportunities in mature development areas with that offer low risk Niobrara and Codell formation productive potential. We also believe that our conventional reservoir development potential in our Silo- East, Hanson and Wilke/Lukassen well areas will yield competitive results. We expect to pursue an aggressive multi-well program.
Our intermediate goal is to create significant value via the investment of up to $50.0 million in our inventory of low and controlled-risk conventional and unconventional properties, while maintaining a low cost structure. To achieve this, our business strategy includes the following elements:
Pursuing the initial development of our Greater Wattenberg Field unconventional assets. We currently have two key unconventional reservoir properties located in the Greater Wattenberg field. We participated in the drilling of one non-operated horizontal well in our North Wattenberg asset during the fourth quarter of 2013, which was completed in the first quarter of 2014 and is now on post-frac production. We are also participating in three additional non-operated horizontal wells on this property that were drilled in the first quarter, 2014. We also plan to operate the drilling of two horizontal wells on our South Wattenberg property during the third quarter of 2014 in which we have a 50% working interest and a 25% working interest in two wells. Drilling activities on both properties will target the prolific and well established Niobrara and Codell formations. Subject to the securing of additional capital, we expect to participate in up to 18 wells in these two assets, with an expected investment that exceeds up to $26.0 million. As of June 1, 2014, the Company has participated in the following in the Watttenberg Field: 1) one horizontal well that is currently on-line, and 2) 3 horizontal wells that are drilled and commencing completion operations in 2nd Quarter 2014.
Extending the development of certain conventional prospects within our inventory of other DJ Basin properties. Subject to the securing of additional capital, we anticipate the expenditure of up to an additional $25.0 million in drilling and development costs on three of our DJ Basin assets where initial exploitation has yield positive results. Additional drilling activities will be conducted on each property in an effort to fully assess each property and define field productivity and economic limits.
Engaging in certain exploration activities, including geologic and geophysics projects, to define additional prospects within our inventory of DJ Basin properties that may have significant development upside. Subject to the securing of additional capital, we anticipate an expenditure of $2.0 to $5.0 million in 2014 to acquire seismic data on at least three key DJ Basin target areas to identify both conventional and unconventional drilling opportunities.
Controlling Costs. We seek to maximize our returns on capital employed by minimizing our production costs via prudent engineering and field management, and by closely monitoring general and administrative expenses. We also minimize initial capital expenditures on geological and geophysical overhead, seismic data, hardware and software by partnering with cost efficient operators that have already invested capital in such. We also outsource some of our technical functions in order to help reduce general and administrative and capital requirements.
From time to time, we use commodity price hedging instruments to reduce our exposure to oil and natural gas price fluctuations and to help ensure that we have adequate cash flow to fund our debt service costs and capital programs. From time to time, we will enter into futures contracts, collars and basis swap agreements, as well as fixed price physical delivery contracts. We intend to use hedging primarily to manage price risks and returns on certain acquisitions and drilling programs. Our policy is to consider hedging an appropriate portion of our production at commodity prices we deem attractive. In the future we may also be required by our lenders to hedge a portion of production as part of any financing.
Currently, our inventory of developed and undeveloped acreage includes approximately 12,000 net acres that are held by production, approximately 25,000 net acres, 61,000, 8,000 and 6,000 net acres that expire in the years 2014, 2015, 2016 and thereafter, respectively. Approximately 75% of our inventory of undeveloped acreage provides for extension of lease terms from two to five years, at the option of the Company, via payment of varying, but typically nominal, extension amounts. However, due to our current liquidity issues, we may enter into one or more transactions to sell a significant number of leases, both developed and undeveloped, to enable us to pay down our outstanding debt or satisfy other financial obligations.
The business of oil and natural gas property acquisition, exploration and development is highly capital intensive and the level of operations attainable by an oil and gas company is directly linked to and limited by the amount of available capital. Therefore, a principal part of our plan of operations is to raise the additional capital required to finance the exploration and development of our current oil and natural gas prospects and the acquisition of additional properties to balance our existing organic cash flow. We will need to raise additional capital to fund our exploration and development budget. We will seek additional capital through the sale of our securities, through debt and project financing, joint venture agreements with industry partners, and through sale of assets. Our ability to obtain additional capital through new debt instruments, project financing and sale of assets may be subject to the repayment of our existing obligations.
We intend to use the services of independent consultants and contractors to provide various professional services, including land, legal, environmental, technical, investor relations and tax services. We believe that by limiting our management and employee costs, we may be able to better control lifting costs and retain general and administrative flexibility.
Marketing and Pricing
We derive revenue principally from the sale of oil and natural gas. As a result, our revenues are determined, to a large degree, by prevailing prices for crude oil and natural gas. We sell our oil and natural gas on the open market at prevailing market prices or through forward delivery contracts. The market price for oil and natural gas is dictated by supply and demand, and we cannot accurately predict or control the price we may receive for our oil and natural gas.
Our revenues, cash flows, profitability and future rate of growth will depend substantially upon prevailing prices for oil and natural gas. Prices may also affect the amount of cash flow available for capital expenditures and our ability to borrow money or raise additional capital. Lower prices may also adversely affect the value of our reserves and make it uneconomical for us to commence or continue production levels of oil and natural gas. Historically, the prices received for oil and natural gas have fluctuated widely. Among the factors that can cause these fluctuations are:
| | ● | changes in global supply and demand for oil and natural gas; |
| | ● | the actions of the Organization of Petroleum Exporting Countries, or OPEC; |
| | ● | the price and quantity of imports of foreign oil and natural gas; |
| | ● | acts of war or terrorism; |
| | ● | political conditions and events, including embargoes, affecting oil-producing activity; |
| | ● | the level of global oil and natural gas exploration and production activity; |
| | ● | the level of global oil and natural gas inventories; |
| | ● | weather conditions; |
| | ● | technological advances affecting energy consumption; and |
| | ● | the price and availability of alternative fuels. |
From time to time, we will enter into hedging arrangements to reduce our exposure to decreases in the prices of oil and natural gas. Hedging arrangements may expose us to risk of significant financial loss in some circumstances including circumstances where:
| | ● | our production and/or sales of natural gas are less than expected; |
| | ● | payments owed under derivative hedging contracts come due prior to receipt of the hedged month’s production revenue; or |
| | ● | the counter party to the hedging contract defaults on its contract obligations. |
In addition, hedging arrangements may limit the benefit we would receive from increases in the prices for oil and natural gas. We cannot assure you that any hedging transactions we may enter into will adequately protect us from declines in the prices of oil and natural gas. On the other hand, where we choose not to engage in hedging transactions in the future, we may be more adversely affected by changes in oil and natural gas prices than our competitors who engage in hedging transactions.
Obligations and Commitments
We had the following contractual obligations and commitments as of December 31, 2013 (in thousands):
| | | Payments due by period | |
| Contractual obligations | | Total | | | Within 1 year | | | 1-3 years | | | 3-5 years | | | More than 5 years | |
| Secured debt | | $ | 18,774 | | | $ | 10,663 | | | $ | 8,111 | | | $ | - | | | $ | - | |
| Interest on secured debt | | | 716 | | | | 66 | | | | 650 | | | | - | | | | - | |
| Convertible debentures | | | 15,580 | | | | - | | | | 15,580 | | | | - | | | | - | |
| | | | | | | | | | | | | | | | | | | | | |
| Interest on convertible debentures | | | 468 | | | | 234 | | | | 234 | | | | - | | | | - | |
| Operating leases | | | 138 | | | | 118 | | | | 20 | | | | - | | | | - | |
| Total contractual cash obligations | | $ | 35,676 | | | $ | 11,081 | | | $ | 24,595 | | | $ | - | | | $ | - | |
As discussed in previous sections of this report, a significant portion of the secured debt listed above was refinanced and restructured in March 2014. Likewise, approximately $9.0 million of the convertible debentures were converted to Common Stock in January 2014, and the remainder is expected to convert upon securing shareholder approval.
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. Our most significant financial estimates are associated with our estimated proved oil and gas reserves, assessments of impairment imbedded in the carrying value of undeveloped acreage and proven properties, as well as valuation of Common Stock used in various issuances of Common Stock, options and warrants, and estimated derivative liabilities.
Oil and Natural Gas Reserves
We follow the full cost method of accounting. All of our oil and gas properties are located within the United States, and therefore all costs related to the acquisition and development of oil and gas properties are capitalized into a single cost center referred to as a full cost pool. Depletion of exploration and development costs and depreciation of production equipment is computed using the units-of-production method based upon estimated proved oil and gas reserves. Under the full cost method of accounting, capitalized oil and gas property costs less accumulated depletion and net of deferred income taxes may not exceed an amount equal to the present value, discounted at 10%, of estimated future net revenues from proved oil and gas reserves less the future cash outflows associated with the asset retirement obligations that have been accrued on the balance sheet plus the cost, or estimated fair value if lower, of unproved properties. Should capitalized costs exceed this ceiling, impairment would be recognized. Under the SEC rules, we prepared our oil and gas reserve estimates as of December 31, 2013, using the average, first-day-of-the-month price during the 12-month period ending December 31, 2013.
Estimating accumulations of gas and oil is complex and is not exact because of the numerous uncertainties inherent in the process. The process relies on interpretations of available geological, geophysical, engineering and production data. The extent, quality and reliability of this technical data can vary. The process also requires certain economic assumptions, some of which are mandated by the SEC, such as gas and oil prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The accuracy of a reserve estimate is a function of the quality and quantity of available data; the interpretation of that data; the accuracy of various mandated economic assumptions; and the judgment of the persons preparing the estimate.
We believe estimated reserve quantities and the related estimates of future net cash flows are the most important estimates made by an exploration and production company such as ours because they affect the perceived value of our company, are used in comparative financial analysis ratios, and are used as the basis for the most significant accounting estimates in our financial statements, including the quarterly calculation of depletion, depreciation and impairment of our proved oil and natural gas properties. Proved oil and natural gas reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future periods from known reservoirs under existing economic and operating conditions. We determine anticipated future cash inflows and future production and development costs by applying benchmark prices and costs, including transportation, quality and basis differentials, in effect at the end of each quarter to the estimated quantities of oil and natural gas remaining to be produced as of the end of that quarter. We reduce expected cash flows to present value using a discount rate that depends upon the purpose for which the reserve estimates will be used. For example, the standardized measure calculation requires us to apply a 10% discount rate. Although reserve estimates are inherently imprecise, and estimates of new discoveries and undeveloped locations are more imprecise than those of established proved producing oil and natural gas properties, we make considerable effort to estimate our reserves, including through the use of independent reserves engineering consultants. We expect that quarterly reserve estimates will change in the future as additional information becomes available or as oil and natural gas prices and operating and capital costs change. We evaluate and estimate our oil and natural gas reserves as of December 31 and quarterly throughout the year. For purposes of depletion, depreciation, and impairment, we adjust reserve quantities at all quarterly periods for the estimated impact of acquisitions and dispositions. Changes in depletion, depreciation or impairment calculations caused by changes in reserve quantities or net cash flows are recorded in the period in which the reserves or net cash flow estimate changes.
Oil and Natural Gas Properties—Full Cost Method of Accounting
We use the full cost method of accounting whereby all costs related to the acquisition and development of oil and natural gas properties are capitalized into a single cost center referred to as a full cost pool. These costs include land acquisition costs, geological and geophysical expenses, carrying charges on non-producing properties, costs of drilling and overhead charges directly related to acquisition and exploration activities.
Capitalized costs, together with the costs of production equipment, are depleted and amortized on the unit-of-production method based on the estimated gross proved reserves as determined by independent petroleum engineers. For this purpose, we convert our petroleum products and reserves to a common unit of measure.
Costs of acquiring and evaluating unproved properties are initially excluded from depletion calculations. This undeveloped acreage is assessed quarterly to ascertain whether impairment has occurred. When proved reserves are assigned or the property is considered to be impaired, the cost of the property or the amount of the impairment is added to the full cost pool and becomes subject to depletion calculations.
Proceeds from the sale of oil and natural gas properties are applied against capitalized costs, with no gain or loss recognized, unless the sale would alter the rate of depletion by more than 25%. Royalties paid, net of any tax credits received, are netted against oil and natural gas sales.
In applying the full cost method, we perform a ceiling test on properties that restricts the capitalized costs, less accumulated depletion, from exceeding an amount equal to the estimated undiscounted value of future net revenues from proved oil and natural gas reserves, as determined by independent petroleum engineers. The estimated future revenues are based on sales prices achievable under existing contracts and posted average reference prices in effect at the end of the applicable period, and current costs, and after deducting estimated future general and administrative expenses, production related expenses, financing costs, future site restoration costs and income taxes. Under the full cost method of accounting, capitalized oil and natural gas property costs, less accumulated depletion and net of deferred income taxes, may not exceed an amount equal to the present value, discounted at 10%, of estimated future net revenues from proved oil and natural gas reserves, plus the cost, or estimated fair value if lower, of unproved properties. Should capitalized costs exceed this ceiling, we would recognize impairment.
Revenue Recognition
The Company derives revenue primarily from the sale of produced natural gas and crude oil. The Company reports revenue as the gross amount received before taking into account production taxes and transportation costs, which are reported as separate expenses and are included in oil and gas production expense in the accompanying consolidated statements of operations. Revenue is recorded in the month the Company’s production is delivered to the purchaser, but payment is generally received between 30 and 90 days after the date of production. No revenue is recognized unless it is determined that title to the product has transferred to the purchaser. At the end of each month, the Company estimates the amount of production delivered to the purchaser and the price the Company will receive. The Company uses its knowledge of its properties, its historical performance, NYMEX and local spot market prices, quality and transportation differentials, and other factors as the basis for these estimates.
Share Based Compensation
The Company accounts for share-based compensation by estimating the fair value of share-based payment awards made to employees and directors, including stock options restricted stock grants, and employees stock purchases related to employee stock purchase plans, on the date of grant using an option-pricing model. The value of the portion of the award that is ultimately expected to vest is recognized as an expense ratably over the requisite service periods.
Derivative Instruments
Periodically, the Company entered into swaps to reduce the effect of price changes on a portion of our future oil production. We reflect the fair market value of our derivative instruments on our balance sheet. Our estimates of fair value are determined by obtaining independent market quotes as well as utilizing a valuation model that is based upon underlying forward curve data and risk free interest rates. Changes in commodity prices will result in substantially similar changes in the fair value of our commodity derivative agreements. We do not apply hedge accounting to any of our derivative contracts, therefore we recognize mark-to-market gains and losses in earnings currently.
| QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK |
Not applicable.
| 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.
| CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE |
None.
Evaluation of Disclosure Controls and Procedures
As of the end of the year covered by this Annual Report, management performed, with the participation of our Chief Executive Officer (“CEO”), and Acting Chief Financial Officer (“CFO”), an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures as defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act of 1934, as amended, or Exchange Act. Our disclosure controls and procedures are designed to ensure that information required to be disclosed in the reports we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to our management, including our CEO and CFO, to allow timely decisions regarding required disclosures. Based on this evaluation, our CEO and CFO have concluded that the Company’s disclosure controls and procedures were effective as of December 31, 2013.
Management’s Annual Report on Internal Control 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 under the supervision of the CEO and CFO, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles in the United States, or GAAP. A company’s internal control over financial reporting includes those policies and procedures that: (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the Company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with GAAP, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and directors of the Company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Company’s assets that could have a material effect on the consolidated financial statements.
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.
Our management, with the participation of our CEO and CFO, assessed the effectiveness of our internal control over financial reporting as of December 31, 2013. Management’s assessment of internal control over financial reporting was conducted using the criteria in Internal Control—Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission in 2012. Management concluded that, as of December 31, 2013, the Company’s internal control over financial reporting was effective.
Changes in Internal Control over Financial Reporting
There were no changes in our internal control over financial reporting during the quarter-ended December 31, 2013 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
None.
PART III
| DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE |
The following table sets forth the names, ages and positions of the persons who are our directors and executive officers as of June 5, 2014:
| Name | | Age | | Position |
| Abraham “Avi” Mirman | | 44 | | Chief Executive Officer |
| Robert A. “Bob” Bell | | 55 | | President and Chief Operating Officer, Director |
| Eric Ulwelling | | 36 | | Acting Chief Financial Officer |
| Nuno Brandolini | | 60 | | Chairman of the Board of Directors |
| D. Kirk Edwards | | 59 | | Director |
| Bruce B. White | | 60 | | Director |
| Timothy N. Poster | | 44 | | Director |
Abraham Mirman: Chief Executive Officer. Mr. Mirman has served as our Chief Executive Officer since April 2014, previously serving as our President since he joined the Company in September 2013. In addition, Mr. Mirman has served as the Managing Director, Investment Banking at T.R. Winston & Company, LLC since April 2013, and continues to devote a portion of his time to serving in that role. 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.
Eric Ulwelling: Interim Chief Financial Officer. Mr. Ulwelling, who was appointed to the position of Interim Chief Financial Officer in May 2014, joined the Company in 2012 as Controller. 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.
Robert A. Bell: President and Chief Operating Officer; Director. Mr. Bell was appointed to the position of President and Chief Operating Officer in April 2014, and has served as a member of our Board since February 2014. He has served as the President and Chief Executive Officer of Peak Operator LLC, a privately held heavy oil operator in Southern California, since October 2012, and continues to devote a portion of his time to serving in that role. Mr. Bell's career began in 1981 in technical and management roles with major oil companies including Exxon and Unocal through 1996. Mr. Bell progressed into both public and private, mid-cap and small-cap, oil and gas enterprise executive roles including vice president-exploitation/co-president of Plains E&P (PXP), president of Tri-Valley Oil & Gas (TIV), and vice-president of operations/co-owner of Bonanza Creek Oil & Gas (BCEI). He also gained valuable experience in service sector management roles including with Schlumberger. Mr. Bell's diverse engineering, management and executive experience is multi-disciplinary, global, spans large-scale developments to mature, marginal developments, and light oil, heavy oil and natural gas assets, and includes prior direct experience in the DJ Basin and unconventional reservoirs such as the Monterey and Bakken formations. Mr. Bell is a 1981 Petroleum & Natural Gas Engineering graduate from Penn State University. Mr. Bell has not held any other public company directorship positions in the past five years.
Director Qualifications:
| | ● | Leadership Experience – President and Chief Executive Officer of Peak Operator LLC. |
| | ● | Industry Experience – Multiple executive roles in both public and private, mid-cap and small-cap, oil and gas enterprises including vice president-exploitation/co-president of Plains E&P (PXP), president of Tri-Valley Oil & Gas (TIV), and vice-president of operations/co-owner of Bonanza Creek Oil & Gas (BCEI). |
Nuno Brandolini: Chairman of the Board of Directors. Mr. Brandolini was appointed to the board of directors in February 2014, and became chairman in April 2014. He is a general partner of Scorpion Capital Partners, L.P., a private equity firm. Prior to forming Scorpion Capital and its predecessor firm, Scorpion Holding, Inc., in 1995, Mr. Brandolini served as managing director of Rosecliff, Inc., a leveraged buyout fund co-founded by Mr. Brandolini in 1993. Mr. Brandolini served previously as a vice president in the investment banking department of Salomon Brothers, Inc., and a principal with the Batheus Group and Logic Capital, two venture capital firms. Mr. Brandolini began his career as an investment banker with Lazard Freres & Co. Mr. Brandolini is a director of Cheniere Energy, Inc. (NYSE MKT: LNG), a Houston-based company primarily engaged in LNG related businesses. Mr. Brandolini received a law degree from the University of Paris and an M.B.A. from the Wharton School.
Director Qualifications:
| | ● | Leadership Experience – Executive positions with several private equity firms, and board position with Cheniere Energy, Inc. |
| | ● | Industry Experience – Service on the board of Cheniere Energy, Inc., as well as personal investments in the oil and gas industry. |
Timothy N. Poster: Director. Mr. Poster joined our board of directors in June 2010. He has been executive vice president of strategy and development for Wynn Resorts (NASDAQ GS: WYNN) since September 2011. From August 2010 through September 2011 Mr. Poster was a partner in Fertitta Entertainment, a worldwide investment venture fund. From July, 2008 through August, 2010 he was senior vice president of strategy and development for Wynn Las Vegas, a subsidiary of Wynn Resorts. In 2000, Mr. Poster sold Travelscape.com, which he had founded and developed, to Expedia. In 2004, Mr. Poster acquired Golden Nugget Hotels & Casinos in Las Vegas and Laughlin, Nevada which he sold in 2005. Between selling the Golden Nugget in 2005 and joining Wynn Las Vegas in July 2008, Mr. Poster managed his investments. Mr. Poster received his bachelor's degree in finance from the University of Southern California in 1995.
Director Qualifications:
| | ● | Leadership Experience – Executive vice president for Wynn Resorts, former partner in Fertitta Entertainment, former owner of Golden Nugget Hotel & Casino, founder of Travelscape.com, Bachelors degree in finance from the University of Southern California. |
| | ● | Industry Experience – Personal investments in the oil and gas industry. |
Bruce B. White: Director. Mr. White joined our board in April 2012. He is currently a senior vice president of High Sierra Water Services, LLC and has served in that capacity since the purchase of Conquest Water Services, LLC by High Sierra in June 2011. Mr. White co-founded Conquest Water Services in 1993 and served as a co-managing partner to build that company into a DJ Basin service company. Mr. White has more than 25 years of experience operating in the DJ Basin, including exploration, drilling, development and other well operations, many of which were conducted through Conquest Oil Company, founded by White in 1984, which he continues to serve as president. White was also a founding member of the Denver Julesburg Petroleum Association, the predecessor to the Colorado Oil and Gas Association (COGA), and served as its president during 1987 and 1988. A veteran of the Vietnam War, Mr. White served in the Navy for six years; he attended Grossmont College in El Cajon, California.
Director Qualifications:
| | ● | Leadership Experience – Founder of Conquest Oil Company and Conquest Water Services; Senior Vice President of High Sierra Water Services |
| | ● | Industry Experience – Extensive experience in oil and gas development and services industries at the entities and in the capacities described above. |
D. Kirk Edwards: Director. Mr. Edwards joined our board in April 2012. Mr. Edwards is president of Las Colinas Energy Partners, LP, where he manages a diverse oil and gas royalty base, surface lands, and non-operated working interests in more than 9,000 wells located throughout the U.S. and the Gulf Coast of Mexico. He also serves as lead manager for Las Colinas Minerals, LP, MacLondon Royalty Company, MacLondon Energy, LP, Alexis Energy, LP, and Noelle Land & Minerals LLC. Mr. Edwards worked in various disciplines as a Petroleum Engineer including Field, Reservoir, and Drilling Engineer for Texaco, Inc. from 1981-1986. In 1987, he founded Odessa Exploration, Inc., an independent oil and gas company, which he sold to Key Energy Services, Inc. in 1993. He served as a director, executive vice president and in other capacities of Key Energy Services until 2001. Mr. Edwards is a past president of the Permian Basin Petroleum Association, and is a past director and former chairman of the board of the Federal Reserve Bank of Dallas’ El Paso Branch. Mr. Edwards received a Bachelor of Science degree in Chemical Engineering from the University of Texas at Austin in 1981, and is a registered Professional Engineer in the State of Texas.
Director Qualifications:
| | ● | Leadership Experience – President of Las Colinas Energy Partner, LP. Lead manager for Las Colinas Minerals, LP, MacLondon Royalty Company, MacLondon Energy, LP, Alexis Energy, LP, and Noelle Land & Minerals LLC. He served as a director, executive vice president and in other capacities of Key Energy Services until 2001. Mr. Edwards is a past president of the Permian Basin Petroleum Association, and is a past director and former chairman of the board of the Federal Reserve Bank of Dallas’ El Paso Branch. |
| | ● | Industry Experience – Extensive experience in oil and gas development and services industries at the entities and in the capacities described above. |
Directors hold office for a period of one year from their election at the annual meeting of stockholders and until a particular director’s successor is duly elected and qualified. Officers are elected by, and serve at the discretion of, our board of directors. None of the above individuals has any family relationship with any other. It is expected that our board of directors will elect officers annually following each annual meeting of stockholders.
Section 16(a) Beneficial Ownership Reporting Compliance
The executive officers and directors of the Company and persons who own more than 10% of the Company’s Common Stock are required to file reports with the SEC, disclosing the amount and nature of their beneficial ownership in Common Stock, as well as changes in that ownership. Based solely on its review of reports and written representations that the Company has received, the Company believes that all required reports were timely filed during 2013 and the portion of 2014 preceding the date of this Annual Report, except that filings under Section 16(a) with respect to the following transactions were not timely:
| | ● | The appointment of Eric Ulwelling as an executive officer of the Company on February 6, 2012, and the following grants to Mr. Ulwelling after such appointment: - 16,667 shares of Common Stock on February 6, 2012. - 16,667 shares of Common Stock on November 23, 2012. - 8,333 shares of Common Stock on May 6, 2013. - 25,000 shares of Common Stock on May 10, 2013. - 30,000 shares of Common Stock on October 16, 2013. - 6,500 shares of Common Stock on February 5, 2014. |
| | | |
| | ● | The following sales by Mr. Ulwelling: - 3,000 shares of Common Stock on May 22, 2013. - 5,000 shares of Common Stock on November 22, 2013. - 1,200 shares of Common Stock on December 5, 2013. |
| | | |
| | ● | The appointment of Abraham Mirman as an executive officer of the Company on September 16, 2013. |
| | | |
| | ● | The grant to Abraham Mirman on September 16, 2013 of 100,000 restricted shares of Common Stock. |
| | ● | The purchase by Abraham Mirman on January 31, 2014, of 110,861 shares of the Company’s common stock and 110,861 warrants to purchase Common Stock in connection with Mr. Mirman’s conversion of Debentures. |
| | | |
| | ● | The following grants to Bruce B. White: - On April 24, 2014 of 13,378 restricted shares of Common Stock. - On June 20, 2013 of 31,250 restricted shares of Common Stock. - On April 24, 2013 of 25,641 restricted shares of Common Stock. |
| | | |
| | ● | The grant to D. Kirk Edwards on June 20, 2013 of 31,250 restricted shares of Common Stock. |
| | | |
| | ● | The grant to W. Phillip Marcum on June 20, 2013 of 93,750 restricted shares of Common Stock. |
| | | |
| | ● | The grant to A. Bradley Gabbard on June 20, 2013 of 93,750 restricted shares of Common Stock. |
| | | |
| | ● | The grant to Timothy N. Poster on June 20, 2013 of 31,250 restricted shares of Common Stock. |
| | | |
| | ● | The purchase by A. Bradley Gabbard on June 18, 2013 of Debentures convertible into 51,292 shares of Common Stock. |
| | | |
| | ● | The purchase by W. Phillip Marcum on June 18, 2013 of Debentures convertible into 51,292 shares of Common Stock. |
| | | |
| | ● | The appointment of Nuno Brandolini and Robert A. Bell to the Board on February 13, 2014. |
The Board of Directors and Committees Thereof
Our board of directors conducts its business through meetings and through its committees. Our board of directors held 19 meetings in 2013. Each director attended at least 75% of the meetings of the Board held after such director’s appointment. Our policy regarding directors’ attendance at the annual meetings of stockholders is that all directors are expected to attend, absent extenuating circumstances.
Affirmative Determinations Regarding Director Independence and Other Matters
Our board of directors follows the standards of independence established under the rules of The NASDAQ Stock Market® (“NASDAQ”) in determining if directors are independent and has determined that four of our current directors, Timothy N. Poster, D. Kirk Edwards, Bruce B. White and Nuno Brandolini are “independent directors” under those rules. Robert A. Bell was an “independent director” prior to his appointment in April 2014 as our president and chief operating officer. No independent director receives, or has received, any fees or compensation from us other than compensation received in his or her capacity as a director. There were no transactions, relationships or arrangements not otherwise disclosed that were considered by the board of directors in determining that any of the directors are independent.
Committees of the Board of Directors
Pursuant to our amended and restated bylaws, our board of directors is permitted to establish committees from time to time as it deems appropriate. To facilitate independent director review and to make the most effective use of our directors’ time and capabilities, our board of directors has established an audit committee and a compensation committee. The membership and function of these committees are described below.
Compensation Committee
Our compensation committee currently consists of Mr. Edwards, Mr. Poster and Mr. White. Mr. Poster is chair of the compensation committee. The compensation committee met once during 2013, but on several occasions met separately in connection with a meeting of the full board, and acted by written consent thereafter. The compensation committee reviews, approves and modifies our executive compensation programs, plans and awards provided to our directors, executive officers and key associates. The compensation committee also reviews and approves short-term and long-term incentive plans and other stock or stock-based incentive plans. In addition, the committee reviews our compensation and benefit philosophy, plans and programs on an as-needed basis. In reviewing our compensation and benefits policies, the compensation committee may consider the recruitment, development, promotion, retention, compensation of executive and senior officers of the Company, trends in management compensation and any other factors that it deems appropriate. The compensation committee may engage consultants in determining or recommending the amount of compensation paid to our directors and executive officer. The compensation committee is governed by a written charter that is reviewed, and amended if necessary, on an annual basis. A copy of the charter is available on our website at www.lilisenergy.com under “Investors.”
Audit Committee
Our audit committee currently consists of Mr. Edwards, Mr. Poster and Mr. White. Mr. Edwards is currently the audit committee chair and meets the definition of an audit committee financial expert. The board has determined that each of Mr. Edwards, Mr. Poster and Mr. White is independent as required by NASDAQ for audit committee members. The audit committee is governed by a written charter that is reviewed, and amended if necessary, on an annual basis. A copy of the charter is available on our website at www.lilisenergy.com under “Investors.”
Communications with the Board of Directors
Stockholders may communicate with our board of directors or any of the directors by sending written communications addressed to the board of directors or any of the directors, Lilis Energy, Inc., 1900 Grant Street, Suite #720, Denver, CO 80203, Attention: Corporate Secretary. All communications are compiled by the corporate secretary and forwarded to the board or the individual director(s) accordingly.
Nomination of Directors
Our board of directors has not established a nominating committee because the board believes that it is unnecessary in light of the board’s small size. In the event that vacancies on our board of directors arise, the board considers potential candidates for director, which may come to the attention of the board through current directors, professional executive search firms, stockholders or other persons. Our board does not set specific, minimum qualifications that nominees must meet in order to be recommended as directors, but believes that each nominee should be evaluated based on his or her individual merits, taking into account the needs of the Company and the composition of our board. We do not have any formal policy regarding diversity in identifying nominees for a directorship, but consider it among the various factors relevant to any particular nominee. We do not discriminate based upon race, religion, sex, national origin, age, disability, citizenship or any other legally protected status. In the event we decide to fill a vacancy that exists or we decide to increase the size of the board, we identify, interview and examine appropriate candidates. We identify potential candidates principally through suggestions from our board and senior management. Our chief executive officer and board members may also seek candidates through informal discussions with third parties. We also consider candidates recommended or suggested by stockholders.
The board will consider candidates recommended by stockholders if the names and qualifications of such candidates are submitted in writing in accordance with the notice provisions for stockholder proposals set forth below under the caption “Stockholder Proposals” in this Annual Report to our corporate secretary, Lilis Energy, Inc., 1900 Grant Street, Suite #720, Denver, CO 80203, Attention: Corporate Secretary. The board considers properly submitted stockholder nominations for candidates for the board of directors in the same manner as it evaluates other nominees. Following verification of the stockholder status of persons proposing candidates, recommendations are aggregated and considered by the board and the materials provided by a stockholder to the corporate secretary for consideration of a nominee for director are forwarded to the board. All candidates are evaluated at meetings of the board. In evaluating such nominations, the board seeks to achieve the appropriate balance of industry and business knowledge and experience in light of the function and needs of the board of directors. The board considers candidates with excellent decision-making ability, business experience, personal integrity and reputation. Our management recommended our incumbent directors for election at our 2014 annual meeting. We did not receive any other director nominations.
Stockholder Proposals
Notice of any stockholder proposal that is intended to be included in the Company’s proxy statement and form of proxy for our 2015 annual meeting of stockholders must be received by our corporate secretary no later than 120 days prior to the date that is one year after the date we mail our 2014 proxy statement. Such notice must be in writing and must comply with the other provisions of Rule 14a-8 under the Securities Exchange Act of 1934. Any notices regarding stockholder proposals must be received by the Company at its principal executive offices at 1900 Grant Street, Suite #720, Denver, CO 80203, Attention: Corporate Secretary. In addition, if a stockholder intends to present a proposal at the 2014 annual meeting without including the proposal in the proxy materials related to that meeting, and if the proposal was not received by the deadline set forth in the 2013 proxy materials, then the proxy or proxies designated by our board of directors for the 2014 annual meeting may vote in their discretion on any such proposal any shares for which they have been appointed proxies without mention of such matter in the proxy statement or on the proxy card for such meeting.
Code of Ethics
Our board of directors has adopted a Code of Business Conduct and Ethics (the “Code”) that applies to all of our officers and employees, including our principal executive officer, principal financial officer, principal accounting officer or controller, and persons performing similar functions. The Code codifies the business and ethical principles that govern all aspects of our business. A copy of the Code is available on our website at www.lilisenergy.com under “Investor Relations” and “Corporate Governance.” We undertake to provide a copy of the Code to any person, at no charge, upon a written request. All written requests should be directed to: Lilis Energy, Inc., 1900 Grant Street, Suite #720, Denver, CO 80203, Attention: Corporate Secretary.
Board Leadership Structure
The board’s current leadership structure separates the positions of chairman and principal executive officer. The board has determined our leadership structure based on factors such as the experience of the applicable individuals, the current business and financial environment faced by the Company, particularly in view of its financial condition and industry conditions generally and other relevant factors. After considering these factors, we determined that separating the positions of chairman of the board and principal executive officer is the appropriate leadership structure at this time. The board is currently responsible for the strategic direction of the Company. The chief executive officer is currently responsible for the day to day operation and performance of the company. The board feels that this provides an appropriate balance of strategic direction, operational focus, flexibility and oversight.
The Board’s Role in Risk Oversight
It is management’s responsibility to manage risk and bring to the board’s attention any material risks to the company. The board has oversight responsibility for the Company's risk policies and processes relating to the financial statements and financial reporting processes and the guidelines, policies and processes for mitigating those risks.
Executive Compensation for Fiscal Year 2013
The compensation earned by our executive officers for fiscal 2013 consisted of base salary and long-term incentive compensation consisting of awards of stock grants.
Summary Compensation Table
The table below sets forth compensation paid to our executive officers for the 2013 and 2012 fiscal years.
| Name and Principal Position | | Year | | Salary | | | Bonus | | | | | | | | | | | | Total | |
| Abraham Mirman | | 2013 | | $ | 50,000 | | | $ | - | | | $ | 245,000 | | | $ | 804,400 | | | $ | 4,000 | | | $ | 1,103,400 | |
| (president from September 2013 to April 2014; chief executive officer from April 2014 to present) | | 2012 | | $ | - | | | $ | - | | | $ | - | | | $ | - | | | $ | - | | | $ | - | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| W. Phillip Marcum | | 2013 | | | 70,000 | | | | - | | | | 150,000 | | | | 261,873 | | | | 18,000 | | | | 499,873 | |
(chief executive officer)(4) | | 2012 | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 2013 | | | 70,000 | | | | - | | | | 150,000 | | | | 261,873 | | | | 18,000 | | | | 499,873 | |
(chief financial officer; president)(5) | | 2012 | | | 182,146 | | | | - | | | | 199,999 | | | | - | | | | 5,275 | | | | 387,420 | |
| (1) | Represents restricted stock awards under our EIP. The grant date fair values for restricted stock awards were determined by multiplying the number of shares awarded times the Company’s stock price on the date of grant. |
| (2) | The dollar amounts indicated represent the aggregate grant date fair value computed in accordance with FASB ASC Topic 718, excluding the effect of estimated forfeitures. |
| (3) | Reflects reimbursement of health insurance premiums. |
| (4) | Mr. Marcum resigned his positions with the Company effective as of April 18, 2014. |
| (5) | Mr. Gabbard resigned his positions with the Company effective as of May 16, 2014. |
Outstanding Equity Awards at Fiscal Year-End
| | | Option Awards | | | Stock Awards | | |
| Name | | Number of securities underlying unexercised option exercisable | | | Number of securities underlying options unexercisable | | | Equity incentive plan awards; Number of securities underlying unexercised unearned options | | | Option exercise price | | | Option expiration date | | | Number of shares or units of stock that have not vested | | | Market value of shares of units of stock that have not vested(3) | | | Equity incentive plan awards: Number of unearned shares, units or other rights that have not vested | | | Equity incentive plan awards: Market or payout value of unearned shares, units or other rights that have not vested | | |
| | | (#) | | | (#) | | | (#) | | | ($) | | | | | | (#) | | | ($) | | | (#) | | | ($) | | |
| Abraham Mirman | | | - | | | | - | | | | 2,000,000 | (1) | | $ | 2.45 | | | | (2 | ) | | | - | | | | - | | | | - | | | | - | |
| | | | | | | | | | | | 600,000 | (1) | | $ | 2.45 | | | | (2 | ) | | | | | | | | | | | | | | | | | |
| A. Bradley Gabbard | | | 100,000 | | | | 200,000 | (3) | | | - | | | $ | 1.60 | | | | - | | | | - | | | | - | | | | 93,750 | (4) | | $ | 150,000 | |
| W. Phillip Marcum | | | 100,000 | | | | 200,000 | (3) | | | - | | | $ | 1.60 | | | | - | | | | - | | | | - | | | | 93,750 | (5) | | $ | 150,000 | |
| (1) | Vesting is based on the achievement of certain performance metrics as set forth in Note 13 “Share Based and Other Compensation” of the financial statements included herewith. |
| (2) | Options expire upon the earlier of (a) five (5) years from the date they vest and become exercisable or (b) September 16, 2023. See Note 13 “Share Based and Other Compensation” of the financial statements included herewith for a discussion of the circumstances under which the options will vest. |
| (3) | Subject to vesting as follows: 100,000 were to vest on June 25, 2014 and 100,000 were to vest on June 25, 2015. Upon the termination of Mr. Gabbard’s employment on May 16, 2014, all unvested options held by Mr. Gabbard were terminated pursuant to the terms of the EIP. Pursuant to the Separation Agreement entered into in connection with the termination of Mr. Marcum’s employment, all unvested options held by Mr. Marcum vested immediately. |
| (4) | All 93,750 shares vested April 15, 2014. |
| (5) | Pursuant to the Separation Agreement entered into in connection with the termination of Mr. Marcum’s employment, all 93,750 shares were forfeited in exchange for a lump sum payment of $150,000. |
Employment Agreements and Other Compensation Arrangements
2012 Equity Incentive Plan (“EIP”)
Our Board and stockholders approved our 2012 Equity Incentive Plan (“EIP”) in August 2012. The EIP provides for grants of equity incentives to attract, motivate and retain the best available personnel for positions of substantial responsibility; to provide additional incentives to our employees, directors and consultants; and to promote the success and growth of our business. Equity incentives that may be granted under our EIP include: (i) incentive stock options qualified as such under U.S. federal income tax laws; (ii) stock options that do not qualify as incentive stock options; (iii) stock appreciation rights (“SARs”); (iv) restricted stock awards; (v) restricted stock units; and (vi) unrestricted stock awards.
Our compensation committee believes long-term incentive-based equity compensation is an important component of our overall compensation program because it:
| | ● | rewards the achievement of our long-term goals; |
| | ● | aligns our executives’ interests with the long-term interests of our stockholders; |
| | ● | aligns compensation with sustained long-term value creation; |
| | ● | encourages executive retention with vesting of awards over multiple years; and |
| | ● | conserves our cash resources. |
Our EIP is administered by our compensation committee, subject to the ultimate authority of our Board, which has full power and authority to take all actions and to make all determinations required or provided for under the EIP, including designation of grantees, determination of types of awards, determination of the number of shares of Common Stock subject an award and establishment of the terms and conditions of awards.
Under our EIP, originally 900,000 shares of our Common Stock were available for issuance. At the annual meeting of stockholders held on June 27, 2013, the Company’s stockholders approved an amendment to the EIP to increase the number of common shares available for grant under the EIP from 900,000 shares to 1,800,000 shares. At a special meeting of stockholders held on November 13, 2013, the stockholders approved an amendment to the EIP to increase the number of common shares available for grant under the EIP from 1,800,000 shares to 6,800,000 shares and to increase the number of common shares eligible for grant under the EIP in a single year to a single participant from 1,000,000 shares to 3,000,000 shares. The number of shares issued or reserved pursuant to our EIP is subject to adjustment as a result of certain mergers, exchanges or other changes in our Common Stock.
As of December 31, 2013, 118,801 shares were available for issuance under the EIP.
During 2013, the compensation committee made grants of restricted stock and stock options under the EIP, including those to our directors and named executive officers set forth in the table below, subject to the vesting requirements set forth below.
| Name | | Restricted Stock Grant Value | | | Stock Option Grant Value | |
| A. Bradley Gabbard | | $ | 150,000 | (1) | | $ | 261,873 | (4) |
| Abraham Mirman | | | 245,000 | (2) | | | 659,000 | (5) |
| W. Phillip Marcum | | $ | 150,000 | (3) | | $ | 261,873 | (4) |
| (1) | All 93,750 shares vested April 15, 2014. |
| (2) | These grants will vest, subject to performance thresholds detailed in his employment agreement. |
| (3) | Pursuant to the Separation Agreement entered into in connection with the termination of Mr. Marcum’s employment, all 93,750 shares were forfeited in exchange for a lump sum payment of $150,000. |
| (4) | Calculated using a grant date fair value of $0.872 per share. We calculated the grant date fair value using a Black-Scholes model. |
| (5) | Calculated using a grant date fair value of $0.3025 for 2,000,000 options, and $0.09 for 600,000 options, based on an independent valuation expert. See Note 13 “Share Based and Other Compensation” of the financial statements included herewith. |
Employment Agreements and Other Arrangements
Messrs. Marcum and Gabbard
The Company entered into Employment Agreements with Mr. Marcum and Mr. Gabbard on June 20, 2013. The Employment Agreements contemplated that each of Mr. Marcum and Mr. Gabbard would receive an annual salary of $220,000, of which $150,000 would be payable in periodic installments in accordance with the Company’s regular payroll practices, and $70,000 would be paid in lump sum at the end of then-current fiscal year, or, in the sole discretion of the Board, prorated over the one year period upon completion of a financing transaction. Each executive was eligible for a performance bonus in an amount up to 50% of annual base compensation payable on an annual basis and subject to determination by the compensation committee of the Board, based on the achievement by the Company of performance goals established by the compensation committee for the preceding fiscal year, which may include targets related to the Company’s earnings before interest, taxes, depreciation and amortization, hydrocarbon production level, and hydrocarbon reserve amounts. Each executive also received an incentive grant of 300,000 stock options with a fair market value exercise price (as defined in the EIP), with one-third vesting immediately and two-thirds vesting in two annual installments on each of the next two anniversaries of the grant date, in each case subject to approval by the shareholders of the Company. Such stock options were to vest 100% upon a termination of employment by the Company without cause, by the executive for good reason, upon a change of control of the Company or upon the death or disability of executive, provided that such vesting be subject to approval by the shareholders of the Company. Each executive was also eligible to participate in all incentive, retirement, profit-sharing, life, medical, dental, disability and other benefit plans and programs as are from time to time generally available to executives of the Company with comparable responsibilities, subject to the provisions of those programs. Any such benefits will be paid for by the Company. Upon a termination due to death or disability, a termination initiated by the executive for any reason except for good reason, or a termination initiated by the Company with cause, the Company’s obligation to pay any compensation or benefits ceases on the separation date. If the separation was initiated by the executive for good reason or by the Company for any reason other than cause, the Company would continue to pay the executive’s monthly salary as then in effect for a period equal to twelve (12) months commencing on the separation date.
As a result of the Company’s liquidity position, each of Mr. Marcum and Mr. Gabbard agreed to take 93,750 shares of Common Stock (based upon the closing price of $1.60 on June 24, 2013) in lieu of his respective base salary of $150,000 for 2013 (including amounts deferred to date), which shares were scheduled to vest on April 15, 2014.
On April 24, 2014, the Company entered into a separation agreement (the “Marcum Agreement”) with Mr. Marcum in connection with his departure from the Company. The Marcum Agreement provides, among other things, that, consistent with his resignation for good reason under his Employment Agreement, (i) the Company will pay him 12 months of severance through payroll continuation, in the gross amount of $220,000, less all applicable withholdings and taxes, (ii) that all stock options held by Mr. Marcum as of the time of his termination immediately vested, and (iii) that Mr. Marcum will remain eligible to receive any performance bonus granted by the Company to its senior executives with respect to Company and/or executive performance in 2013. In addition, the Marcum Agreement provides that the Company will pay Mr. Marcum $150,000 in accrued base salary for his service in 2013, less all applicable withholdings and taxes, in exchange for Mr. Marcum’s forfeiture of the 93,750 shares of unvested restricted Common Stock of the Company that was issued to Marcum in June 2013 in lieu of such base salary. Mr. Marcum may elect to apply amounts payable under the Marcum Agreement against his commitment to invest $125,000 in the Company’s previously disclosed private offering, upon shareholder approval of the participation of the Company’s officers and directors in that offering. The Marcum Agreement also contains certain mutual non-disparagement covenants, as well as certain mutual confidentiality, non-solicitation and non-compete covenants. In addition, Mr. Marcum and the Company each mutually released and discharged all known and unknown claims against the other and their respective representatives that they had or presently may have, including claims relating to Mr. Marcum’s employment. The Marcum Agreement effectively terminated the Employment Agreement entered into between Mr. Marcum and the Company.
Mr. Mirman
In connection with his appointment as the Company’s President, the Company entered into an Employment Agreement with Mr. Mirman (the “Mirman Agreement”) dated September 16, 2013. The Mirman Agreement provides, among other things, that Mr. Mirman would receive an annual salary of $240,000 which was deferred until the Company successfully consummated a financing of any kind of not less than $2 million in gross proceeds. Additionally, he was granted 100,000 shares of Common Stock, which vested immediately and are fully paid and non-assessable as an inducement for joining the Company. Mr. Mirman was granted an option to purchase 600,000 shares of Common Stock of the Company, at a strike price equal to the Company’s closing share price on the September 16, 2013, which become exercisable upon the date the Company receives gross cash proceeds or drawing availability of at least $30,000,000, measured on a cumulative basis and including certain restructuring transactions. Mr. Mirman was provided an incentive bonus package and an additional stock option grant, which will be granted once certain conditions specified in the Mirman Agreement are met.
Mr. Bell
In connection with his appointment as President and Chief Operating Officer, the Company entered into an employment agreement with Mr. Bell (the “Bell Agreement”), which has an initial term of three years, provides for an annual base salary of $240,000 subject to adjustment by the Company, as well as a signing bonus of $100,000 and 100,000 shares of Common Stock, subject to certain conditions set forth in the Bell Agreement. In addition, Mr. Bell will receive an equity incentive bonus consisting of a non-statutory stock option to purchase up to 1,500,000 shares of Common Stock and a cash incentive bonus of up to $1,000,000, both subject to Mr. Bell’s continued employment. In addition, Mr. Bell’s incentive bonuses are subject to the Company’s achievement of certain production thresholds set forth in the Bell Agreement. The Bell Agreement effectively terminates the Independent Director Appointment Agreement between Mr. Bell and the Company, effective as of March 1, 2014. Mr. Bell remained a member of the Board, but will no longer be considered a non-employee director.
Narrative Disclosure to Summary Compensation Table
Overview
The following Compensation Discussion and Analysis describes the material elements of compensation for the named executive officers identified in the Summary Compensation Table above. As more fully described below, the compensation committee reviews and recommends to the full board of directors the total direct compensation programs for our named executive officers. Our chief executive officer also reviews the base salary, annual bonus and long-term compensation levels for the other named executive officers.
Compensation Philosophy and Objectives
Our compensation philosophy has been to encourage growth in our oil and natural gas reserves and production, encourage growth in cash flow, and enhance stockholder value through the creation and maintenance of compensation opportunities that attract and retain highly qualified executive officers. To achieve these goals, the compensation committee believes that the compensation of executive officers should reflect the growth and entrepreneurial environment that has characterized our industry in the past, while ensuring fairness among the executive management team by recognizing the contributions each individual executive makes to our success.
Based on these objectives, the compensation committee has recommended an executive compensation program that includes the following components:
| | ● | a base salary at a level that is competitive with the base salaries being paid by other oil and natural gas exploration and production enterprises that have characteristics similar to the Company and could compete with the Company for executive officer level employees; |
| | ● | annual incentive compensation to reward achievement of the Company's objectives, individual responsibility and productivity, high quality work, reserve growth, performance and profitability and that is competitive with that provided by other oil and natural gas exploration and production enterprises that have some characteristics similar to the Company; and |
| | ● | long-term incentive compensation in the form of stock-based awards that is competitive with that provided by other oil and natural gas exploration and production enterprises that have some characteristics similar to the Company. |
As described below, the compensation committee periodically reviews data about the compensation of executives in the oil and gas industry. Based on these reviews, we believe that the elements of our executive compensation program have been comparable to those offered by our industry competitors.
Elements of Lilis’s Compensation Program
The three principal components of the Company’s compensation program for its executive officers, base salary, annual incentive compensation and long-term incentive compensation in the form of stock-based awards, are discussed below.
Base Salary.
Base salaries (paid in cash) for our executive officers have been established based on the scope of their responsibilities, taking into account competitive market compensation paid by our peer companies for similar positions. We have reviewed our executives’ base salaries in comparison to salaries for executives in similar positions and with similar responsibilities at companies that have certain characteristics similar to the Company. Base salaries are reviewed annually, and typically are adjusted from time to time to realign salaries with market levels after taking into account individual responsibilities, performance, experience and other criteria.
The compensation committee reviews with the chief executive officer his recommendations for base salaries for the named executive officers, other than himself, each year. New base salary amounts have historically been based on an evaluation of individual performance and expected future contributions to ensure competitive compensation against the external market, including the companies in our industry with which we compete. The compensation committee has targeted base salaries for executive officers, including the chief executive officer, to be competitive with the base salaries being paid by other oil and natural gas exploration and production enterprises that have some characteristics similar to the Company. We believe this is critical to our ability to attract and retain top level talent.
Long Term Incentive Compensation.
We believe the use of stock-based awards creates an ownership culture that encourages the long-term performance of our executive officers. Our named executive officers generally receive a stock grant upon becoming an employee of the Company. These grants vest over time.
Other Benefits.
All employees may participate in our 401(k) retirement savings plan (“401(k) Plan”). Each employee may make before tax contributions in accordance with the Internal Revenue Service limits. We provide this 401(k) Plan to help our employees save a portion of their cash compensation for retirement in a tax efficient manner. We make a matching contribution in an amount equal to 100% of the employee’s elective deferral contribution below 3% of the employee’s compensation and 50% of the employee’s elective deferral that exceeds 3% of the employee’s compensation but does not exceed 5% of the employee’s compensation.
All fulltime employees, including our named executive officers, may participate in our health and welfare benefit programs, including medical, dental and vision care coverage, disability insurance and life insurance.
Compensation of Directors
The table below sets forth the compensation earned by our non-employee directors during the 2013 fiscal year. There were no non-equity incentive plan compensation, stock options, change in pension value or any non-qualifying deferred compensation earnings during the 2013 fiscal year.
| Name | | Fees Earned or Paid in Cash Compensation | | | Stock Awards | | | Option Awards | | | All Other Compensation | | | Total | |
| Timothy N. Poster | | $ | - | | | $ | 90,000 | | | $ | 213,690 | | | $ | - | | | $ | 303,690 | |
| Bruce B. White | | $ | - | | | $ | 90,000 | | | $ | 213,690 | | | $ | - | | | $ | 303,690 | |
| D. Kirk Edwards | | $ | - | | | $ | 90,000 | | | $ | 213,690 | | | $ | - | | | $ | 303,690 | |
We have entered into independent director agreements with each of our non-employee directors. Pursuant to these agreements, we generally pay each of our non-employee directors’ annual cash compensation of $40,000 (payable quarterly), and an additional $10,000 per year (payable quarterly) to the chairman of each of our audit and compensation committees (currently Mr. Edwards and Mr. Poster, respectively). In 2013, our directors agreed to receive restricted shares of our common stock in lieu of their cash compensation, and for each director to receive restricted shares equal to $50,000 as of the date of grant (without regard to additional fees payable to the chairs of committees). Accordingly, the Company granted Mr. Poster, Mr. Edwards and Mr. White each 31,250 shares on June 20, 2013.
In addition, on each anniversary of the date an independent director was initially appointed to our board (June 1, 2010 for Mr. Poster, April 24, 2012 for Mr. White, and May 18, 2012 for Mr. Edwards), so long as such director continues to be an independent director on such date, we issue to such director a number of shares of our Common Stock equal to $40,000 divided by the most recent closing price per share prior to the date of each annual grant. These grants are fully vested upon issuance. Accordingly, the Company granted Mr. Poster 24,096 shares on June 3, 2013, granted Mr. Edwards 23,810 shares on May 20, 2013, and granted Mr. White 25,641 on April 24, 2013.
The agreements permit a director to engage in other business activities in the energy industry, some of which may be in conflict with the best interests of Lilis Energy, and also states that if a director becomes aware of a business opportunity, he has no affirmative duty to present or make such opportunity available to the Company, except as may be required by his fiduciary duty as a director or by applicable law.
Indemnification of Directors and Officers
Pursuant to our certificate of incorporation we provide indemnification of our directors and officers to the fullest extent permitted under Nevada law. We believe that this indemnification is necessary to attract and retain qualified directors and officers.
Narrative Disclosure of Compensation Policies and Practices as they Relates to Risk Management
In accordance with the requirements of Regulation S-K, Item 402(e), to the extent that risks may arise from our compensating policies and practices that are reasonably likely to have a material adverse effect on the Company, we are required to discuss these policies and practices for compensating our employees (including employees that are not named executive officers) as they relate to our risk management practices and the possibility of incentivizing risk-taking. We have determined that the compensation policies and practices established with respect to our employees are not reasonably likely to have a material adverse effect on the Company and, therefore, no such disclosure is necessary. The compensation committee and the board for directors are aware of the need to routinely assess our compensation policies and practices and will make a determination as to the necessity of this particular disclosure on an annual basis.
| SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS |
Securities Authorized for Issuance under Equity Compensation Plans
The following table represents the securities authorized for issuance under our equity compensation plans as of December 31, 2013.
| Equity Compensation Plan Information | |
| Plan category | | Number of securities to be issued upon exercise of outstanding options, warrants and rights | | | Weighted-average exercise price of outstanding options, warrants and rights | | | Number of securities remaining available for future issuance under equity compensation plans | |
| Equity compensation plans approved by security holders (1) | | | — | | | | — | | | | 1,208,384 | |
| Equity compensation plans not approved by security holders | | | 900,000 | (2) | | $ | 4.25 | | | | — | |
| Total | | | — | | | | — | | | | 1,208,384 | |
| (1) | Represents securities available for issuance under our EIP as of December 31, 2013. |
| (2) | Represents warrants issued to TR Winston in connection with an investment banking agreement. See Item 13 “Certain Relationships and Related Transactions, and Director Independence.” |
Security Ownership of Certain Beneficial Owners and Management
The following table sets forth certain information with respect to beneficial ownership of our Common Stock as of June 1, 2014 by each of our executive officers and directors and each person known to be the beneficial owner of 5% or more of the outstanding Common Stock. This table is based upon the total number of shares outstanding as of June 1, 2014 of 27,628,827. Unless otherwise indicated, the persons and entities named in the table have sole voting and sole investment power with respect to the shares set forth opposite the stockholder’s name, subject to community property laws, where applicable. Beneficial ownership is determined in accordance with Rule 13d-3 under the Securities Exchange Act of 1934, as amended. In computing the number of shares beneficially owned by a person or a group and the percentage ownership of that person or group, shares of our Common Stock subject to options or warrants currently exercisable or exercisable within 60 days after the date hereof are deemed outstanding by such person or group, but are not deemed outstanding for the purpose of computing the percentage ownership of any other person. Unless otherwise indicated, the address of each stockholder listed in the table is c/o Lilis Energy, 1900 Grant Street, Suite #720, Denver, CO 80203.
| Name and Address of Beneficial Owner | | Common Stock Held Directly | | | Common Stock Acquirable Within 60 Days | | | Total Beneficially Owned | | Percent of Class Beneficially Owned | |
| | | | | | | | | | | | | |
| Directors and Executive Officers | | | | | | | | | | |
| | | | | | | | | | | | | |
| Abraham Mirman, Chief Executive Officer | | | 310,861 | | | | 103,735 | | | | 414,596 | (1) | | | 1.49 | % |
| Robert A. Bell, President, Chief Operating Officer, and Director | | | 150,000 | | | | - | | | | 150,000 | (2) | | | 0.54 | % |
| Eric Ulwelling, Acting Chief Financial Officer | | | 93,967 | | | | - | | | | 93,967 | (3) | | | 0.34 | % |
| A. Bradley Gabbard, Former Chief Financial Officer | | | 484,010 | | | | 210,861 | | | | 694,871 | (4) | | | 2.50 | % |
| W. Phillip Marcum, Former Chief Executive Officer | | | 274,053 | | | | 410,861 | | | | 684,914 | (5) | | | 2.44 | % |
| Nuno Brandolini, Chairman | | | 175,000 | | | | 166,494 | | | | 341,494 | (6) | | | 1.23 | % |
| Timothy N. Poster, Director | | | 219,786 | | | | - | | | | 219,786 | | | | 0.80 | % |
| Bruce White, Director | | | 220,269 | | | | - | | | | 220,269 | (7) | | | 0.80 | % |
| D. Kirk Edwards, Director | | | 237,687 | | | | - | | | | 237,687 | (8) | | | 0.86 | % |
| Officers and directors as a group (nine persons) | | | 2,165,633 | | | | 891,951 | | | | 3,057,584 | | | | 10.72 | % |
| | | | | | | | | | | | | | | | | |
Pierre Calland Rutimatstrasse 16, 3780 Gstadd, Switzerland Tortola, British Virgin Islands | | | 3,879,724 | | | | 1,235,202 | | | | 5,114,926 | (9) | | | 17.72 | % |
Wallington Investment Holdings, Ltd. Trident Chambers P.O. Box 146, Road Town Tortola, British Virgin Islands | | | 3,310,984 | | | | 51,868 | | | | 3,362,852 | (10) | | | 12.15 | % |
G. Tyler Runnels 1999 Avenue of the Stars #2550 Los Angeles, CA 90067 | | | 1,818,109 | | | | 323,238 | | | | 2,141,347 | (11) | | | 7.66 | % |
Scott J. Reiman 730 17th Street, Suite 800 Denver, CO 80202 | | | 2,558,471 | | | | 0 | | | | 2,558,471 | (12) | | | 9.26 | % |
Hexagon, LLC 730 17th Street, Suite 800 Denver, CO 80202 | | | 2,250,000 | | | | 0 | | | | 2,250,000 | (13) | | | 8.14 | % |
Steven B. Dunn and Laura Dunn Revocable Trust DTD 10/28/10 16689 Schoenborn Street North Hills, CA 91343 | | | 2,379,686 | | | | 416,667 | | | | 2,796,353 | (14) | | | 9.97 | % |
| (1) | Includes (i) 110,861 shares of Common Stock held by The Bralina Group, LLC, in which Mr. Mirman has voting and dispositive power, (ii) 110,861 shares of Common Stock issuable upon exercise of warrants held by The Bralina Group, LLC, in which Mr. Mirman has voting and dispositive power, and (iii) 103,735 shares of Common Stock issuable upon conversion of the Company's Series A 8% Convertible Preferred Stock. |
| (2) | Includes 50,000 shares of Common Stock subject to future vesting. |
| (3) | Includes 75,389 shares of restricted Common Stock subject to future vesting. |
| (4) | Includes 100,000 shares of Common Stock issuable upon the exercise of stock options exercisable until August 14, 2014, and 110,861 shares of Common Stock issuable upon the exercise of warrants. Mr. Gabbard resigned from his positions as an officer and a director of the Company on May 16, 2014. |
| (5) | Includes 300,000 shares of Common Stock issuable upon the exercise of vested stock options exercisable until April 24, 2019, and 110,861 shares of Common Stock issuable upon the exercise of warrants. Mr. Marcum resigned from his positions as an officer and a director of the Company on April 18, 2014. |
| (6) | Includes (i) 50,000 shares of restricted Common Stock subject to future vesting, (ii) 125,000 shares of Common Stock issuable upon exercise of warrants, and (iii) 41,494 shares of Common Stock issuable upon conversion of the Company Series A 8% Convertible Preferred Stock. |
| (7) | Includes 16,667 shares of Common Stock subject to future vesting. |
| (8) | Includes 16,667 shares of Common Stock subject to future vesting. |
| (9) | Based upon information received from the shareholder. 3,310,984 shares of Common Stock are owned directly by Wallington Investment Holdings, Ltd. and indirectly by Mr. Pierre Caland, the holder of sole voting and dispositive power over such shares. 568,740 shares of Common Stock are owned directly by Silvercreek Investment Limited Inc. and indirectly by Mr. Caland, the holder of sole voting and dispositive power over such shares. Does not include (i) 1,027,506 shares of Common Stock issuable to Wallington upon the conversion of the remaining Debentures, with the right to convert being subject to shareholder approval, or (ii) 2,254,359 shares of Common Stock issuable upon the exercise of warrants, some of which are subject to conversion caps and some of which are not yet exercisable by their terms. |
| (10) | Does not include (i) 1,027,506 shares of Common Stock issuable upon the conversion of the remaining Debentures, with the right to convert being subject to shareholder approval, or (ii) 2,254,359 shares of Common Stock issuable upon the exercise of warrants, some of which are subject to conversion caps and some of which are not yet exercisable by their terms. |
| (11) | Includes (i) 952,090 shares held directly by TR Winston, of which Mr. Runnels is the majority owner, (ii) 1,025 shares held by G. Tyler Runnels directly, (iii) 15,000 shares held by G. Tyler Runnels through his self-directed 401(k) Plan, and (iv) 849,994 shares held by The Runnels Family Trust DTD 1-11-2000, of which Mr. Runnels, with Jasmine N. Runnels, is trustee. Does not include (i) 418,296 shares of Common Stock issuable to The Runnels Family Trust DTD 1-11-2000 upon the conversion of the remaining Debentures, with the right to convert being subject to shareholder approval, or (ii) 844,830 shares of Common Stock issuable to The Runnels Family Trust upon exercise of warrants, some of which are subject to conversion caps and some of which are not yet exercisable by their terms. |
| (12) | Based upon Schedule 13D filed with the SEC on June 5, 2014. Includes (i) 1,250,000 shares owned by Hexagon, LLC ("Hexagon"), (ii) 1,000,000 shares underlying warrants held by Hexagon, (iii) 129,008 shares owned by Labyrinth Enterprises LLC, which is controlled by Scott J. Reiman, (iv) 129,463 shares owned by Reiman Foundation, which is controlled by Scott J. Reiman and (v) 50,000 shares owned by Scott J. Reiman. Mr. Reiman is President of Hexagon. |
| (13) | Based upon Schedule 13D filed with the SEC on June 5, 2014. Includes (i) 1,250,000 shares owned by Hexagon, and (ii) 1,000,000 shares underlying warrants held by Hexagon. |
| (14) | Based upon information received from a representative of Steven B. Dunn and Laura Dunn. Includes (i) 2,205,768 shares owned by Steven B. Dunn and Laura Dunn Revocable Trust, (ii) 86,959 shares owned by Beau 8, LLC, and (iii) 86,959 shares owned by Winston 8, LLC. Steven B. Dunn and Laura Dunn are trustees of the Trust and also share voting and dispositive power with respect to the shares owned by the LLCs. Does not include (i) 500,000 shares of Common Stock issuable upon the conversion of the remaining Debentures, with the right to convert being subject to shareholder approval, or (ii) 925,223 shares of Common Stock issuable to the Steven B. Dunn and Laura Dunn Revocable Trust upon the exercise of warrants, some of which are subject to conversion caps and some of which are not yet exercisable by their terms. |
| CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE |
During fiscal years 2012 and 2013, we have engaged in the following transactions with related parties:
T.R. Winston & Company, LLC
On September 8, 2012, the Company issued 50,000 shares, valued at $0.23 million, to T.R. Winston & Company LLC (“TR Winston”) for acting as a placement agent of the Debentures issued on March 19, 2012, to certain existing debenture holders. The Company is amortizing the $0.23 million over the life of the loan as deferred financing costs. The Company amortized $0.13 million of deferred financing costs into interest expense during the year ended December 31, 2013, and has $0.22 million of deferred financing costs to be amortized through May 2014.
TR Winston and G. Tyler Runnels, its majority owner, also participated as investors in the Debentures, and purchased an aggregate of $1.41 million in Debentures between February 2011 and June 2013.
On April 15, 2013, the Company entered into an amendment of the Debentures to extend their maturity dates from February 8, 2014 to May 16, 2014. In consideration for the extended maturity date, the Company provided the holders of the Debentures an additional security interest in 15,000 acres of its undeveloped acreage.
On April 16, 2013, the Company entered into an agreement with a family trust controlled by Mr. Runnels to issue up to an additional $5.0 million in additional Debentures to existing Debenture holders, of which $1.5 million of would be issued on or before July 16, 2013. Between June 2013 through October 2013, the Company issued a total of $2.2 million in additional Debentures to existing Debenture holders. In November 2013, the Company paid TR Winston a commission of $40,000 in connection with the sale of these Debentures.
On May 10, 2013, the Company entered into a one-year, non-exclusive investment banking agreement with TR Winston. Among other things, the agreement provided for (i) initial compensation to TR Winston in the amount of 100,000 common shares, and three-year warrants to purchase up to 900,000 shares of the Company’s common stock at a strike price of $4.25 per share (the “Retainer Fee”), (ii) a cash fee equal to 5% of the gross proceeds of any equity financing involving solely the issuance of common stock, or 6% for all other equity issuances, (iii) a cash expense allowance equal to 1% of the gross proceeds of any equity financing, (iv) warrants to purchase common stock equal to either 4% of the shares of common stock issued in connection with an equity offering or 2% of the shares to be issued upon conversion of convertible equity in such offering, (v) 3% of the total gross proceeds of any non-revolving, non-convertible credit facility debt financing, (vi) 1% of the amount initially drawn at closing on any revolving credit line or facility, and (vii) 1% of the issuance price of any credit enhancement instrument, including on an insured or guaranteed basis. (See Note 12-Shareholders Equity.)
Under the investment banking agreement, in addition to the Retainer Fee, the Company paid TR Winston $40,000 in connection with the 2013 Debenture offerings, $576,570 in connection with the January 2014 Private Offering (paid in cash and restricted stock), and $225,000 (paid in 112,500 shares of restricted stock) in connection with the Debenture Conversion Agreement. TR Winston invested $0.17 million of these fees in the January Private Placement. The Company is obligated to pay TR Winston additional fees of $0.16 million upon shareholder approval of the participation of certain directors and officers in the January 2014 Private Placement and conversion of the remaining outstanding Debentures.
In September 2013, the Company appointed Abraham Mirman as its President. Prior to joining the Company, Mr. Mirman was employed by TR Winston as its Managing Director of Investment Banking and continues to devote a portion of his time to serving in that role. In connection with the appointment of Mr. Mirman, the Company and TR Winston amended the investment banking agreement to provide that, upon the receipt by the Company of gross cash proceeds or drawing availability of at least $30,000,000, measured on a cumulative basis and including certain restructuring transactions, subject to the Company’s continued employment of Mr. Mirman, TR Winston would receive from the Company a lump sum payment of $1 million. Mr. Mirman’s compensation arrangements with TR Winston provide 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. Mr. Mirman also received, as part of his compensation arrangement with TR Winston, the 100,000 common shares of the Company that were issued to TR Winston in conjunction with the investment banking agreement.
January 22, 2014, the Company paid TR Winston a commission equal to $486,000 (equal to 8% of gross proceeds at the closing of the January Private Placement). Of this $486,000 commission, $313,750 was paid in cash and $172,250 was paid in 86,125 Units. In addition, the Company paid TR Winston a non-accountable expense allowance of $182,250 (equal to 3% of gross proceeds at the closing of the January Private Placement) in cash. If the participation of certain of the Company’s current and former officer and directors is approved by the Company’s shareholders, the Company will pay TR Winston a commission equal to $114,000 (equal to 8% of gross proceeds of the Units members of the Company’s officers and board of directors agreed to purchase in the January Private Placement) in 57,000 Units, and the Company will pay TR Winston a non-accountable expense allowance of $42,750 (equal to 3% of gross proceeds of the Units members of the Company’s officers and board of directors agreed to purchase in the January Private Placement) in 21,375 Units. The Units issued to TR Winston were the same Units sold in the January Private Placement and were invested in the January Private Placement.
January 31, 2014, the Company paid TR Winston a commission equal to $450,000 (equal to 5% of the amount of Debentures converted pursuant to the Conversion Agreement) in the form of Common Stock at a price of $2.00 per share. In addition, the Company agreed to pay TR Winston a 5% fee on the conversion of any additional Debentures converted pursuant to the Conversion Agreement, payable in Common Stock at a price of $2.00 per share.
On March 28, 2014, the Company and TR Winston entered into a Transaction Fee Agreement in connection with the May Private Placement, pursuant to which the Company agreed to compensate TR Winston 5% of the gross proceeds of the May Private Placement, plus a $25,000 expense reimbursement. On April 29, 2014, the Company and TR Winston amended the Transaction Fee Agreement to increase TR Winston’s compensation to 8% of the gross proceeds, plus an additional 1% of the gross proceeds as an expense reimbursement in addition to the $25,000 originally contemplated.
On May 19, 2014, the Company and the holders of the Debentures agreed to extend the maturity date under the Debentures until August 15, 2014, and on June 6, 2014, they agreed to further extend the maturity date under the Debentures from August 15, 2014 to January 15, 2015.
On May 30, 2014, the Company paid TR Winston a commission equal to $600,000 (equal to 8% of gross proceeds at the closing of the May Private Placement). Of this $600,000 commission, $51,850 was paid in cash to TR Winston, $94,150 was paid in cash to other brokers designated by TR Winston, and $454,000 was paid in shares of Preferred Stock. In addition, the Company paid TR Winston a non-accountable expense allowance of $75,000 (equal to 1% of gross proceeds at the closing of the May Private Placement) in cash.
June 6, 2014, TR Winston executed a commitment to purchase or effect the purchase by third parties of an additional $15 million in Preferred Stock, which transaction is to be consummated within ninety (90) days.
G. Tyler Runnels, the majority owner of TR Winston, beneficially holds more than 5% of the Company’s Common Stock, including the holdings of TR Winston and his personal holdings. Mr. Mirman, the Company’s Chief Executive Officer and former President, has served as the Managing Director, Investment Banking at TR Winston since April 2013, and continues to devote a portion of his time to serving in that role.
Hexagon
Hexagon, the Company’s primary lender, also holds over 5% of the Company’s common stock. On April 15, 2013, the Company and Hexagon agreed to amend the term loans to extend their maturity dates to May 16, 2014. Pursuant to the amendment, Hexagon agreed to (i) reduce the interest rate under the term loans from 15% to 10% beginning retroactively with March 2013, (ii) permit the Company to make interest-only payments for March, April, May, and June 2013, after which time the minimum secured term loan payment became $0.23 million, and (iii) forbear from exercising its rights under the term loan credit agreements for any breach that may have occurred prior to the amendment. In consideration for the extended maturity date, the reduced interest rate and minimum loan payment under the secured term loans, the Company provided Hexagon an additional security interest in 15,000 acres of its undeveloped acreage. (See Note 8-Loan Agreements.)
On May 19, 2014, the Company and Hexagon agreed to amend the term loans to extend their maturity dates to August 15, 2014, and agreed in principal to the settlement of all amounts outstanding under the term loans.
In addition, Hexagon and its affiliates have interests in certain of the Company’s wells independent of Hexagon’s interests under the term loans, for which Hexagon or its affiliates receive revenue and joint-interest billings.
Officers and Directors of the Company
Certain of the Company’s directors and officers participated or committed to participate, directly and indirectly, as investors in the 2013 Debenture offerings, for an aggregate investment of $653,970.
On January 22, 2014, members of the Company’s officers and board of directors agreed to purchase $1,4250,000 of the Units offered in the January Private Placement subject to receipt of shareholder approval as required by the Company’s listing with NASDAQ.
On January 31, 2014, the Company entered into the Conversion Agreement with the holders of the Debentures, including The Bralina Group, LLC, in which Mr. Mirman has voting and dispositive power, W. Phillip Marcum, the Company’s then Chief Executive Officer, and A. Bradley Gabbard, the Company’s then Chief Financial Officer, pursuant to which, among other things, the parties agreed to convert $9 million of the approximately $15.8 million in outstanding principal and accrued and unpaid interest into shares of Common Stock at an exchange price of $2.00 per share. Each holder of the Debentures received one warrant to purchase one share of Common Stock at an exercise price equal to $2.50 per share for each share of Common Stock so issued.
On May 19, 2014, the Company and the holders of the Debentures agreed to extend the maturity date under the Debentures until August 15, 2014, and on June 6, 2014, they agreed to further extend the maturity date under the Debentures from August 15, 2014 to January 15, 2015.
Employment Agreements with Officers
See “Employment Agreements and Other Arrangements” above.
Compensation of Directors
See “Compensation of Directors” above.
Conflict of Interest Policy
The Board of Directors has recognized that transactions between the Company and certain related persons present a heightened risk of conflicts of interest. We have a corporate conflict of interest policy that prohibits conflicts of interests unless approved by the board of directors. Our board of directors has established a course of conduct whereby it considers in each case whether the proposed transaction is on terms as favorable or more favorable to the Company than would be available from a non-related party. Our board also looks at whether the transaction is fair and reasonable to us, taking into account the totality of the relationships between the parties involved, including other transactions that may be particularly favorable or advantageous to us. Each of the related party transactions described above was presented to our board of directors for consideration and each of these transactions was unanimously approved by our board of directors after reviewing the criteria set forth in the preceding two sentences.
Director Independence
Our Board of Directors has determined that each of Bruce B. White, Kirk D. Edwards, Timothy N. Poster and Nuno Brandolini qualifies as an independent director under rules promulgated by the SEC and NASDAQ listing standards, and has concluded that none of these directors has a material relationship with the Company that would interfere with the exercise of independent judgment in carrying out the responsibilities of a director.
| PRINCIPAL ACCOUNTING FEES AND SERVICES |
Hein & Associates LLP became our independent registered public accounting firm on January 19, 2010. There were no disagreements in 2012 or 2013 on any matter of accounting principles or practices, financial statement disclosures or auditing scope or procedures.
The following table sets forth fees billed by our principal accounting firm of Hein & Associates LLP for the years ended December 31, 2012 and 2013:
| | | Year Ended December 31, | |
| | | 2013 | | | 2012 | |
| Audit Fees | | $ | 205,000 | | | $ | 175,000 | |
| Audit Related Fees | | | - | | | | - | |
| Tax Fees | | | 12,000 | | | | 12,000 | |
| All Other Fees | | | - | | | | - | |
| | | $ | 217,000 | | | $ | 187,000 | |
Audit Fees. Fees for audit services consisted of the audit of our annual financial statements and reports on internal controls required by the Sarbanes-Oxley Act of 2002 and reviews of our quarterly financial statements.
Audit Related Fees. Fees billed for audit related services related to professional services rendered by Hein & Associates for assurance and related services that are reasonably related to the performance of the audit or review of our financial statements but are not included in audit fees above.
Tax Fees. Fees for tax services consisted of tax preparation.
Audit Committee Pre-Approval Policy
The Company’s independent registered public accounting firm may not be engaged to provide non-audit services that are prohibited by law or regulation to be provided by it, nor may the Company’s independent registered public accounting firm be engaged to provide any other non-audit service unless it is determined that the engagement of the principal accountant provides a business benefit resulting from its inherent knowledge of the Company while not impairing its independence. Our Audit Committee must pre-approve permissible non-audit services. During fiscal year 2013, our Audit Committee approved 100% of the non-audit services provided by its independent registered public accounting firm.
| EXHIBITS AND FINANCIAL STATEMENT SCHEDULES |
INDEX TO FINANCIAL STATEMENTS
a)
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.
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: June 11, 2014 | 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 and the capacities and on the dates indicated.
| Signature | | Title | | Date |
| | | | | |
| /s/ Abraham Mirman | | Chief Executive Officer | | June 11, 2014 |
| Abraham Mirman | | (Principal Executive Officer) | | |
| | | | | |
| /s/ Eric Ulwelling | | Interim/Acting Chief Financial Officer and Chief Accounting Officer, | | June 11, 2014 |
| Eric Ulwelling | | (Principal Financial Officer) | | |
| | | | | |
| /s/ Robert A. Bell | | Director , Chief Operating Officer, and President | | June 11, 2014 |
| Robert A. Bell | | | | |
| | | | | |
| /s/ Timothy N. Poster | | Director | | June 11, 2014 |
| Timothy N. Poster | | | | |
| | | | | |
| /s/ D. Kirk Edwards | | Director | | June 11, 2014 |
| D. Kirk Edwards | | | | |
| | | | | |
| /s/ Bruce B. White | | Director | | June 11, 2014 |
| Bruce B. White | | | | |
| | | | | |
| /s/ Nuno Brandolini | | Director | | June 11, 2014 |
| Nuno Brandolini | | | | |
Exhibit Index
The following exhibits are either filed herewith or incorporated herein by reference:
| 2.1 | Membership Unit Purchase Agreement by and among Recovery Energy, Lanny M. Roof, Judith Lee and Michael Hlvasa dated as of September 21, 2009 (incorporated herein by reference to Exhibit 10.1 from our current report filed on Form 8-K filed on September 22, 2009). |
| 3.1 | Amended and Restated Articles of Incorporation (incorporated herein by reference to Exhibit 3.1 from our current report filed 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 our current report filed 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). |
| 4.1 | Warrant to Purchase Common Stock dated December 11, 2009 (incorporated by reference to Exhibit 4.2 to the Company’s current report filed on Form 8-K filed on December 17, 2009). |
| 4.2 | Form of Warrant (incorporated by reference to Exhibit 4.1 to the Company’s current report filed on Form 8-K on January 28, 2014). |
| 4.3 | Form of Warrant (incorporated by reference to Exhibit 4.1 to the Company’s current report filed on Form 8-K on February 6, 2014). |
| 4.4 | Warrant to Purchase Common Stock of Recovery Energy, Inc. issued to Hexagon Investments, LLC dated April 14, 2010 (incorporated herein by reference to Exhibit 10.4 to the Company’s current report filed on Form 8-K filed on April 20, 2010). |
| 4.5 | Form of Warrant Issued in Private Placement (incorporated herein by reference to Exhibit 4.1 to the Company’s current report filed on Form 8-K filed on June 4, 2010). |
| 4.6 | Warrant to Purchase Common Stock of Recovery Energy, Inc. issued to Hexagon Investments, LLC (incorporated herein by reference to Exhibit 4.2 to the Company’s current report filed on Form 8-K filed on June 4, 2010). |
| 4.7 | Five Year Warrant to Market Development Consulting Group, Inc. (incorporated herein by reference to Exhibit 10.2 to the Company’s current report filed on Form 8-K filed on June 18, 2010). |
| 4.8 | Three Year Warrant to Market Development Consulting Group, Inc. (incorporated herein by reference to Exhibit 10.3 to the Company’s current report filed on Form 8-K filed on June 18, 2010). |
| 4.9 | Warrant to Globe Media (incorporated herein by reference to Exhibit 10.4 to the Company’s current report filed on Form 8-K filed on June 18, 2010). |
| 4.10 | Form of $2.20 Warrant Issued to Persons Exercising $1.50 Warrants (incorporated herein by reference to Exhibit 10.1 to the Company’s current report on Form 8-K filed on October 8, 2010). |
| 4.11 | Warrant Issued to Hexagon Investments, LLC on January 1, 2011 (incorporated herein by reference to Exhibit 10.1 to the Company’s current report on Form 8-K filed on January 4, 2011). |
| 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 filed 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 filed 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 filed 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 filed on Form 8-K filed on March 4, 2010). |
| 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 filed 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 filed 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 filed 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 filed 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 filed 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 filed on Form 8-K filed on April 20, 2010). |
| 10.11 | Wyoming Mortgage to Hexagon Investments, LLC dated April 14, 2010 (incorporated herein by reference to Exhibit 10.5 to the Company’s current report filed on Form 8-K filed on April 20, 2010). |
| 10.12 | Letter Agreement with Hexagon Investments, LLC (incorporated herein by reference to Exhibit 10.4 to the Company’s current report filed on Form 8-K filed on June 4, 2010). |
| 10.13 | Registration Rights Agreement with Hexagon Investments, Inc. (incorporated herein by reference to Exhibit 10.5 to the Company’s current report filed 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 filed 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 filed on Form 10-K 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. |
| 10.19 | Third Amendment to Credit Agreement (Second Credit Agreement), dated November 8, 2012. |
| 10.20 | Third Amendment to Credit Agreement (Third Credit Agreement), dated November 8, 2012. |
| 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). |
| 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). |
| 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). |
| 10.24 | First Amendment to Nebraska Mortgage to Hexagon, LLC, dated March 1, 2013. |
| 10.25 | Wyoming Mortgage to Hexagon, LLC, dated March 1, 2013. |
| 10.26 | Form of Securities Purchase Agreement (incorporated herein by reference to Exhibit 10.1 to the Company’s current report filed 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 filed on Form 8-K filed on June 4, 2010). |
| 10.28 | Consulting Agreement with Market Development Consulting Group, Inc. dated January 17, 2014. |
| 10.29 | 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). |
| 10.30 | 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). |
| 10.31 | 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). |
| 10.32 | 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 filed on Form 10-K on March 21, 2012). |
| 10.33 | 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 filed on Form 10-K on March 21, 2012). |
| 10.34 | 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 filed on Form 10-K on March 21, 2012). |
| 10.35 | Amendment to 8% Senior Secured Convertible Debenture and Waiver under Securities Purchase Agreement, dated July 23, 2012. |
| 10.36 | 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). |
| 10.37 | 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). |
| 10.38 | 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). |
| 10.39 | Letter Agreement with Debenture Holder dated April 16, 2013. |
| 10.40 | 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). |
| 10.42 | 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). |
| 10.43 | 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). |
| 10.44 | Letter of Intent with Shoreline Energy Corp. |
| 10.45† | 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 filed on Form 8-K on November 19, 2013). |
| 10.46† | Separation Agreement with Roger A. Parker dated as of November 15, 2012 (incorporated herein by reference to Exhibit 10.1 to the Company’s current report on Form 8-K filed on December 4, 2012). |
| 10.47 | 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) |
| 10.48† | 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). |
| 10.49† | Employment Agreement between the Company and Abraham Mirman, dated September 16, 2013 (incorporated herein by reference to Exhibit 10.1 to the Company’s current report on Form 8-K filed on September 20, 2013). |
| 10.50† | Independent Director Appointment Agreement with W. Phillip Marcum dated April 27, 2012 (incorporated herein by reference to Exhibit 10.1 to the Company’s current report on Form 8-K filed on May 2, 2012). |
| 10.51† | Independent Director Appointment Agreement with Bruce B. White dated April 27, 2012 (incorporated herein by reference to Exhibit 10.2 to the Company’s current report on Form 8-K filed on May 2, 2012). |
| 10.52† | Amended and Restated Independent Director Appointment Agreement with Timothy N. Poster dated April 27, 2012 (incorporated herein by reference to Exhibit 10.32 to the Company’s current report on Form 8-K filed on June 1, 2010). |
| 10.53† | Independent Director Appointment Agreement with D. Kirk Edwards dated May 18, 2012 (incorporated by reference to Exhibit 10.1 to the Company’s current report filed on Form 8-K on May 18, 2012). |
| 10.55 † | Independent Director Appointment Agreements dated March 1, 2014. |
| 10.56 † | Investment Banking Agreement with T.R. Winston dated as of May 10, 2013. |
| 10.57 † | Amendment to Investment Banking Agreement with T.R. Winston dated as of September 16, 2013. |
| 10.58 † | Stock Option Award Agreement with A. Bradley Gabbard dated as of June 25, 2013. |
| 10.59 † | Stock Option Award Agreement with W. Phillip Marcum dated as of June 25, 2013. |
| 10.60 † | Stock Option Award Agreement (600K) with Abraham Mirman dated as of September 16, 2013. |
| 10.61 † | Stock Option Award Agreement (2M) with Abraham Mirman dated as of September 16, 2013. |
| 10.62 † | Stock Option Award Agreement with D. Kirk Edwards dated as of October 24, 2013. |
| 10.63 † | Stock Option Award Agreement with Bruce White dated as of October 24, 2013. |
| 10.64 † | Stock Option Award Agreement with Timothy Poster dated as of October 24, 2013. |
| 21.1 | List of subsidiaries of the registrant (incorporated herein by reference to Exhibit 21.1 to the Company’s registration statement on Form S-1 (333-164291). |
| 23.1 | Consent of Hein & Associates, LLP (included in its report on page F-1) |
| 23.2 | 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 |
| 101.LAB | XBRL Taxonomy Extension Label Linkbase Document |
| 101.PRE | XBRL Taxonomy Extension Presentation Linkbase Document |
_______________________
† Indicates a management contract or any compensatory plan, contract or arrangement.
To the Board of Directors and Shareholders
Lilis Energy, Inc.
We have audited the accompanying consolidated balance sheets of Lilis Energy, Inc. and subsidiaries (together, the “Company”) as of December 31, 2013 and 2012, and the related consolidated statements of operations, shareholders’ equity, and cash flows for the years 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 audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits 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 audits provide 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 2012, and the results of their operations and their cash flows for the years then ended, in conformity with U.S. generally accepted accounting principles.
Hein & Associates LLP
Denver, Colorado
June 11, 2014
CONSOLIDATED BALANCE SHEETS
| | | December 31, | | | December 31, | |
| | | 2013 | | | 2012 | |
| Assets | |
| Current assets | | | | | | |
| Cash | | $ | 165,365 | | | $ | 970,035 | |
| Restricted cash | | | 504,623 | | | | 671,382 | |
| Accounts receivable (net of allowance of $50,000 at December 31, 2013 and 2012, respectively) | | | 467,337 | | | | 934,591 | |
| Prepaid assets | | | 195,716 | | | | 13,458 | |
| Commodity price derivative receivable | | | 6,679 | | | | - | |
| Total current assets | | | 1,339,720 | | | | 2,589,466 | |
| | | | | | | | | |
| Oil and gas properties (full cost method), at cost: | | | | | | | | |
| Evaluated properties | | | 68,213,467 | | | | 58,610,095 | |
| Unevaluated acreage, excluded from amortization | | | 18,663,569 | | | | 28,067,005 | |
| Wells in progress, excluded from amortization | | | 1,145,794 | | | | 193,515 | |
| Total oil and gas properties, at cost | | | 88,022,830 | | | | 86,870,615 | |
| | | | | | | | | |
| Less accumulated depreciation, depletion, amortization, and impairment | | | (45,457,637 | ) | | | (43,187,962 | ) |
| Net oil and gas properties, at cost | | | 42,565,193 | | | | 43,682,653 | |
| | | | | | | | | |
| Other assets: | | | | | | | | |
| Office equipment, net | | | 91,161 | | | | 90,630 | |
| Deferred financing costs, net | | | 294,699 | | | | 974,856 | |
| Restricted cash and deposits | | | 215,541 | | | | 215,435 | |
| Total other assets | | | 601,401 | | | | 1,280,921 | |
| | | | | | | | | |
| Total Assets | | $ | 44,506,314 | | | $ | 47,553,040 | |
The accompanying notes are an integral part of these financial statements.
CONSOLIDATED BALANCE SHEETS
| | | December 31, | | | December 31, | |
| | | 2013 | | | 2012 | |
| Liabilities and Shareholders' Equity | |
| Current liabilities | | | | | | |
| Accounts payable | | $ | 1,932,618 | | | $ | 1,831,590 | |
| Accrued expenses | | | 1,439,956 | | | | 1,411,016 | |
| Short term notes payable | | | 10,662,904 | | | | 388,351 | |
| Total current liabilities | | | 14,035,478 | | | | 3,630,957 | |
| | | | | | | | | |
| Long term liabilities | | | | | | | | |
| Asset retirement obligation | | | 1,104,952 | | | | 911,546 | |
| Term notes payable | | | 8,111,436 | | | | 18,947,963 | |
| Convertible notes payable, net of discount | | | 14,586,618 | | | | 10,300,361 | |
| Convertible notes conversion derivative liability | | | 1,150,000 | | | | 1,680,000 | |
| Total long-term liabilities | | | 24,953,006 | | | | 31,839,870 | |
| | | | | | | | | |
| Total liabilities | | | 38,988,484 | | | | 35,470,827 | |
| | | | | | | | | |
| Commitments and contingencies – Note 2,8,9,10,13 and 14 | | | | | | | | |
| | | | | | | | | |
| Shareholders’ equity | | | | | | | | |
| Preferred stock, 10,000,000 authorized, none issued and outstanding | | | - | | | | - | |
| Common stock, $0.0001 par value: 100,000,000 shares authorized; 19,671,901 and 17,436,825 shares issued and outstanding as of December 31, 2013 and December 31, 2012, respectively | | | 1,967 | | | | 1,839 | |
| Additional paid in capital | | | 121,451,232 | | | | 118,296,679 | |
| Accumulated deficit | | | (115,935,369 | ) | | | (106,216,305 | ) |
| Total shareholders' equity | | | 5,517,830 | | | | 12,082,213 | |
| | | | | | | | | |
| Total Liabilities and Shareholders’ Equity | | $ | 44,506,314 | | | $ | 47,553,040 | |
The accompanying notes are an integral part of these financial statements.
CONSOLIDATED STATEMENTS OF OPERATIONS
Years Ended December 31, 2013 and 2012
| | | 2013 | | | 2012 | |
| Revenue | | | | | | |
| Oil sales | | $ | 4,312,325 | | | $ | 5,898,459 | |
| Gas sales | | | 340,609 | | | | 406,216 | |
| Operating fees | | | 148,474 | | | | 174,779 | |
| Realized gains (loss) on commodity price derivatives | | | (17,572 | ) | | | 780,135 | |
| Unrealized gains on commodity price derivatives | | | 2,475 | | | | - | |
| Total revenue | | | 4,786,311 | | | | 7,259,589 | |
| | | | | | | | | |
| Costs and expenses | | | | | | | | |
| Production costs | | | 1,217,853 | | | | 1,421,177 | |
| Production taxes | | | 263,437 | | | | 227,455 | |
| General and administrative | | | 4,965,279 | | | | 4,331,328 | |
| Depreciation, depletion and amortization | | | 2,388,871 | | | | 4,549,303 | |
| Bad debt expense | | | - | | | | 77,957 | |
| Impairment of developed properties | | | - | | | | 26,658,707 | |
| Total costs and expenses | | | 8,835,440 | | | | 37,265,927 | |
| | | | | | | | | |
| Loss from operations | | | (4,049,129 | ) | | | (30,006,338 | ) |
| | | | | | | | | |
| Other income (expenses): | | | | | | | | |
| Other income | | | 11,062 | | | | 5,896 | |
| Convertible notes conversion derivative gain | | | 730,000 | | | | 320,000 | |
| Interest expense | | | (6,410,996 | ) | | | (8,056,232 | ) |
| Total other income (expenses) | | | (5,669,934 | ) | | | (7,730,336 | ) |
| | | | | | | | | |
| Net Loss | | $ | (9,719,063 | ) | | $ | (37,736,674 | ) |
| Net loss per common share | | | | | | | | |
| Basic and diluted | | $ | (0.51 | ) | | $ | (2.11 | ) |
| Weighted average shares outstanding: | | | | | | | | |
| Basic and diluted | | | 18,990,383 | | | | 17,902,013 | |
The accompanying notes are an integral part of these financial statements
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY
Years Ended December 31, 2013 and 2012
| | | | | | | | | Additional | | | | | | | |
| | | Common Stock | | | Paid-In | | | Accumulated | | | | |
| | | Shares | | | Amount | | | Capital | | | Deficit | | | Total | |
| | | | | | | | | | | | | | | | | | | | | |
| Balance, December 31, 2011 | | | 17,436,825 | | | $ | 1,744 | | | $ | 118,146,119 | | | $ | (68,479,631 | ) | | $ | 49,668,232 | |
| | | | | | | | | | | | | | | | | | | | | |
| Common stock issued in connection with interest payment on convertible debt | | | 278,225 | | | | 28 | | | | 894,063 | | | | - | | | | 894,091 | |
| | | | | | | | | | | | | | | | | | | | | |
| Common stock issued for deferred financing costs | | | 50,000 | | | | 5 | | | | 229,995 | | | | - | | | | 230,000 | |
| | | | | | | | | | | | | | | | | | | | | |
| Common stock issued for services | | | 100,000 | | | | 10 | | | | 348,990 | | | | - | | | | 349,000 | |
| | | | | | | | | | | | | | | | | | | | | |
| Common stock issued for compensation (board and employees) | | | 529,351 | | | | 52 | | | | 1,836,512 | | | | - | | | | 1,836,564 | |
| | | | | | | | | | | | | | | | | | | | | |
| Modification of common stock issued for compensation | | | - | | | | - | | | | (3,159,000 | ) | | | - | | | | (3,159,000 | ) |
| | | | | | | | | | | | | | | | | | | | | |
| Net Loss | | | - | | | | - | | | | - | | | | (37,736,674 | ) | | | (37,736,674 | ) |
| | | | | | | | | | | | | | | | | | | | | |
| Balance, December 31, 2012 | | | 18,394,401 | | | $ | 1,839 | | | $ | 118,296,678 | | | $ | (106,216,305 | ) | | $ | 12,082,212 | |
| | | | | | | | | | | | | | | | | | | | | |
| 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 | | | - | | | | - | | | | - | | | | (9,719,064 | ) | | | (9,719,064 | ) |
| | | | | | | | | | | | | | | | | | | | | |
| Balance, December 31, 2013 | | | 19,671,901 | | | $ | 1,967 | | | $ | 121,451,232 | | | $ | (115,935,369 | ) | | $ | 5,517,830 | |
The accompanying notes are an integral part of these financial statements.
CONSOLIDATED STATEMENTS OF CASH FLOWS
Years Ended December 31, 2013 and 2012
| | | Year ended December 31, | |
| | | 2013 | | | 2012 | |
| | | | | | | |
| Cash flows from operating activities: | | | | | | |
| Net loss | | $ | (9,719,064 | ) | | $ | (37,736,674 | ) |
| Adjustments to reconcile net loss to net cash used in operating activities: | | | | | | | | |
| Impairment provision, proved leases | | | - | | | | 26,658,707 | |
| Common stock issued for convertible note interest | | | 1,167,997 | | | | 894,092 | |
| Bad debt | | | - | | | | 77,957 | |
| Common stock for services and compensation | | | 1,986,685 | | | | (973,432 | ) |
| Changes in the fair value of commodity price derivatives | | | 6,679 | | | | (855,744 | ) |
| Amortization of deferred financing costs | | | 680,157 | | | | 1,596,739 | |
| Change in fair value of convertible notes conversion derivative | | | (720,000 | ) | | | (320,000 | ) |
| Depreciation, depletion, amortization and accretion of asset retirement obligation | | | 2,388,871 | | | | 4,549,305 | |
| Accretion of debt discount | | | 2,408,522 | | | | 2,316,428 | |
| Changes in operating assets and liabilities: | | | | | | | | |
| Accounts receivable | | | 467,254 | | | | (228,934 | ) |
| Restricted cash | | | 166,758 | | | | 260,783 | |
| Other assets | | | (182,256 | ) | | | 636,078 | |
| Accounts payable and other accrued expenses | | | 129,967 | | | | (264,708 | ) |
| Net cash used in operating activities | | | (1,218,430 | ) | | | (3,389,403 | ) |
| | | | | | | | | |
| Cash flows from investing activities: | | | | | | | | |
| Acquisition of undeveloped acreage | | | (1,404,121 | ) | | | (536,249 | ) |
| Drilling capital expenditures | | | (398,752 | ) | | | (4,533,954 | ) |
| Sale of undeveloped acreage interests | | | 640,000 | | | | 2,918,414 | |
| Additions of office equipment | | | (27,829 | ) | | | (2,928 | ) |
| Loss (gain) from hedge settlements | | | (13,359 | ) | | | 780,135 | |
| Investment in operating bonds | | | (106 | ) | | | (29,379 | ) |
| Net cash used in investing activities | | | (1,204,167 | ) | | | (1,403,961 | ) |
| | | | | | | | | |
| Cash flows from financing activities: | | | | | | | | |
| | | | | | | | | |
| Proceeds from debt | | | 2,179,902 | | | | 5,000,000 | |
| Repayment of debt | | | (561,975 | ) | | | (1,944,323 | ) |
| Net cash provided by financing activities | | | 1,617,927 | | | | 3,055,677 | |
| | | | | | | | | |
| Change in cash and cash equivalents | | | (804,670 | ) | | | (1,737,687 | ) |
| Cash and cash equivalents at beginning of period | | | 970,035 | | | | 2,707,722 | |
| | | | | | | | | |
| CASH AND CASH EQUIVALENTS AT END OF PERIOD | | $ | 165,365 | | | $ | 970,035 | |
| Supplemental disclosure: | |
| Cash paid for interest | | $ | 2,096,769 | | | $ | 3,201,312 | |
| Cash paid for income taxes | | $ | - | | | $ | - | |
| | | | | | | | | |
| Non-cash transactions: | | | | | | | | |
| Sale of property for receivable | | $ | - | | | $ | 1,443,852 | |
| Debt issuance cost | | $ | - | | | $ | 400,000 | |
| Stock and warrants issued for deferred financing costs | | $ | - | | | $ | 230,000 | |
| Stock and warrants issued for prepaid financial advisory fees | | $ | 674,506 | | | $ | 349,000 | |
| Property additions for asset retirement obligation | | $ | 101,510 | | | $ | 198,110 | |
| Stock issued for payment on long-term debt | | $ | 1,167,997 | | | $ | 894,091 | |
The accompanying notes are an integral part of these financial statements.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1 – ORGANIZATION
On September 21, 2009, Universal Holdings, Inc. (“Universal”), a Nevada corporation, completed the acquisition of Coronado Acquisitions, LLC (“Coronado”). Under the terms of the acquisition, Coronado was merged into Universal. On October 12, 2009, Universal changed its name to Recovery Energy, Inc. On December 1, 2013, Recovery Energy, Inc. changed its name to Lilis Energy, Inc. (“Lilis”, “Lilis Energy”, “we”, “our”, and the “Company”). The acquisition was accounted for as a reverse acquisition with Coronado being treated as the acquirer for accounting purposes. Accordingly, the financial statements of Coronado and Recovery Energy have been adopted as the historical financial statements of Lilis.
The Company is an independent oil and gas exploration and production company focused on the Denver-Julesburg Basin (“DJ Basin”) where it holds 112,000 net acres. Lilis drills for, operates and produces oil and natural gas wells through the Company’s land holdings located in Wyoming, Colorado, and Nebraska.
All references to production, sales volumes and reserves quantities are net to our interest unless otherwise indicated.
NOTE 2 – LIQUIDITY
As of December 31, 2013, the Company had $18.77 million outstanding under its term loans with Hexagon, LLC (“Hexagon”) and $15.58 million outstanding under its 8% Senior Secured Convertible Debentures (the “Debentures”). Both the term loans and the Debentures were to mature on May 16, 2014.
Since December 31, 2013, the Company has consummated the following transactions: (i) on January 22, 2014, the Company completed a private placement of units consisting of one share of Common Stock and one three-year warrant to purchase one share of Common Stock for aggregate gross proceeds of $5,918,250, plus an additional $1,425,000 in proceeds committed by certain officers and directors of the Company, which we expect to be funded upon our receipt of the required shareholder approval; (ii) on January 31, 2014, the Company entered into a Debenture Conversion Agreement, under which $9.0 million in Debentures was immediately converted to Common Stock at a price of $2.00 per common share; (iii) on May 19, 2014, the Company received extensions from both Hexagon and the remaining Debenture holders of the maturity dates under the Company’s term loans and Debentures, respectively, from May 16, 2014 to August 15, 2014; (iv) on May 30, 2014, the Company and Hexagon entered into an agreement providing for the settlement of all amounts outstanding under the term loans, in exchange for two cash payments of $5.0 million each to be made by the Company to Hexagon, as well as the issuance to Hexagon of a two-year $6.0 million unsecured 8% note, maturity May 30, 2016, and 943,208 shares of unregistered Common Stock; (v) on May 30, 2014 the Company consummated a private placement to accredited investors of 8% Convertible Preferred Stock and three-year warrants to purchase Common Stock equal to 50% of the number of shares issuable upon full conversion of the Preferred Stock for gross proceeds of $7.50 million; (vi) on June 6, 2014, the holders of the remaining Debentures agreed to further extend the maturity date under the Debentures from August 15, 2014 to January 15, 2015; and (vii) on June 6, 2014, TR Winston executed a commitment to purchase or effect the purchase by third parties of an additional $15 million in Preferred Stock, which transaction is to be consummated within ninety (90) days. The consummation of these transactions has been partially reflected in the Company’s balance sheet via the classification of certain portions of the Hexagon term loans and Debentures as long-term debt. Absent these transactions, all such debt would have otherwise been classified as current liabilities. (See Note 14 -Subsequent Events.)
The closing of these transactions provided the Company with working capital for general corporate purposes, as well as a portion of the initial capital requirements to initiate further development activities on two of its Wattenberg prospects. However, the Company will require additional capital to satisfy its obligations to Hexagon under the settlement agreement, to fund its current drilling commitments and capital budget plans, to help fund its ongoing overhead, and to provide additional capital to generally improve its working capital position. We anticipate that such additional funding will be provided by a combination of capital raising activities, including the selling of additional debt and/or equity securities, the selling of certain assets and by the development of certain of the Company’s undeveloped properties via arrangements with joint venture partners. If we are not successful in obtaining sufficient cash sources to fund the aforementioned capital requirements, we may be required to curtail our expenditures, restructure our operations, sell assets on terms which may not be deemed favorable and/or curtail other aspects of our operations, including deferring portions of capital budget. There is no assurance that any such funding will be available to the Company.
NOTE 3 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES AND ESTIMATES
Basis of Presentation
The accompanying financial statements were prepared by Lilis in accordance with generally accepted accounting principles (“GAAP”) in the United States. The financial statements reflect all normal recurring adjustments which are, in the opinion of management, necessary to provide a fair statement of the results of operations and financial position.
Reclassification
Certain amounts in the 2012 consolidated financial statements have been reclassified to conform to the December 31, 2013 consolidated financial statement presentation. Such reclassifications had no effect on net loss.
Use of Estimates
The preparation of the financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of oil and gas reserves, assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. We evaluate our estimates on an ongoing basis and base our estimates on historical experience and on various other assumptions we believe to be reasonable under the circumstances. Although actual results may differ from these estimates under different assumptions or conditions, we believe that our estimates are reasonable.
Our most significant financial estimates are associated with our estimated proved oil and gas reserves, assessments of impairment imbedded in the carrying value of undeveloped acreage and proven properties, as well as valuation of common stock used in various issuances of common stock, options and warrants, and estimated derivative liabilities.
Cash and Cash Equivalents
Cash and cash equivalents include cash in banks and highly liquid debt securities which have original maturities of 90 days or less at the purchase date.
Restricted Cash
Restricted cash consists of severance and ad valorem tax proceeds which are payable to various tax authorities. As of December 31, 2013 and 2012, the restricted cash balance was $0.50 million and $0.67 million, respectively.
Accounts Receivable
The Company records actual and estimated oil and gas revenue receivable from third parties at its net revenue interest. The Company also reflects costs incurred on behalf of joint interest partners in accounts receivable. Management periodically reviews accounts receivable amounts for collectability and records its allowance for uncollectible receivables under the specific identification method. The Company recorded an allowance for uncollectible receivables of $50,000 as of December 31, 2013 and 2012. Allowance for doubtful accounts are based primarily on joint interest billings for expenses related to oil and natural gas wells. Receivables which derive from sales of certain oil and gas production are collateral for our Loan Agreements. (See Note 7-Fair Value of Financial Instruments.)
During the year ended December 31, 2013, the Company did not write off any accounts receivable. During the year ended December 31, 2012, the Company wrote off accounts receivable for $0.03 million as bad debt expense.
Concentration of Credit Risk
The Company's cash, cash equivalents and short-term investments are invested at major financial institutions primarily within the United States. At December 31, 2013 and 2012, the Company’s cash and cash equivalents were maintained in accounts that are insured up to the limit determined by the federal governmental agency. The Company may at times have balances in excess of the federally insured limits.
The Company's receivables are comprised of oil and gas revenue receivables and joint interest billings receivable. The amounts are due from a limited number of entities. Therefore, the collectability is dependent upon the general economic conditions and financial health of a small number purchasers and joint interest owners. The receivables are not collateralized. However, to date the Company has had minimal bad debts. As of December 31, 2013, the Company recorded an allowance for doubtful accounts of $50,000.
Significant Customers
During the year ended December 31, 2013 and 2012, the Company had one customer, Shell Trading (US), which accounted for approximately 83 percent and 67 percent, respectively, of our revenues.
However, the Company does not believe that the loss of a single purchaser, including Shell Trading (US), would materially affect the Company's business because there are numerous other purchasers in the area in which the Company sells its production.
Reserves
All of the reserves data included herein are estimates. Estimates of our crude oil and natural gas reserves are prepared in accordance with guidelines established by the SEC, including rule revisions designed to modernize the oil and gas company reserves reporting requirements, which we implemented effective December 31, 2010. Reservoir engineering is a subjective process of estimating underground accumulations of crude oil and natural gas. There are numerous uncertainties inherent in estimating quantities of proved crude oil and natural gas reserves. Uncertainties include the projection of future production rates and the expected timing of development expenditures. The accuracy of any reserves estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, reserves estimates may be different from the quantities of crude oil and natural gas that are ultimately recovered. In addition, economic producibility of reserves is dependent on the oil and gas prices used in the reserves estimate. Our reserves estimates are based on 12-month average commodity prices, unless contractual arrangements otherwise designate the price to be used, in accordance with SEC rules. However, oil and gas prices are volatile and, as a result, our reserves estimates will change in the future.
Estimates of proved crude oil and natural gas reserves significantly affect our depreciation, depletion, and amortization “DD&A” expense. For example, if estimates of proved reserves decline, the DD&A rate will increase, resulting in a decrease in net income. A decline in estimates of proved reserves could also result in an impairment charge, which would reduce earnings.
Oil and Gas Producing Activities
The Company follows the full cost method of accounting for oil and gas operations whereby all costs related to the exploration, non-production related development and acquisition of oil and natural gas reserves are capitalized. Such costs include land acquisition costs, geological and geophysical expenses, carrying charges on non-producing properties, costs of drilling, developing and completing productive wells and/or plugging and abandoning non-productive wells, and any other costs directly related to acquisition and exploration activities. Proceeds from property sales are generally applied as a credit against capitalized exploration and development costs, with no gain or loss recognized, unless such a sale would significantly alter the relationship between capitalized costs and the proved reserves attributable to these costs. A significant alteration would typically involve a sale of 25% or more of proved reserves.
Depletion of exploration and development costs and depreciation of wells and tangible production assets is computed using the units-of-production method based upon estimated proved oil and gas reserves. Costs included in the depletion base to be amortized include (a) all proved capitalized costs including capitalized asset retirement costs net of estimated salvage values, less accumulated depletion, (b) estimated future development cost to be incurred in developing proved reserves; and (c) estimated decommissioning and abandonment/restoration costs, net of estimated salvage values, that are not otherwise included in capitalized costs.
The costs of undeveloped acreage are withheld from the depletion base until it is determined whether or not proved reserves can be assigned to the properties. When proved reserves are assigned to such properties or one or more specific properties are deemed to be impaired, the cost of such properties or the amount of the impairment is added to full cost pool which is subject to depletion calculations.
Under the full cost method of accounting, capitalized oil and gas property costs less accumulated depletion and net of deferred income taxes may not exceed an amount equal to sum of i.) the present value, discounted at 10%, of estimated future net revenues from proved oil and gas reserves, plus ii.) the cost of unproved properties not subject to amortization (without regard to estimates of fair value), or estimated fair value, if lower, of unproved properties that are not subject to amortization. Should capitalized costs exceed this ceiling, an impairment expense is recognized.
The present value of estimated future net cash flows was computed by applying: a flat oil price to forecast revenues from estimated future production of proved oil and gas reserves as of period-end, less estimated future expenditures to be incurred in developing and producing the proved reserves (assuming the continuation of existing economic conditions), less any applicable future taxes.
The Company recognized impairment expense of $0 and $26.66 million for the years ended December 31, 2013 and 2012, respectively.
Effective as of December 31, 2013, the Company completed an assessment of impairment related to its inventory of undeveloped acreage, which resulted in a reduction of the carrying value in the amount of $9.58 million. This impairment was recognized by a transfer of the impairment value from undeveloped acreage to developed properties. In assessing impairment, the Company analyzed all of its undeveloped acreage with expiration dates during the years ended December 31, 2014 and 2015, and that are not otherwise renewable, and impaired such acreage in the amount of $6.38 million. In addition to impairment related to near and intermediate term expirations, the Company assessed carrying value of its remaining acreage, and concluded that an additional impairment of $3.20 million was necessary. (See Note 4 – Oil and Gas Properties & Oil and Gas Properties Acquisitions and Divestitures.)
Wells in Progress
Wells in progress connotes wells that are currently in the process of being drilled or completed or otherwise under evaluation as to their potential to produce oil and gas reserves in commercial quantities. Such wells continue to be classified as wells in progress and withheld from the depletion calculation and the ceiling test until such time as either proved reserves can be assigned, or the wells are otherwise abandoned. Upon either the assignment of proved reserves or abandonment, the costs for these wells are then transferred to the full cost pool and become subject to both depletion and the ceiling test calculations. (See Note 5 – Wells in Progress.)
During the year ended December 31, 2013, the Company evaluated the wells in progress activity and transferred $0.18 million to evaluated properties for projects that were either completed or are no longer being evaluated.
As of December 31, 2013, the Company has $1.15 million in wells in progress compared to $0.19 million in wells in progress as of December 31, 2012. (See Note 5 – Wells in Progress.)
Deferred Financing Costs
As of December 31, 2013 and December 31, 2012, the Company recorded unamortized deferred financing costs of approximately $0.03 million and $0.97 million, respectively, related to the closing of its loans and credit agreements. Deferred financing costs include origination (warrants issued and overriding royalty interests assigned to Hexagon), legal and engineering fees incurred in connection with the Company's credit facility, which are being amortized over the term of the credit facility. The Company recorded amortization expense of approximately $0.71 million and $1.60 million, respectively, in the years ended December 31, 2013 and December 31, 2012. (See Note 8-Loan Agreements.)
Property and Equipment
Property and equipment are stated at cost. Depreciation is calculated using the straight-line method over the estimated useful lives of the assets. The estimated useful lives of property and equipment range from one to seven years. The Company recorded $0.03 million and $0.02 million of depreciation for the years ended December 31, 2013 and December 31, 2012, respectively.
Impairment of Long-lived Assets
The Company accounts for long-lived assets (other than oil and gas properties) at cost. Other long-lived assets include property and equipment, prepaid advisory fees, and identifiable intangible assets with finite useful lives (subject to amortization, depletion, and depreciation). The Company may impair these assets whenever events or changes in circumstances indicate that the carrying amount such assets may not be fully recoverable. Recoverability is measured by comparing the carrying amount of an asset to the expected undiscounted future net cash flows generated by the asset. If it is determined that the asset may not be recoverable, and if the carrying amount of an asset exceeds its estimated fair value, an impairment charge is recognized to the extent of the difference.
As of December 31, 2013, no impairment has been recorded for long lived assets. As of December 31, 2012, no impairment was recorded for long lived assets other than the impairment of capitalized oil and gas property costs during December 31, 2013 and 2012 as discussed in undeveloped acreage and wells in progress. (See Note 4 – Oil and Gas Properties & Oil and Gas Properties Acquisitions and Divestitures.)
Fair Value of Financial Instruments
As of December 31, 2013 and 2012, the carrying value of cash and cash equivalents, short-term investments, accounts receivable, accounts payable, accrued expenses, interest payable and customer deposits approximates fair value due to the short-term nature of such items. The carrying value of the Company’s secured debt is carried at cost as the related interest rate, approximates rates currently available to the Company. Certain other assets and liabilities are measured at fair value. (See Note 7-Fair Value of Financial Instruments.)
Commodity Derivative Instrument
The Company utilizes swaps to reduce the effect of price changes on a portion of our future oil production. On a monthly basis, a swap requires us to pay the counterparty if the settlement price exceeds the strike price and the same counterparty is required to pay us if the settlement price is less than the strike price. The objective of the Company's use of derivative financial instruments is to achieve more predictable cash flows in an environment of volatile oil and gas prices and to manage its exposure to commodity price risk. While the use of these derivative instruments limits the downside risk of adverse price movements, such use may also limit the Company's ability to benefit from favorable price movements. The Company may, from time to time, add incremental derivative contracts to hedge additional production, restructure existing derivative contracts or enter into new transactions to modify the terms of current contracts in order to realize the current value of the Company's existing positions. (See Note 6-Derivitvies.)
The use of derivatives involves the risk that the counterparties to such instruments will be unable to meet the financial terms of such contracts. The Company's derivative contracts have typically been arranged with one counterparty. The Company has netting arrangements with this counterparty that provide for the offset of payables against receivables from separate derivative arrangements with the counterparty in the event of contract termination. The derivative contracts may be terminated by a non-defaulting party in the event of default by one of the parties to the agreement. The Company periodically enters into various commodity derivative financial instruments intended to hedge against exposure to market fluctuations of oil prices. As of December 31, 2013, the Company maintained an active commodity swap for 100 barrels of oil per day through January 31, 2014 at a price of $99.25 per barrel. (See Note 6-Derivitvies.)
Revenue Recognition
We record revenues from the sales of crude oil, natural gas and natural gas liquids when the product is delivered at a fixed or determinable price, title has transferred and collectability is reasonably assured.
Asset Retirement Obligation
The Company incurs retirement obligations for certain assets at the time they are placed in service. The fair values of these obligations are recorded as liabilities on a discounted basis. The costs associated with these liabilities are capitalized as part of the related assets and depreciated. Over time, the liabilities are accreted for the change in their present value. (See Note 7-Fair Value of Financial Instruments.)
For purposes of depletion calculations, the Company also includes estimated dismantlement and abandonment costs, net of salvage values, associated with future development activities that have not yet been capitalized as asset retirement obligations.
Asset retirement obligations incurred are classified as Level 3 (unobservable inputs) fair value measurements. The asset retirement liability is allocated to operating expense using a systematic and rational method. As of December 31, 2013 and 2012, the Company recorded a related liability of $1.11 million and $0.91 million. (See Note 7-Fair Value of Financial Instruments.)
The information below reconciles the value of the asset retirement obligation for the periods presented (in thousands):
| | | For the years ended December 31, | |
| | | 2013 | | | 2012 | |
| Balance, beginning of period | | $ | 912 | | | $ | 613 | |
| Liabilities incurred | | | 66 | | | | 198 | |
| Accretion expense | | | 91 | | | | 101 | |
| Change in estimate | | | 36 | | | | - | |
| Balance, end of period | | $ | 1,105 | | | $ | 912 | |
Share Based Compensation
The Company measures the fair value of share-based compensation expense awards made to employees and directors, including stock options, restricted stock 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. The measurement of share-based compensation expense is based on several criteria, including but not limited to the valuation model used and associated input factors, such as expected term of the award, stock price volatility, risk free interest rate, dividend rate and award cancellation rate. These inputs are subjective and are determined using management’s judgment. If differences arise between the assumptions used in determining share-based compensation expense and the actual factors, which become known over time, Lilis may change the input factors used in determining future share-based compensation expense.
Lilis accounts for warrant grants to non-employees whereby the fair values of such warrants are determined using the option pricing model at the earlier of the date at which the non-employee’s performance is complete or a performance commitment is reached. (See Note 12- Shareholders Equity.)
Warrant Modification Expense
The Company accounts for the modification of warrants as an exchange of the old award for a new award. The incremental value is measured as the excess, if any, of the fair value of the modified award over the fair value of the original award immediately before modification, and is either expensed as a period expense or amortized over the performance or vesting date. We estimate the incremental value of each warrant using the Black-Scholes option pricing model. The Black-Scholes model is highly complex and dependent on key estimates by management. The estimate with the greatest degree of subjective judgment is the estimated volatility of our stock price. (See Note 12-Shareholder Equity.)
Loss per Common Share
Earnings (losses) per share are computed based on the weighted average number of common shares outstanding during the period presented. Diluted earnings (losses) per share are computed using the weighted-average number of common shares outstanding plus the number of common shares that would be issued assuming exercise or conversion of all potentially dilutive common shares. Potentially dilutive securities, such as conversion derivatives and stock purchase warrants, are excluded from the calculation when their effect would be anti-dilutive. As of December 31, 2013, a total of 6,773,913 and 3,665,859, respectively, of shares underlying warrants and convertible debentures have been excluded from the diluted share calculations as they were anti-dilutive as a result of net losses incurred. Accordingly, basic shares equal diluted shares for all periods presented.
Income Taxes
Prior to December 31, 2011, the Company filed its tax returns on an April 30 fiscal year end. During the year ended December 31, 2012, the Company received approval by the Internal Revenue Service (“IRS”) to move the Company’s tax year end to December 31 from April.
The Company uses the asset liability method in accounting for income taxes. Deferred tax assets and liabilities are recognized for temporary differences between financial statement carrying amounts and the tax bases of assets and liabilities, and are measured using the tax rates expected to be in effect when the differences reverse. Deferred tax assets are also recognized for operating loss and tax credit carry forwards. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in the results of operations in the period that includes the enactment date. A valuation allowance is used to reduce deferred tax assets when uncertainty exists regarding their realization.
We recognize tax benefits only for tax positions that are more likely than not to be sustained upon examination by tax authorities. The amount recognized is measured as the largest amount of benefit that is greater than 50 percent likely to be realized upon settlement. A liability for “unrecognized tax benefits” is recorded for any tax benefits claimed in our tax returns that do not meet these recognition and measurement standards. As of December 31, 2013 and 2012, the Company has determined that no liability is required to be recognized. (See Note-11 Income Taxes.)
Our policy is to recognize any interest and penalties related to unrecognized tax benefits in income tax expense. However, we did not accrue interest or penalties at December 31, 2013 and December 31, 2012, because the jurisdiction in which we have unrecognized tax benefits does not currently impose interest on underpayments of tax and we believe that we are below the minimum statutory threshold for imposition of penalties. We do not expect that the total amount of unrecognized tax benefits will significantly increase or decrease during the next 12 months. The earliest years remaining subject to examination are December 31, 2011, April 30, 2011 and April 30, 2010. (See Note-11 Income Taxes.)
Recently Issued Accounting Pronouncements
Various accounting standards updates are issued, most of which represented technical corrections to the accounting literature or were applicable to specific industries, are not expected to a have a material impact on the Company's financial position, results of operations or cash flows.
NOTE 4 – OIL AND GAS PROPERTIES & OIL AND GAS PROPERTIES ACQUISITIONS AND DIVESTITURES
In February 2012, we completed the sale of our Grover Prospect acreage, under which we agreed to sell all of our oil and gas leases in the Grover Field in Weld County, Colorado to Bill Barrett Corporation for approximately $4.54 million.
In April, 2012, we made the decision to abandon one of our unconventional Niobrara wells that was categorized as a well in progress as of December 31, 2011. In conjunction with that decision, all capitalized drilling, completion and allocable lease costs related to this well in the amount of $4.8 million were transferred to developed properties. This transfer of costs contributed to a $3.27 impairment charge of developed properties derived from the ceiling test completed as of March 31, 2012. In December 2012, the Company made a decision to abandon the one remaining unconventional Niobrara well. In conjunction with the decision, all capitalized drilling, completion and allocable lease costs related to both wells-in-progress in the amount of $10.06 million were transferred to developed properties. Furthermore, the company analyzed all of its undeveloped acreage with expiration dates during the year ended December 31, 2015 and transferred $5.94 million to developed properties. Also, the Company reduced the PV-10 of the proved undeveloped reserve acreage by utilizing the assumption that its proven undeveloped reserves would be developed on a promoted basis, which reduced the production amounts to 25% of the Company’s 100% ownership. As a result, the ceiling test performed by the Company yielded an increased impairment. The transfer of both of the costs to the developed properties and a reduction of proved undeveloped reserve acreage resulted in an impairment of $23.39 million during December 2012, for a total impairment of $26.66 million for the year ended December 31, 2012.
During 2012, the Company purchased $0.20 million of undeveloped oil and gas acreage interest located in the DJ Basin.
On December 27, 2012, the Company leased undeveloped acreage for total proceeds of $1.50 million in the DJ Basin to a private company granting a four-year lease for the deep rights on approximately 6,300 net acres. The Company paid Hexagon $0.75 million of the proceeds which reduced the long-term debt principal amount.
In February 2013, the Company completed the sale of certain oil and gas properties for $0.64 million.
In June 2013, the Company purchased a 50% working interest in a section in Laramie County, Wyoming for $0.60 million with an additional $0.13 million as additions to the well equipment and intangible equipment. The purchase was classified as $0.30 million into undeveloped acreage and $0.43 million into oil and gas properties.
Effective as of December 31, 2013, the company impaired all of its undeveloped acreage with expiration dates prior to 2016 that are not otherwise extendable, and transferred $6.12 million of the cost of such acreage to developed properties. Also, the Company also completed its annual impairment analysis of undeveloped acreage and transferred an additional amount of $3.20 million in carrying cost from unevaluated leaseholds to evaluated leaseholds.
Depreciation, depletion and amortization (“DD&A”) expenses related to the proved properties were approximately $2.39 million and $4.55 million for the years ended December 31, 2013 and December 31, 2012, respectively. During the year ended December 31, 2012, the company impaired the carrying costs of its developed oil and gas properties by $26.66 million, respectively, as a result of an excess of carrying costs above the applicable ceiling threshold based on the fair market value of the proved developed and proved undeveloped acreage. No such impairment expense has been recognized in the year ended December 31, 2013.
The following table sets forth a summary of oil and gas property costs (net of divestitures) not being amortized as of December 31, 2013 and 2012 (in thousands):
| | | As of December 31, | |
| | | 2013 | | | 2012 | |
| Undeveloped acreage | | | | | | |
| Beginning Balance | | $ | 28,067 | | | $ | 45,697 | |
| Acquisitions | | | 368 | | | | 204 | |
| Transferred to evaluated properties | | | - | | | | - | |
| Leased deep rights of undeveloped acreage | | | - | | | | (1,444 | ) |
| Impairment and other reclassification to evaluated properties | | | (9,771 | ) | | | (16,390 | ) |
| Total undeveloped acreage | | $ | 18,664 | | | $ | 28,067 | |
| | | | | | | | | |
| Wells in progress: | | | | | | | | |
| Beginning Balance | | $ | 194 | | | $ | 6,426 | |
| Additions | | | 1,125 | | | | 3,824 | |
| Reclassification to evaluated properties | | | (173 | ) | | | (10,056 | ) |
| Total wells in progress | | $ | 1,146 | | | $ | 194 | |
| Total property not subject to DD&A | | $ | 19,810 | | | $ | 28,261 | |
NOTE 5 – WELLS IN PROGRESS
The following table reflects the net changes in capitalized additions to wells in progress during 2013 and 2012 (in thousands):
| | | As of December 31, | |
| | | 2013 | | 2012 | |
| Wells in progress: | | | | |
| Beginning Balance | | $ | 194 | | | $ | 6,426 | |
| Additions | | | 1,125 | | | | 3,824 | |
| Reclassification to developed properties | | | (173 | ) | | | (10,056 | ) |
| Total wells in progress | | $ | 1,146 | | | $ | 194 | |
During the year ended December 31, 2013, the Company evaluated the wells in progress activity and transferred $0.18 million to evaluated properties for projects that were neither completed or are no longer being evaluated.
During the fourth quarter of 2013, the Company funded the drilling of a horizontal well in North Wattenberg for a $1.07 million. Completion of the well is scheduled for second quarter 2014.
In 2012, we made the decision to abandon both of our unconventional Niobrara wells that were categorized as a well in progress as of December 31, 2011. In conjunction with that decision, all capitalized drilling, completion and allocable lease costs related to these wells in the amount of $10.06 million were transferred to developed properties.
NOTE 6 - DERIVATIVES
The Company periodically enters into various commodity derivative financial instruments intended to hedge against exposure to market fluctuations of oil prices. As of December 31, 2013, the Company maintained an active commodity swap for 100 barrels of oil per day through January 31, 2014 at a price of $99.25 per barrel.
The amount of gain (loss) recognized in income related to our derivative financial instruments was as follows (in thousands):
| | | For the Year Ended December 31, | |
| | | 2013 | | | 2012 | |
| Realized gain (loss) on oil price hedges | | $ | (17 | ) | | $ | 780 | |
| Unrealized gain oil price hedges | | $ | 2 | | | $ | - | |
Realized gains and losses are recorded as individual swaps mature and settle. These gains and losses are recorded as income or expenses in the periods during which applicable contracts settle. Swaps which are unsettled as of a balance sheet date are carried at fair market value, either as an asset or liability. Unrealized gains and losses result from mark-to-market changes in the fair value of these derivatives between balance sheet dates. (See Note 7 - Fair Value of Financial Instruments.)
NOTE 7 - FAIR VALUE OF FINANCIAL INSTRUMENTS
The Company measures fair value of its financial assets on a three-tier value hierarchy, which prioritizes the inputs, used in the valuation methodologies in measuring fair value:
● Level 1 – Observable inputs that reflect quoted prices (unadjusted) for identical assets or liabilities in active markets.
● Level 2 – Other inputs that are directly or indirectly observable in the marketplace.
● Level 3 – Unobservable inputs which are supported by little or no market activity.
The fair value hierarchy also requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value.
The Company’s cash equivalents, short-term investments, accounts receivable, accounts payable, accrued expenses, interest payable and customer deposits approximate fair value due to the short-term nature or maturity of the instruments. The Company’s fixed rate 10% and 8% term loans and convertible debentures, respectively, are measured using Level 3 inputs.
Executive Compensation
In September, 2013, we announced the appointment of Abraham Mirman as our new president. In connection with Mr. Mirman’s appointment, the Company entered an employment agreement with Mr. Mirman (the “Mirman Agreement”). The Mirman Agreement provides for an incentive bonus package that, depending upon the relative performance of the Company’s common stock compared to the performance of stocks of certain peer group companies as measured from Mr. Mirman’s initial date of employment through December 31, 2014, may result in a cash bonus payment to Mr. Mirman of up to 3.0 times his base salary. The incentive bonus is recorded as a liability and will be valued every quarter. The Company engaged a third party to complete a valuation of this conversion liability. As of December 31, 2013, the Company recorded a liability of $0.15 million. (See Note 13-Share Based and Other Compensation.)
Derivative Instruments
The Company determines its estimate of the fair value of derivative instruments using a market approach based on several factors, including quoted market prices in active markets, quotes from third parties, and the credit rating of its counterparty. The Company also performs an internal valuation to ensure the reasonableness of third-party quotes.
The types of derivative instruments utilized by the Company included commodity swaps. The oil derivative markets are highly active. Although the Company’s economic hedges are valued using public indices, the instruments themselves are traded with third-party counterparties and are not openly traded on an exchange. As such, the Company has classified these instruments as Level 2.
In evaluating counterparty credit risk, the Company assessed the possibility of whether the counterparty to the derivative would default by failing to make any contractually required payments. The Company considered that the counterparty is of substantial credit quality and has the financial resources and willingness to meet its potential repayment obligations associated with the derivative transactions. (See Note 6-Derivitives.)
Asset Retirement Obligation
The fair value of the Company’s asset retirement obligation liability is calculated at the point of inception by taking into account: 1) the cost of abandoning oil and gas wells, which is based on the Company’s and/or Industry’s historical experience for similar work, or estimates from independent third-parties; 2) the economic lives of its properties, which are based on estimates from reserve engineers; 3) the inflation rate; and 4) the credit adjusted risk-free rate, which takes into account the Company’s credit risk and the time value of money. Given the unobservable nature of the inputs, the initial measurement of the asset retirement obligation liability is deemed to use Level 3 inputs.
Convertible Debentures Payable Conversion Feature
In February 2011, the Company issued in a private placement $8.40 million aggregate principal amount of three year 8% Senior Secured Convertible Debentures (“Debentures”) with a group of accredited investors. During the year ended December 31, 2012, the Company issued an additional $5.00 million of Debentures, resulting in a total of $13.40 million of Debentures outstanding as of December 31, 2012. Through December 31, 2013, the Company issued an additional $2.20 million of supplemental convertible debentures As of December 31, 2013 the Company had a total debenture amount of $15.58 million. As of December 31, 2013, the Debentures are convertible at any time at the holders’ option into shares of our common stock at $4.25 per share, subject to certain adjustments, including the requirement to reset the conversion price based upon any subsequent equity offering at a lower price per share amount. The Company engaged a third party to complete a valuation of this conversion liability. (See Note 8-Loan Agreements.)
The following table provides a summary of the fair values of assets and liabilities measured at fair value (in thousands):
December 31, 2013:
| | | Level 1 | | | Level 2 | | | Level 3 | | | Total | |
| Assets | | | | | | | | | | | | |
| Commodity derivative instruments | | $ | - | | | $ | 7 | | | $ | - | | | $ | 7 | |
| Total assets, at fair value | | $ | - | | | $ | 7 | | | $ | - | | | $ | 7 | |
| | | | | | | | | | | | | | | | | |
| Liability | | | | | | | | | | | | | | | | |
| Executive employment agreement | | $ | - | | | $ | - | | | $ | (145 | ) | | $ | (145 | ) |
| Convertible debentures conversion derivative liability | | $ | - | | | $ | - | | | $ | (1,150 | ) | | $ | (1,150 | ) |
| Total liability, at fair value | | $ | - | | | $ | - | | | $ | (1,295 | ) | | $ | (1,295 | ) |
December 31, 2012:
| | | Level 1 | | | Level 2 | | | Level 3 | | | Total | |
| Liability | | | | | | | | |
| Commodity derivative instruments | | $ | - | | | $ | - | | | $ | - | | | $ | - | |
| Convertible debentures conversion derivative liability | | | - | | | | - | | | | (1,680 | ) | | | (1,680 | ) |
| Total liability at fair value | | $ | - | | | $ | - | | | $ | (1,680 | ) | | $ | (1,680 | ) |
The following table provides a summary of changes in fair value of the Company’s Level 3 financial assets and liabilities as of December 31, 2013 (in thousands):
| Beginning balance, December 31, 2012 | | $ | (1,680 | ) |
| Executive employment agreement liability | | | (145 | ) |
| Convertible debentures conversion derivative gain | | | 730 | |
| Additions to derivative liability from Supplemental Debenture | | | (200 | ) |
| Ending balance, December 31, 2013 | | $ | (1,295 | ) |
The Company did not have any transfers of assets or liabilities between Level 1, Level 2 or Level 3 of the fair value measurement hierarchy during the year ending December 31, 2013 and 2012.
NOTE 8 - LOAN AGREEMENTS
Term Loans
The Company entered into three separate loan agreements with Hexagon in January, March and April 2010. All three loans originally bore annual interest at a rate of 15% (which has been reduced, as discussed below), each had an original maturity date of December 1, 2010 (which has been extended, as discussed below), and have similar terms, including customary representations and warranties and indemnification, and require the Company to repay the loans with the proceeds of the monthly net revenues from the production of the acquired properties. The loans contain cross collateralization and cross default provisions and are collateralized by mortgages against a portion of the Company’s developed and undeveloped leasehold acreage.
In April 2013, Hexagon agreed to amend all three loan agreements to extended the maturity date to May 16, 2014, reduce the annualized interest rate to 10% from 15% beginning retroactively with March 2013, decrease our minimum monthly payment under the term loans to $0.23 and allow us to make interest-only payments for March, April, May, and June. In consideration for the extended maturity date, reduced interest rate, and reduced minimum loan payment, we provided Hexagon an additional security interest in 15,000 acres of our undeveloped acreage.
The Company is subject to certain non-financial covenants with respect to the Hexagon loan agreements. As of December 31, 2013, the Company was in compliance with all covenants under the facilities.
As of December 31, 2013, the total amount outstanding on the three loan agreements was $18.77 million.
On May 19, 2014, the Company received an extension from Hexagon of the maturity date under its term loans, from May 16, 2014 to August 15, 2014. On May 30, 2014, the Company entered into a Settlement Agreement (the “Settlement Agreement”) with Hexagon, which provides for the settlement of all amounts outstanding under the Term Loans. In connection with the execution of the Settlement Agreement, the Company made an initial cash payment of $5.0 million. The Settlement Agreement requires the Company to make an additional cash payment of $5.0 million (the “Second Cash Payment”) by June 30, 2014, and at that time issue to Hexagon (i) a two-year $6.0 million unsecured note (the “Replacement Note”), bearing interest at an annual rate of 8%, requiring principal and interest payments of $90,000 per month, and (ii) 943,208 shares of unregistered common stock (the “Shares”). The parties have also agreed that if the Second Cash Payment is not made by June 30, 2014, an additional $1.0 million in principal will be added to the Replacement Note, and if the Replacement Note is not retired by December 31, 2014, the Company will issue an additional 1.0 million shares of its common stock to Hexagon. Finally, Hexagon will not, until the earlier of June 30, 2014 or the date the Company achieves sustained average trading volume in excess of 100,000 shares per day for at least ten consecutive trading days, sell or otherwise transfer for value any shares of the Company’s common stock or any securities convertible into the Company’s common stock, and thereafter until December 31, 2014, Hexagon will not sell or otherwise transfer for value more than 10,000 shares per week of the Company’s common stock or any securities convertible into the Company’s common stock. Under the Settlement Agreement, Hexagon will release its security interest under the Term Loans once the Company has delivered the Second Cash Payment, the Replacement Note and the Shares. (See Note 14-Subsequent Events.)
Convertible Debentures Payable
In February 2011, the Company completed a private placement of $8.40 million aggregate principal amount of the Debentures, secured by mortgages on several of our properties. Initially, the Debentures were convertible at any time at the holders' option into shares of our common stock at $9.40 per share, subject to certain adjustments, including the requirement to reset the conversion price based upon any subsequent equity offering at a lower price per share amount. Interest at an annualized rate of 8% is payable quarterly on each May 15, August 15, November 15 and February 15 in cash or, at the Company's option, in shares of common stock, valued at 95% of the volume weighted average price of the common stock for the 10 trading days prior to an interest payment date. The Company can redeem some or all of the Debentures at any time. The redemption price is 115% of principal plus accrued interest. If the holders of the Debentures elect to convert the Debentures, following notice of redemption, the conversion price will include a make-whole premium equal to the interest accruable through the 18 month anniversary of the original issue date of the Debenture less the amount of any interest paid on the portion of the Debenture being redeemed prior to the optional redemption date, payable in common stock. TR Winston acted as placement agent for the private placement and received $0.04 million of Debentures equal to 5% of the gross proceeds from the sale. The Company is amortizing the $0.04 million over the life of the loan as deferred financing costs. The Company amortized $0.01 million of deferred financing costs into interest expense during the year ended December 31, 2013, and has $0.03 million of deferred financing cost to be amortized through May 2014.
In December 2011, the Company agreed to amend the Debentures to lower the conversion price to $4.25 from $9.40 per share. This amendment was an inducement consideration to the Debenture holders for their agreement to release a mortgage on certain properties so the properties could be sold. The sale of these properties was effective December 31, 2011, and a final closing occurred during first quarter of 2012.
On March 19, 2012, the Company entered into agreements with some of its existing Debenture holders to issue up to $5.0 million in additional debentures (the “Supplemental Debentures”). Under the terms of the Supplemental Debenture agreements, proceeds derived from the issuance of Supplemental Debentures were used principally for the development of certain of the Company's proved undeveloped properties and other undeveloped acreage currently targeted by the Company for exploration, as well as for other general corporate purposes. Any new producing properties developed from the proceeds of Supplemental Debentures are to be pledged as collateral under a mortgage to secure future payment of the Debentures and Supplemental Debentures. All terms of the Supplemental Debentures are substantively identical to the Debentures. The Agreements also provided for the payment of additional consideration to the purchasers of Supplemental Debentures in the form of a proportionately reduced 5% carried working interest in any properties developed with the proceeds of the Supplemental Debenture offering.
Through July 2012, we received $3.04 million of proceeds from the issuance of Supplemental Debentures, which were used for the drilling and development of six new wells, resulting in a total investment of $3.69 million. Four of these wells resulted in commercial production, and two wells were plugged and abandoned.
In August 2012, the Company and holders of the Supplemental Debentures agreed to renegotiate the terms of the Supplemental Debenture offering. These negotiations concluded with the issuance of an additional $1.96 million of Supplemental Debentures. The August 2012 modifications to the Supplemental Debenture agreements increased the carried working interest from 5% to 10% and also provided for a one-year, proportionately reduced net profits interest of 15% in the properties developed with the proceeds of the Supplemental Debenture offering, as well as the next four properties to be drilled and developed by the Company. In conjunction with commitments to additional Debentures in June 2013 (see below), the commitment to provide a 10% carried interest and a 15% one year net profits interest related to the development of four future properties was modified to a 15% carried interest in such properties. As a result, of the modified carried working interest to 15%, $0.16 million of debt discount was reversed.
On September 8, 2012, the Company issued 50,000 shares, valued at $0.23 million, to TR Winston for acting as a placement agent of the Supplemental Debentures. The Company is amortizing the $0.23 million over the life of the loan as deferred financing costs. The Company amortized $0.13 million and $0.05 million of deferred financing costs into interest expense during the year ended December 31, 2013 and 2012, and has $0.05 million of deferred financing costs to be amortized through May 2014.
In April 2013, the holders of the Debentures agreed to extend their maturity date to May 16, 2014. On May 19, 2014, the Company received an extension on the Debentures until August 15, 2014. The Debentures waived their right to declare an event of default in connection with the May 15, 2014 maturity date under the Debenture agreement. In consideration for the extended maturity date the Company provided an additional security interest in 15,000 acres of our undeveloped acreage, as additional collateral for the Debentures.
In April 2013, we received approval from our existing secured debt and convertible debenture holders to issue up to $5.00 million of additional convertible debentures with terms substantially identical to our existing convertible debentures. As of November 8, 2013 we have issued $2.20 million of such convertible debt, inclusive of $2.21 million that had been issued as of December 31, 2013. Two officers of the Company participated in the additional convertible debentures for a combined total of $0.43 million. Proceeds from the issuance of this convertible debt have been used toward the development of certain specific properties, and to a lesser extent, general corporate purposes. The recent commitments were subject to certain yield enhancements, including a 25% carried interest in certain properties scheduled to be developed with the proceeds. During the year ended December 31, 2013, the Company paid TR Winston $0.04 million as acting placement agent for the additional $2.20 million of supplemental debentures. The Company amortized $.01 million for the year ended December 31, 2013, and has $0.03 million of deferred financing costs to be amortized through May 2014.
We periodically engage a third party valuation firm to complete a valuation of the conversion feature associated with the Debentures, and with respect to December 31, 2013, the Supplemental Debentures. This valuation resulted in an estimated derivative liability as of December 31, 2013 and December 31, 2012 of $1.15 million and $1.68 million, respectively. The portion of the derivative liability that is associated with the October 2013 Supplemental Debentures, in the approximate amount of $0.50 million has been recorded as a debt discount, and is being amortized over the remaining life of the Supplemental Debentures. (See Note 7-Fair Value of Financial Instruments.)
During the year ended December 31, 2013 and 2012, the Company amortized $2.41 million and $2.36 million, respectively, of debt discounts.
On January 31, 2014, the Company entered into a Debenture Conversion Agreement (the “Conversion Agreement”) between the Company and all of the holders of the Debentures. Under the terms of the Agreement, $9 million of the approximately $15.6 million in Debentures then outstanding immediately converted to common stock at a price of $2.00 per common share. The balance of the Debentures may be converted to common stock, subject to receipt of shareholder approval as required by NASDAQ continued listing requirements. As additional inducement for the conversions, the Conversion Agreement provides that the Company issue 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. (See Note 14-Subsequent Events.)
On May 19, 2014, the holders of the Debentures agreed to extend the maturity date of the Debentures until August 15, 2014, and waived their right to declare an event of default in connection with the May 16, 2014 maturity date under the Debentures. On June 6, 2014, the holders of the remaining Debentures agreed to further extend the maturity date under the Debentures from August 15, 2014 to January 15, 2015. (See Note 14-Subsequent Events.)
As of December 31, 2013 and 2012, the convertible debt is recorded as follows (in thousands):
| | | As of December 31, 2013 | | | As of December 31, 2012 | |
| Convertible debentures | | $ | 15,580 | | | $ | 13,400 | |
| Debt discount | | | (993 | ) | | | (3,100 | ) |
| Total convertible debentures, net | | $ | 14,587 | | | $ | 10,300 | |
As a result of the Conversion Agreement, the Debentures are being carried on the balance sheet as of December 31, 2013 as long term liabilities. The convertible debentures have been extended to January 15, 2015 by all of the convertible debenture owners. (See Note 14-Subsequent Events.)
As a result of the Hexagon Settlement Agreement, the Term Notes are being carried on the balance sheet as of December 31, 2013 as follows (in thousands):
| | | As of December 31, 2013 | |
| Total Term Notes | | $ | 18,774 | |
| Short term notes payable | | | (10,663 | ) |
| Long term notes payable | | $ | 8,111 | |
Annual debt maturities as of December 31, 2013 (in thousands):
| Year 1 | | $ | 10,663 | |
| Year 2 | | | 23,691 | |
| Thereafter | | | - | |
| Total | | $ | 34,354 | |
Interest Expense
For the year ended December 31, 2013 and 2012, the Company incurred interest expense of approximately $6.41 million and $8.06 million, respectively, of which approximately $4.04 million and $4.85 million, respectively, were non-cash interest expense and amortization of the deferred financing costs, accretion of the convertible debentures payable discount, and convertible debentures interest paid in common stock.
NOTE 9 - COMMITMENTS and CONTINGENCIES
Environmental and Governmental Regulation
At December 31, 2013, there were no known environmental or regulatory matters which are reasonably expected to result in a material liability to the Company. Many aspects of the oil and gas industry are extensively regulated by federal, state, and local governments in all areas in which the Company has operations. Regulations govern such things as drilling permits, environmental protection and air emissions/pollution control, spacing of wells, the unitization and pooling of properties, reports concerning operations, land use, and various other matters including taxation. Oil and gas industry legislation and administrative regulations are periodically changed for a variety of political, economic, and other reasons. As of December 31, 2013 the Company had not been fined or cited for any violations of governmental regulations that would have a material adverse effect upon the financial condition of the Company.
Legal Proceedings
The Company may from time to time be involved in various legal actions arising in the normal course of business. In the opinion of management, the Company’s liability, if any, in these pending actions would not have a material adverse effect on the financial position of the Company. The Company’s general and administrative expenses would include amounts incurred to resolve claims made against the Company.
Parker v. Tracinda Corporation, Denver District Court, Case No. 2011CV561. In November 2012, the Company filed a motion to intervene in garnishment proceedings involving Roger Parker, the Company’s former Chief Executive Officer and Chairman. The Defendant has served various writs of garnishment on the Company to enforce a judgment against Mr. Parker seeking, among other things, shares of unvested restricted stock. The Company has asserted rights to lawful set-offs and deductions in connection with certain tax consequences, which may be material to the Company. As a result of bankruptcy proceedings filed by Mr. Parker, the garnishment proceedings have been stayed. At this stage, we cannot express an opinion as to the probable outcome of this matter.
In re Roger A. Parker: Tracinda Corp. v. Recovery Energy, Inc. and Roger A. Parker, United States Bankruptcy Court for the District of Colorado, Case No. 13-10897-EEB. On June 10, 2013, Tracinda Corp. (“Tracinda”) filed a complaint (Adversary No. 13-011301 EEB) against the Company and Roger Parker in connection with the personal bankruptcy proceedings of Roger Parker, alleging that the Company improperly failed to remit to Tracinda certain property in connection with a writs of garnishment issued by the Denver District Court (discussed above). The Company filed an answer to this complaint on July 10, 2013. A trial date has not been set.
There are no other material pending legal proceedings to which we or our properties are subject.
Operating Leases
The Company leases an office space under a one year operating lease in Denver, Colorado and Melville, New York. Rent expense for the years ended December 31, 2013 and December 31, 2012, was $0.09 million and $0.09 million, respectively. The Company will have minimum lease payments of $0.12 million for the year ending December 31, 2014.
NOTE 10 - RELATED PARTY TRANSACTIONS
During the year ended December 31, 2013 and 2012, we have engaged in the following transactions with related parties:
T.R. Winston & Company, LLC
TR Winston, as placement agent for the Debentures, received compensation in the form of 50,000 shares, valued at $0.23 million, on September 8, 2012. The Company is amortizing the $0.23 million over the life of the loan as deferred financing costs. The Company amortized $0.13 million of deferred financing costs into interest expense during the year ended December 31, 2013, and has $0.22 million of deferred financing costs to be amortized through May 2014.
TR Winston and G. Tyler Runnels, its majority owner, also participated as investors in the Debentures, and purchased an aggregate of $1.41 million in Debentures between February 2011 and June 2013.
On April 15, 2013, the Company entered into an amendment of the Debentures to extend their maturity dates from February 8, 2014 to May 16, 2014. In consideration for the extended maturity date, the Company provided the holders of the Debentures an additional security interest in 15,000 acres of its undeveloped acreage. (See Note 8-Loan Agreements.)
On April 16, 2013, the Company entered into an agreement with a family trust controlled by Mr. Runnels to issue up to an additional $5.0 million in additional Debentures to existing Debenture holders, of which $1.5 million of would be issued on or before July 16, 2013. Between June 2013 through October 2013, the Company issued a total of $2.2 million in additional Debentures to existing Debenture holders. In November 2013, the Company paid TR Winston a commission of $40,000 in connection with the sale of these Debentures. (See Note 8-Loan Agreements.)
On May 10, 2013 the Company entered into a one-year, non-exclusive investment banking agreement with TR Winston. Among other things, the agreement provided for (i) initial compensation to TR Winston in the amount of 100,000 common shares, and three-year warrants to purchase up to 900,000 shares of the Company’s common stock at a strike price of $4.25 per share (the “Retainer Fee”), (ii) a cash fee equal to 5% of the gross proceeds of any equity financing involving solely the issuance of common stock, or 6% for all other equity issuances, (iii) a cash expense allowance equal to 1% of the gross proceeds of any equity financing, (iv) warrants to purchase common stock equal to either 4% of the shares of common stock issued in connection with an equity offering or 2% of the shares to be issued upon conversion of convertible equity in such offering, (v) 3% of the total gross proceeds of any non-revolving, non-convertible credit facility debt financing, (vi) 1% of the amount initially drawn at closing on any revolving credit line or facility, and (vii) 1% of the issuance price of any credit enhancement instrument, including on an insured or guaranteed basis. (See Note 12-Shareholders Equity.)
Under the investment banking agreement, in addition to the Retainer Fee, the Company paid TR Winston $40,000 in connection with the 2013 Debenture offerings, $576,570 in connection with the January 2014 Private Offering (paid in cash and restricted stock), and $225,000 (paid in 112,500 shares of restricted stock) in connection with the Debenture Conversion Agreement. TR Winston invested $0.17 million of these fees in the January Private Placement. The Company is obligated to pay TR Winston additional fees of $0.16 million upon shareholder approval of the participation of certain directors and officers in the January 2014 Private Placement and conversion of the remaining outstanding Debentures.
In September 2013, the Company appointed Abraham Mirman as its President. Prior to joining the Company, Mr. Mirman was employed by TR Winston as its Managing Director of Investment Banking and continues to devote a portion of his time to serving in that role. In connection with the appointment of Mr. Mirman, the Company and TR Winston amended the investment banking agreement to provide that, upon the receipt by the Company of gross cash proceeds or drawing availability of at least $30,000,000, measured on a cumulative basis and including certain restructuring transactions, subject to the Company’s continued employment of Mr. Mirman, TR Winston would receive from the Company a lump sum payment of $1 million. Mr. Mirman’s compensation arrangements with TR Winston provide 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. Mr. Mirman also received, as part of his compensation arrangement with TR Winston, the 100,000 common shares of the Company that were issued to TR Winston in conjunction with the investment banking agreement.
Mr. Runnels, the majority owner of TR Winston, beneficially holds more than 5% of the Company’s common stock, including the holdings of TR Winston and his personal holdings.
Roger Parker
Roger Parker, the Company’s Chief Executive Officer until November 15, 2012, has interests in certain of the Company’s wells for which he is receiving revenue and joint-interest billings. As of December 31, 2012, Mr. Parker had $0.01 million in receivables outstanding and continued to have additional receivables based on monthly production and well maintenance. Furthermore, upon his resignation on November 15, 2012, the Company entered into a separation agreement which provided that Mr. Parker receive a one-year salary severance and health benefits for the year, and also provided for the deferral of vesting of 1,350,000 shares. In return, the Company received a general release and certain non-compete terms from Mr. Parker, in exchange for no less than 10 hours per week of Mr. Parker’s time as a consultant to the Company during the term of the separation agreement. As of December 31, 2013, the Company does not owe Mr. Parker any further amounts under the separation agreement.
At the time of his retirement, Mr. Parker had been granted 1,350,000 shares of unvested common stock. As a result of his separation from the Company, it was deemed improbable that these shares would vest to Mr. Parker in his capacity as an employee of the Company due to the termination of employment; however, it was deemed probable that these shares will vest under his separation agreement. As a result, the Company reversed all of the compensation expense, in the amount of $6.75 million, associated with stock grants to Mr. Parker during his tenure as an employee, and recorded a consulting expense (in the amount of $3.59 million) related to the shares of stock that are expected to vest during the severance period of the separation agreement. The net difference of these two amounts resulted in a reduction in 2012 general and administrative expenses of $3.16 million.
Hexagon
Hexagon, LLC (“Hexagon”), the Company’s primary lender, also holds over 5% of the Company’s common stock. On April 15, 2013, the Company and Hexagon agreed to amend the term loans to extend their maturity dates to May 16, 2014. Pursuant to the amendment, Hexagon agreed to (i) reduce the interest rate under the term loans from 15% to 10% beginning retroactively with March 2013, (ii) permit the Company to make interest-only payments for March, April, May, and June 2013, after which time the minimum secured term loan payment became $0.23 million, and (iii) forbear from exercising its rights under the term loan credit agreements for any breach that may have occurred prior to the amendment. In consideration for the extended maturity date, the reduced interest rate and minimum loan payment under the secured term loans, the Company provided Hexagon an additional security interest in 15,000 acres of its undeveloped acreage. (See Note 8-Loan Agreements.)
In addition, Hexagon and its affiliates have interests in certain of the Company’s wells independent of Hexagon’s interests under the term loans, for which Hexagon or its affiliates receive revenue and joint-interest billings.
Other Transactions Involving Directors and Officers
Certain of the Company’s directors and officers participated or committed to participate, directly and indirectly, as investors in the 2013 Debenture offerings (for an aggregate investment of $653,970).
Conflict of Interest Policy
We have a corporate conflict of interest policy that prohibits conflicts of interests unless approved by the board of directors. Our board of directors has established a course of conduct whereby it considers in each case whether the proposed transaction is on terms as favorable or more to the Company than would be available from a non-related party. Our board also looks at whether the transaction is fair and reasonable to us, taking into account the totality of the relationships between the parties involved, including other transactions that may be particularly favorable or advantageous to us. Each of the related party transactions was presented to our board of directors for consideration and each of these transactions was unanimously approved by our board of directors after reviewing the criteria set forth in the preceding two sentences. Each of our purchases from Davis was individually negotiated, and none of the transactions was contingent upon or otherwise related to any other transaction.
NOTE 11 - INCOME TAXES
The tax effects of temporary differences that gave rise to the deferred tax liabilities and deferred tax assets as of December 31, 2013 and 2012 were:
| | | December 31, | |
| | | 2013 | | | 2012 | |
| Deferred tax assets: | | | | | | |
| Oil and gas properties and equipment | | $ | 7,924,585 | | | $ | 8,496,988 | |
| Net operating loss carry-forward | | | 17,373,276 | | | | 14,910,936 | |
| Share based compensation | | | 4,369,953 | | | | 3,885,974 | |
| Abandonment obligation | | | 404,394 | | | | 238,864 | |
| Derivative instruments | | | 2,445 | | | | 173,826 | |
| Other | | | 3,660 | | | | (48,909 | ) |
| Total deferred tax asset | | | 30,078,313 | | | | 27,657,679 | |
| Valuation allowance | | | (30,078,313 | ) | | | (27,657,679 | ) |
| Net deferred tax asset | | $ | - | | | $ | - | |
Reconciliation of the Company’s effective tax rate to the expected federal tax rate is:
| | | For the Year Ended December 31, | |
| | | 2013 | | | 2012 | |
| Effective federal tax rate | | | 35.00 | % | | | 35.00 | % |
| Effect of permanent differences | | | -6.38 | % | | | -4.43 | % |
| State tax rate | | | 1.60 | % | | | 1.64 | % |
| Change in rate | | | - | % | | | - | % |
| Other | | | -5.31 | % | | | - | % |
| Valuation allowance | | | -24.91 | % | | | -32.21 | % |
| Net | | | - | % | | | - | % |
At December 31, 2013 and 2012, the Company had net operating loss carry-forwards for federal income tax purposes of approximately $47.47million and $40.70 million, respectively that may be offset against future taxable income. The Company has established a valuation allowance for the full amount of the deferred tax assets as management does not currently believe that it is more likely than not that these assets will be recovered in the foreseeable future. To the extent not utilized, the net operating loss carry-forwards as of December 31, 2013 will expire in from 2030 through 2033. Net operating loss carryovers may be subject to reduction or limitation by application of Internal Revenue Code Section 382 from the result of ownership changes.
NOTE 12 - SHAREHOLDERS’ EQUITY
Common Stock
As December 31, 2013, the Company had 100,000,000 shares of common stock and 10,000,000 shares of preferred stock authorized, of which 19,671,901 shares of common stock were issued and outstanding. No preferred shares were issued or outstanding.
During the year ended December 31, 2013, the Company issued 1,277,499 shares of common stock, including 636,282 shares to pay interest on convertible debentures, 100,000 paid to the investment banker, and 596,215 shares of common stock as restricted stock grants to employees, board members, or consultants. (See Note 13-Share Based and Other Compensation.)
Investment Banking Agreement
During the year ended December 31, 2013, the Company was party to a one-year, non-exclusive investment banking agreement with TR Winston, pursuant to which the Company issued to TR Winston 100,000 common shares, and 900,000 common stock purchase warrants. All warrants have a term of three years and a strike price of $4.25 per share. The investment banking agreement also provided for additional commissions and compensation in the event that TR Winston arranged a successful equity or debt financing during the term of the agreement. The 900,000 warrants were valued at $0.26 million and the 100,000 common shares were valued at $0.16 million. Both equity instruments are classified as prepaid assets and amortized over the life of the agreement. During the year ended December 31, 2013, $0.25 million was included in general and administrative expense as amortization of the value of these grants. (See Note 10- Related Party Transactions.)
Convertible Debenture Interest
During the year ended December 31, 2013, the Company issued 636,282 shares for payment of yearly interest expense on the convertible debentures valued at $1.17 million.
Warrants
A summary of warrant activity for the nine months ended December 31, 2013 is presented below:
| | | Warrants | | | Weighted-Average Exercise Price | |
| Outstanding at December 31, 2012 | | | 5,638,900 | | | $ | 7.04 | |
| Granted | | | 1,216,263 | | | | 4.25 | |
| Exercised, forfeited, or expired | | | (81,250 | ) | | | (6.00 | ) |
| Outstanding at December 31, 2013 | | | 6,773,913 | | | $ | 5.24 | |
In January 2013, the Company entered into two separate consulting agreements, one with a financial advisory firm and one with a public relations company. Each agreement provided for the issuance by the Company of 200,000 warrants for a total of 400,000 warrants, with an exercise price of $4.25 and a total valuation of $0.26 million. The shares vested 25% on March 31, 2013 and will vest 25% for each quarter thereafter. The Company is valuing the warrants each quarter based on their vesting schedule, and including the amount associated with such vesting warrants as an expense in the period of vesting. During the year ended December 31, 2013, the Company recognized a total expense of $0.26 million for both of the consulting agreements.
The aggregate intrinsic value associated with outstanding warrants as of December 31, 2013 and 2012 was $0, as the strike price of all warrants exceeded the market price for common stock, based on the Company’s closing common stock price of $2.32 and $1.99, respectively. The weighted average remaining contract life as of December 31, 2013 was 1.56 years, and 2.56 years as of December 31, 2012.
NOTE 13 - SHARE BASED AND OTHER COMPENSATION
Share-Based Compensation
In September 2012, the Company adopted the 2012 Equity Incentive Plan (the “Plan”). The Plan was amended by the stockholders on June 27, 2013 to increase the number of common shares available for grant under the EIP from 900,000 shares to 1,800,000 shares and again on November 13, 2013 to increase the number of common shares available for grant under the EIP from 1,800,000 shares to 6,800,000 shares and to increase the number of common shares eligible for grant under the EIP in a single year to a single participant from 1,000,000 shares to 3,000,000 shares. Each member of the board of directors and the management team has been periodically awarded restricted stock grants, and in the future will be awarded such grants under the terms of the Plan.
The costs of employee services received in exchange for an award of equity instruments are based on the grant-date fair value of the award, recognized over the period during which an employee is required to provide services in exchange for such award.
During the year ended December 31, 2013, the Company granted 596,215 shares of restricted common stock to employees, directors and consultants, including 30,002 during the three months ended December 31, 2013. The Company also granted 3,800,000 stock options to employees and board members.
The Company recognized a stock compensation expense of approximately $1.31 million and a credit of $1.75 million, respectively, for the year ended December 31, 2013 and 2012.
Stock Options
A summary of stock options activity for year ended December 31, 2013 is presented below:
| | | Stock Options | |
| Outstanding at December 31, 2012 | | | - | |
| Granted | | | 3,800,000 | |
| Exercised, forfeited, or expired | | | - | |
| Outstanding at December 31, 2013 | | | 3,800,000 | |
In June 2013, the Company entered into employment agreements with the CEO and the then President/CFO for non-cash compensation which consisted of each individual receiving 300,000 stock options of which 100,000 vested immediately and 200,000 were scheduled to vest over the following 2 years. The options had a five-year life and an exercise price of $1.60, volatility of 63%, and an option value of $0.87 per share. The 600,000 stock options were valued at $0.52 million on date of grant. During the year ended December 31, 2013, the Company recognized $0.27 million as non-cash compensation expense and $0.25 million is to be amortized over the remaining vesting period.
In connection with execution of these employment contracts, each executive also agreed to receive 93,750 shares of restricted common stock in lieu of a portion of their cash salaries, to vest on April 15, 2014.
In September, 2013, the Company entered an employment agreement with Abraham Mirman (the “Mirman Agreement”). As an inducement for joining the Company, Mr. Mirman was granted 100,000 shares of the Company’s common stock, which vested immediately, was valued at $0.25 million, and was expensed as of the date of the grant. Mr. Mirman was also granted an option to purchase up to 600,000 shares of common stock of the Company, at a strike price of $2.45 per share, equal to the Company’s closing share price on September 16, 2013. This option will become exercisable upon the date the Company receives gross cash proceeds and/or drawing availability under a line of credit of at least $30,000,000, measured on a cumulative basis and including certain restructuring transactions. As such, the Company anticipates that this option will become exercisable if our shareholders subsequently approve the conversion of the remaining Debentures.
Mr. Mirman was also granted options to purchase up to 2,000,000 shares of the Company’s common stock, 666,667 of which become exercisable if the Company has a reported share price of $7.50 and average daily production of 2,500 barrels of oil equivalent per day for a continuous 90-day period, and 666,667 and 666,666 of which become exercisable upon the same daily production condition and reported share prices of $10.00 per share and $12.50 per share, respectively.
The Company received independent valuations of the i) option to purchase 600,000 shares of common stock; ii) the incentive bonus; and iii) the options to purchase 2,000,000 shares. The option to purchase 600,000 shares was valued at $0.61 million and is being amortized over the life of the Mirman Agreement, which expires on December 31, 2014. The incentive bonus was valued at $0.15 million, and is recorded as a liability. This liability will be revalued at each balance sheet date. The options to purchase 2,000,000 shares were valued at $0.05 million and are being amortized over the life of the Mirman Agreement.
In October 2013, the Company granted each of its independent directors 200,000 non-statutory options to purchase the Company’s common stock at an exercise price of $2.05, equal to the closing price at October 24, 2013. The options vest one-third for the next three years on the anniversary grant date. The value of the 600,000 options at grant date was $0.64 million and will be amortized over the vesting period.
A summary of restricted stock grant activity for the year ended December 31, 2013 is presented below:
| | | Shares | |
| Balance outstanding at December 31, 2012 | | | 1,730,710 | |
| Granted | | | 596,215 | |
| Vested | | | (196,008 | ) |
| Expired/ cancelled | | | (106,542 | ) |
| Balance outstanding at December 31, 2013 | | | 2,024,375 | |
Total unrecognized compensation cost related to unvested stock grants was approximately $0.30 million as of December 31, 2013. The cost at December 31, 2013 is expected to be recognized over a weighted-average remaining service period of 3 years.
Separation Agreement
In April 2014, the Company entered into a separation agreement with the W. Phillip Marcum, the Chief Executive Officer until April 16, 2014. The company provided Mr. Marcum with one year of severance compensation, to be paid through normal payroll practices. Furthermore, he received the immediate vesting of 200,000 options to purchase stock and the conversion of the remaining amount of the 2013 compensation into $0.15 million cash from 93,780 shares of stock. (See Note 14-Subsequent Events.)
Employment Agreement
In April 2014, we announced the appointment of Robert (Bob) A. Bell as our new Chief Operating Officer and President. In connection with Mr. Bell’s appointment, the Company entered an employment agreement with Mr. Bell (the “Bell Agreement”), which has an initial term of three years, provides for an annual base salary of $240,000 subject to adjustment by the Company, as well as a signing bonus of $100,000 and 100,000 shares of common stock, subject to certain conditions set forth in the Bell Agreement. In addition, Mr. Bell will receive an equity incentive bonus consisting of a non-statutory stock option to purchase up to 1,500,000 shares of common stock and a cash incentive bonus of up to $1,000,000, both subject to Mr. Bell’s continued employment. In addition, Mr. Bell’s incentive bonuses are subject to the Company’s achievement of certain production thresholds set forth in the Bell Agreement. (See Note 14-Subsequent Events.)
Other Compensation
We sponsor a 401(k) savings plan. All regular full-time employees are eligible to participate. We make contributions to match employee contributions up to 5% of compensation deferred into the plan. The Company made cash contributions of $0.03 million for the year ended December 31, 2013.
NOTE 14- SUBSEQUENT EVENTS
January 2014 Private Placement
On January 22, 2014, the Company entered into and closed a series of subscription agreements with accredited investors, pursuant to which the Company issued an aggregate of 2,959,125 units, with each unit consisting of (i) one share of the Company’s 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 $5,918,250 (the “January Private Placement”). The Company’s officers and directors have agreed to purchase an additional $1,425,000 of Units subject to receipt of shareholder approval as required by NASDAQ’s continued listing requirements. The warrants are not exercisable for six months following the closing of the January Private Placement. At any time following the closing of the Private Offering, the Company may force the exercise of the warrants provided the shares underlying the warrants are registered, the Common Stock has traded at or above $10.00 per share for a period of twenty (20) consecutive trading days with a minimum daily average volume of 100,000 shares, and the Company has given the Investors at least twenty (20) trading days’ notice.
Debenture Conversion
On January 31, 2014, the Company entered into a Debenture Conversion Agreement (the “Conversion Agreement”), between the Company and all of the holders of the Debentures. Under the terms of the Conversion Agreement, $9 million of the approximately $15.6 million in Debentures then outstanding immediately converted to common stock at a price of $2.00 per common share. The balance of the Debentures may be converted to common stock, subject to receipt of shareholder approval as required by the NASDAQ continued listing requirements. As additional inducement for the conversions, the Company issued warrants to the converting Debenture holders to purchase one share of Common Stock, at an exercise price equal to $2.50 per share, for each share of Common Stock issued upon conversion of the Debentures. The shares underlying the warrants have not been registered under the Securities Act of 1933, as amended, or any state securities laws and may not be offered or sold in the United States absent registration or an applicable exemption from registration.
A shareholders’ meeting to approve i) participation by officers and directors in the Private Offering, and ii) the conversion of the remaining outstanding Debentures is pending, and is anticipated to be held during the third quarter of 2014.
Employment Agreement
In April 2014, we announced the appointment of Robert A. (Bob) Bell as our new President and Chief Operating Officer. In connection with Mr. Bell’s appointment, the Company entered an employment agreement with Mr. Bell (the “Bell Agreement”), which has an initial term of three years, provides for an annual base salary of $240,000 subject to adjustment by the Company, as well as a signing bonus of $100,000 and 100,000 shares of common stock of which 1/3 vest immediately and the balance over three years, subject to certain conditions set forth in the Bell Agreement. In addition, Mr. Bell will receive an equity incentive bonus consisting of a non-statutory stock option to purchase up to 1,500,000 shares of common stock and a cash incentive bonus of up to $1,000,000, both subject to Mr. Bell’s continued employment. In addition, Mr. Bell’s incentive bonuses are subject to the Company’s achievement of certain pre-defined production thresholds set forth in the Bell Agreement.
Separation Agreement
In April 2014, the Company entered into a separation agreement (the “Marcum Agreement”) with W. Phillip Marcum in connection with his resignation from his positions with the Company. The Marcum Agreement provides, among other things, that, consistent with his resignation for good reason under his Employment Agreement, the Company will pay him 12 months of severance through payroll continuation, in the gross amount of $220,000, less all applicable withholdings and taxes, that all stock options held by Mr. Marcum as of the time of his termination will immediately vest, and that Mr. Marcum will remain eligible to receive any performance bonus granted by the Company to its senior executives with respect to Company and/or executive performance in 2013. In addition, the Marcum Agreement provides that the Company will pay Mr. Marcum $150,000 in accrued base salary for his service in 2013, less all applicable withholdings and taxes, in exchange for Mr. Marcum’s forfeiture of the 93,750 shares of unvested restricted common stock of the Company that was issued to Marcum in June 2013 in lieu of such base salary. Mr. Marcum may elect to apply amounts payable under the Marcum Agreement against his commitment to invest $125,000 in the Company’s previously disclosed private offering, upon shareholder approval of the participation of the Company’s officers and directors in that offering. The Marcum Agreement also contains certain mutual non-disparagement covenants, as well as certain mutual confidentiality, non-solicitation and non-compete covenants. In addition, Mr. Marcum and the Company each mutually released and discharged all known and unknown claims against the other and their respective representatives that they had or presently may have, including claims relating to Mr. Marcum’s employment. The Marcum Agreement effectively terminated the previously disclosed Employment Agreement entered into between Mr. Marcum and the Company, dated as of June 25, 2013.
Hexagon Settlement
On May 19, 2014, the Company received an extension from Hexagon of the maturity date under our term loans, from May 16, 2014 to August 15, 2014. As of May 16, 2014, there was an aggregate of $18.77 million outstanding under the term loans, which are collateralized by mortgages against a portion of the Company’s developed and undeveloped leasehold acreage.
In connection with the extension, Hexagon and the Company agreed in principal to the settlement of all amounts outstanding under the term loans, pursuant to which (1) the Company will make a cash payment of $5.0 million no later than May 30, 2014 (the “First Cash Payment”), (2) the Company will make a cash payment of $5.0 million no later than June 30, 2014 (the “Second Cash Payment” and together with the First Cash Payment, the “Cash Payments”), (3) the Company will issue to Hexagon a two-year $6 million unsecured note (the “Hexagon Replacement Note”), bearing interest at an annual rate of 8%, requiring principal and interest payments of $90,000 per month, maturity May 30, 2016, and (4) the Company will issue to Hexagon 943,208 shares of unregistered common stock. The parties have also agreed that if either of the Cash Payments is not made on time, an additional $1.0 million in principal will be added to the Hexagon Replacement Note, and if the Hexagon Replacement Note is not retired by December 31, 2014, the Company will issue an additional 1.0 million shares of its common stock to Hexagon. Finally, Hexagon will not, until the earlier of June 30, 2014 or the date the Company achieves sustained average trading volume in excess of 100,000 shares per day for at least ten consecutive trading days, sell or otherwise transfer for value any shares of the Company’s common stock or any securities convertible into the Company’s common stock, and that thereafter until December 31, 2014, Hexagon will not sell or otherwise transfer for value more than 10,000 shares per week of the Company’s common stock or any securities convertible into the Company’s common stock.
Debentures Extension
On May 19, 2014, holders of the remaining Debentures agreed to extend the maturity date under the Debentures from May 16, 2014 to August 15, 2014, and to waive their right to declare an event of default in connection with the May 16, 2014 maturity date under the Debentures. On June 6, 2014, the holders of the remaining Debentures agreed to further extend the maturity date under the Debentures from August 15, 2014 to January 15, 2015.
May Private Placement
On May 30, 2014 the Company entered into and consummated a private placement (the “May Private Placement”) of its 8% Convertible Preferred Stock (“Preferred Stock”) with accredited investors, pursuant to which the company sold $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. The Company has the right to convert the Preferred Stock to common stock if the common stock is traded at $7.50 for ten consecutive trading days and the underlying shares of common stock are registered for resale. TR Winston was the placement agent for the transaction and will be paid a fee equal to 8% of the proceeds plus an additional 1% of the proceeds plus $25,000 in expenses. The Company used $5.00 million of the proceeds of the private placement to make the first cash payment in connection with the Hexagon settlement (discussed above), and intends to use 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 effect the purchase by third parties of an additional $15 million in Preferred Stock, which transaction is to be consummated within ninety (90) days.
NOTE 15- SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED)
The following table sets forth information for the years ended December 31, 2013 and 2012 with respect to changes in the Company's proved (i.e. proved developed and undeveloped) reserves:
| | | Crude Oil (Bbls) | | | Natural Gas (Mcf) | |
| December 31, 2011 | | | 608,237 | | | | 148,077 | |
| Purchase of reserves | | | 39,327 | | | | - | |
| Revisions of previous estimates | | | (310,919 | ) | | | 25,813 | |
| Extensions, discoveries | | | 99,615 | | | | 313,958 | |
| Sale of reserves | | | - | | | | - | |
| Production | | | (85,160 | ) | | | (80,438 | ) |
| December 31, 2012 | | | 351,100 | | | | 407,410 | |
| Purchase of reserves | | | 7,825 | | | | - | |
| Revisions of previous estimates | | | 512,023 | | | | 2,238,788 | |
| Extensions, discoveries | | | 36,325 | | | | - | |
| Sale of reserves | | | (12,848 | ) | | | (17,076 | ) |
| Production | | | (51,706 | ) | | | (64,845 | ) |
| December 31, 2013 | | | 842,719 | | | | 2,564,277 | |
| Proved Developed Reserves, included above: | | | | | | | | |
| Balance, December 31, 2011 | | | 215,693 | | | | 148,077 | |
| Balance, December 31, 2012 | | | 213,306 | | | | 186,017 | |
| Balance, December 31, 2013 | | | 170,531 | | | | 313,358 | |
| Proved Undeveloped Reserves, included above: | | | | | | | | |
| Balance, December 31, 2011 | | | 392,545 | | | | - | |
| Balance, December 31, 2012 | | | 137,555 | | | | 221,314 | |
| Balance, December 31, 2013 (2) | | | 672,188 | | | | 2,250,920 | |
As of December 31, 2013 and December 31, 2012, we had estimated proved reserves of 842,719 and 351,100 barrels of oil, respectively and 427,380 and 67,902 thousand cubic feet ("MCF") of natural gas converted to BOE, respectively. Our reserves are comprised of 66% and 84% crude oil and 34% and 16% natural gas on an energy equivalent basis, as of December 31, 2013 and December 31, 2012, respectively.
The following values for the December 31, 2013 and December 31, 2012 oil and gas reserves are based on the 12 month arithmetic average first of month price January through December 31; resulting in a natural gas price of $4.31 and $2.75 per MMBtu (NYMEX price), respectively, and crude oil price of $89.56 and $87.37 per barrel (West Texas Intermediate price), respectively. All prices are then further adjusted for transportation, quality and basis differentials.
The following summary sets forth the Company's future net cash flows relating to proved oil and gas reserves:
| | | For the Year Ended December 31, | |
| | | (in thousands) | |
| | | 2013 | | | 2012 | |
| Future oil and gas sales | | $ | 86,521 | | | $ | 32,612 | |
| Future production costs | | | (22,095 | ) | | | (9,718 | ) |
| Future development costs | | | (21,980 | ) | | | (546 | ) |
| Future income tax expense (1) | | | - | | | | - | |
| Future net cash flows | | | 42,446 | | | | 22,348 | |
| 10% annual discount | | | (19,104 | ) | | | (6,926 | ) |
| | | | | | | | | |
| Standardized measure of discounted future net cash flows (2) | | $ | 23,342 | | | $ | 15,422 | |
The principal sources of change in the standardized measure of discounted future net cash flows are (in thousands):
| | | 2013 | | | 2012 | |
| Balance at beginning of period | | $ | 15,422 | | | $ | 20,014 | |
| Sales of oil and gas, net | | | (3,172 | ) | | | (4,656 | ) |
| Net change in prices and production costs | | | (879 | ) | | | (1,724 | ) |
| Net change in future development costs (2) | | | (20,311 | ) | | | 7,766 | |
| Extensions and discoveries (2) | | | 686 | | | | 3,916 | |
| Acquisition of reserves | | | 202 | | | | 1,677 | |
| Sale of reserves | | | (643 | ) | | | - | |
| Revisions of previous quantity estimates (2) | | | 30,968 | | | | (15,031 | ) |
| Previously estimated development costs incurred | | | - | | | | 638 | |
| Net change in income taxes | | | - | | | | - | |
| Accretion of discount | | | 1,864 | | | | 2,001 | |
| Other | | | (795 | ) | | | 821 | |
| Balance at end of period | | $ | 23,342 | | | $ | 15,422 | |
| (1) | Our calculations of the standardized measure of discounted future net cash flows include the effect of estimated future income tax expenses for all years reported. We expect that all of our Net Operating Loss’ (“NOL”) will be realized within future carry forward periods. All of the Company's operations, and resulting NOLs, are attributable to our oil and gas assets. There were no taxes in any year as the tax basis and NOLs exceeded the future net revenue. |
| (2) | Total proven reserves as of December 31, 2013 are $23.34 million compared to reserves of $15.42 million for the year ended December 31, 2012, an increase of $7.92 million or 51%. This increase in standardized measure reflects an increase in proved undeveloped reserves to 1,047 MBOE in 2013 from 175 MBOE in 2012, an increase of 872 MBOE. This increase, in part, reflects the uncertainty in 2012 regarding whether the Company would have sufficient capital to support its current development plan. Proved undeveloped reserves in 2012 were estimated under the assumption that certain farm-outs and joint venture arrangements were required in order to finance development of such reserves. This assumption lowered both the reserve values and capital requirements. This assumption was removed in the preparation of the Company’s 2013 reserve estimates due to the Company’s improving financial health. Proved undeveloped reserves also increased as a result of a change in the development plan for one of the Company’s major properties. The development plan was modified from a vertical to a horizontal program due principally to recent development activities in adjacent and nearby drilling units, resulting in significant increases in units attributable to revisions of previous estimates. At December 31, 2013, we have no proved undeveloped reserves that are scheduled for development five years or more beyond the date the reserves were initially recorded. |
Revisions of previous quantity estimate in 2013 reflect the incremental reserve value from the reinstatement of PUD’s which were recorded in 2012 on a promoted basis. Additionally, the Company increased extension and discoveries by new discoveries by existing Proved Developed Production and improved recoveries in our Wattenberg prospect.
A variety of methodologies are used to determine our proved reserve estimates. The principal methodologies employed are reservoir simulation, decline curve analysis, volumetric, material balance, advance production type curve matching, petro-physics/log analysis and analogy. Some combination of these methods is used to determine reserve estimates in substantially all of our fields.
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