ITEM 1A. RISK FACTORS.
In the course of conducting our business operations, we are exposed to a variety of risks that are inherent to the oil and gas industry. The following discusses some of the key inherent risk factors that could affect our business and operations. Other factors besides those discussed below or elsewhere in this report also could adversely affect our business and operations, and these risk factors should not be considered a complete list of potential risks that may affect us.
Risks Related to Recent Developments
Our 2014 oil and gas reserve report shows a material decline in our estimated reserves, which will have adverse implications to our business.
Our 2014 oil and gas reserve report shows a material decline in our estimated reserves. There are numerous uncertainties inherent in estimating quantities of proved oil and natural gas reserves and in projecting future rates of production and timing of development expenditures, including many factors beyond our control. For example, estimates of quantities of proved reserves and their PV10 value are affected by changes in crude oil and gas prices, because estimates are based on prevailing prices at the time of their determination. Further, reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in any exact way, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, estimates made by different engineers often vary from one another.
The reduction in our reserve estimates is likely to change the schedule of future production and development drilling that was contemplated in our 2013 reserve report. Reserve estimates are generally different, and often materially so, from the quantities of oil and natural gas that are ultimately recovered. Furthermore, estimates of quantities of proved reserves and their PV10 value may be affected by changes in crude oil and gas prices because the Company’s estimates are based on prevailing prices at the time of their determination.
Our 2014 oil and gas report has caused a material reduction in our borrowing base under our revolving credit facility, resulting in us being overdrawn on our credit facilities.
Our maximum borrowings under our credit facility are subject to reduction based upon a borrowing base calculation, which is re-determined using updated reserve reports. Because our 2014 reserve report shows a material reduction in reserves as discussed above, our borrowing base will be similarly reduced. Such a reduction could show that we are overdrawn on our credit facilities and therefore not in compliance with the financial covenants imposed by our lenders.
If this occurs our lenders may impose a plan requiring that we reduce the amount of that overdraft. Any such plan may include an adjustment in the interest rate on our secured credit facilities and a requirement for regular amortizing payments. Any such plan would likely require, among other things, that we apply our net cash flow to repayment of the principal of our secured credit facilities, limit our ability to pay our ordinary operating expenses as they become due, limit our new production activities, and may require that we suspend payment of dividends on our series A preferred stock. All of those factors will adversely affect the results of our operations and our stock price.
Current volatile market conditions and significant fluctuations in energy prices may continue indefinitely, negatively affecting our business prospects and viability.
The oil and gas markets are very volatile, and we cannot predict future oil and natural gas prices. Historically, oil and natural gas prices have been volatile and are subject to fluctuations in response to changes in supply and demand, market uncertainty and a variety of additional factors that are beyond our control. Any substantial decline in the price of oil and natural gas will likely have a material adverse effect on our planned operations and financial condition. The amount of any royalty payment we receive, if any, from the production of oil and gas from our oil and gas interests will depend on numerous factors beyond our control.
Declining economic conditions and worsening geopolitical conditions could negatively impact our business.
Our operations are affected by local, national and worldwide economic conditions. Markets in the United States and elsewhere have been experiencing volatility and disruption for more than 5 years, due in part to the financial stresses affecting the liquidity of the banking system and the financial markets generally. The consequences of a potential or prolonged recession may include a lower level of economic activity and uncertainty regarding energy prices and the capital and commodity markets.
In addition, actual and attempted terrorist attacks in the United States, Middle East, Southeast Asia and Europe, and war or armed hostilities in the Middle East, the Persian Gulf, North Africa, Iran, North Korea or elsewhere, or the fear of such events, could further exacerbate the volatility and disruption to the financial markets and economy.
While the ultimate outcome and impact of the current economic conditions cannot be predicted, a lower level of economic activity might result in a decline in energy consumption, which may materially adversely affect the price of oil and gas, our revenues, liquidity and future growth. Instability in the financial markets, as a result of recession or otherwise, also may affect the cost of capital and our ability to raise capital.
The oil and natural gas business involves numerous uncertainties and operating risks that can prevent us from realizing profits and can cause substantial losses.
Our development, exploitation and exploration activities may be unsuccessful for many reasons, including weather, cost overruns, equipment shortages and mechanical difficulties. Moreover, the successful drilling of a well does not ensure a profit on investment. A variety of factors, both geological and market-related, can cause a well to become uneconomical or only marginally economical. In addition to their cost, unsuccessful wells can hurt our efforts to replace reserves.
The oil and natural gas business involves a variety of operating risks, including:
· unexpected operational events and/or conditions;
· reductions in oil and natural gas prices;
· limitations in the market for oil and natural gas;
· adverse weather conditions;
· facility or equipment malfunctions;
· title problems;
· oil and gas quality issues;
· pipe, casing, cement or pipeline failures;
· natural disasters;
· fires, explosions, blowouts, surface cratering, pollution and other risks or accidents;
· environmental hazards, such as oil spills, pipeline ruptures and discharges of toxic gases;
· compliance with environmental and other governmental requirements; and
· uncontrollable flows of oil or natural gas or well fluids.
If we experience any of these problems, it could affect well bores, gathering systems and processing facilities, which could adversely affect our ability to conduct operations. We could also incur substantial losses as a result of:
· injury or loss of life;
· severe damage to and destruction of property, natural resources and equipment;
· pollution and other environmental damage;
· clean-up responsibilities;
· regulatory investigation and penalties;
· suspension of our operations; and
· repairs to resume operations.
Because we use third-party drilling contractors to drill our wells, we may not realize the full benefit of worker compensation laws in dealing with their employees. Our insurance does not protect us against all operational risks. We do not carry business interruption insurance at levels that would provide enough funds for us to continue operating without access to other funds. For some risks, we may not obtain insurance if we believe the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. If a significant accident or other event occurs and is not fully covered by insurance, it could impact our operations enough to force us to cease our operations.
Oil and gas prices are volatile. Future volatility may cause negative change in cash flows which may result in our inability to cover our operating or capital expenditures.
Our future revenues, profitability, future growth and the carrying value of our properties depend substantially on the prices we may realize for our oil and gas production. Our realized prices may also affect the amount of cash flow available for operating or capital expenditures and our ability to borrow and raise additional capital.
Oil and gas prices are subject to wide fluctuations in response to relatively minor changes in or perceptions regarding supply and demand. Historically, the markets for oil and gas have been volatile, and they are likely to continue to be volatile in the future. Among the factors that can cause this volatility are:
·commodities speculators;
·local, national and worldwide economic conditions;
·worldwide or regional demand for energy, which is affected by economic conditions;
·the domestic and foreign supply of oil and gas;
·weather conditions;
·natural disasters;
·acts of terrorism;
·domestic and foreign governmental regulations and taxation;
·political and economic conditions in oil and gas producing countries, including those in the Middle East and South America;
·impact of the U.S. dollar exchange rates on oil and gas prices;
·the availability of refining capacity;
·actions of the Organization of Petroleum Exporting Countries, or OPEC, and other state controlled oil and gas companies relating to oil and gas price and production controls; and
·the price and availability of other fuels.
It is impossible to predict oil and gas price movements with certainty. A drop in oil and gas prices may not only decrease our future revenues on a per unit basis but also may reduce the amount of oil and gas that we can produce economically. A substantial or extended decline in oil and gas prices would materially and adversely affect our future business enough to potentially force us to cease our business operations. In addition, our reserves, financial condition, results of operations, liquidity and ability to finance and execute planned capital expenditures will also suffer in such a price decline.
Approximately 31% of our total proved reserves as of December 31, 2014 consist of undeveloped reserves, and those reserves may not ultimately be developed or produced.
Our estimated total proved PV10 (present value) before tax of reserves as of December 31, 2014 was $64.3 million, versus $102.4 million as of December 31, 2013. Of the 4.4 million BOE of total proved reserves, approximately 50% are classified as proved developed producing, approximately 19% are classified as proved developed non-producing, and approximately 31% are classified as proved undeveloped.
Assuming we can obtain adequate capital resources, we plan to develop and produce all of our proved reserves, but ultimately some of these reserves may not be developed or produced. Furthermore, not all of our undeveloped or developed non-producing reserves may be produced in the time periods we have planned, at the costs we have budgeted, or at all.
Because we face uncertainties in estimating proved recoverable reserves, you should not place undue reliance on such reserve information.
Our reserve estimates and the future net cash flows attributable to those reserves at December 31, 2014 were prepared by MHA Petroleum Consultants LLC, an independent petroleum consultant. There are numerous uncertainties inherent in estimating quantities of proved reserves and cash flows from such reserves, including factors beyond our control and the control of these independent consultants and engineers. Reserve engineering is a subjective process of estimating underground accumulations of oil and gas that can be economically extracted, which cannot be measured in an exact manner. The accuracy of an estimate of quantities of reserves, or of cash flows attributable to these reserves, is a function of the available data, assumptions regarding future oil and gas prices, expenditures for future development and exploitation activities, and engineering and geological interpretation and judgment. Reserves and future cash flows may also be subject to material downward or upward revisions based upon production history, development and exploitation activities and oil and gas prices. Actual future production, revenue, taxes, development expenditures, operating expenses, quantities of recoverable reserves and value of cash flows from those reserves may vary significantly from the assumptions and estimates in our reserve reports. Any significant variance from these assumptions to actual figures could greatly affect our estimates of reserves, the economically recoverable quantities of oil and gas attributable to any particular group of properties, the classification of reserves based on risk of recovery, and estimates of the future net cash flows. In addition, reserve engineers may make different estimates of reserves and cash flows based on the same available data. The estimated quantities of proved reserves and the discounted present value of future net cash flows attributable to those reserves included in this report were prepared by MHA Petroleum Consultants LLC in accordance with rules of the Securities and Exchange Commission, or SEC, and are not intended to represent the fair market value of such reserves.
The present value of future net cash flows from our proved reserves is not necessarily the same as the current market value of our estimated reserves. We base the estimated discounted future net cash flows from our proved reserves on prices and costs. However, actual future net cash flows from our oil and gas properties also will be affected by factors such as:
·geological conditions;
·assumptions governing future oil and gas prices;
·amount and timing of actual production;
·availability of funds;
·future operating and development costs;
·actual prices we receive for oil and gas;
·changes in government regulations and taxation; and
·capital costs of drilling new wells
The timing of both our production and our incurrence of expenses in connection with the development and production of our properties will affect the timing of actual future net cash flows from proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating discounted future net cash flows may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with our business or the oil and gas industry in general.
The differential between the New York Mercantile Exchange, or NYMEX, or other benchmark price of oil and gas and the wellhead price we receive could have a material adverse effect on our results of operations, financial condition and cash flows.
The prices that we receive for our oil production in Texas, Colorado and Kansas are typically based on a discount to the relevant benchmark prices, such as NYMEX, that are used for calculating hedge positions. The prices we receive for our natural gas production in Colorado is based upon local market conditions but generally we receive a discount to Henry Hub. The difference between the benchmark price and the price we receive is called a differential. We cannot accurately predict oil and gas differentials. In recent years for example, production increases from competing North American producers, in conjunction with limited refining and pipeline capacity have widened this differential. Recent economic conditions, including volatility in the price of oil and gas, have resulted in both increases and decreases in the differential between the benchmark price for oil and gas and the wellhead price we receive. These fluctuations could have a material adverse effect on our results of operations, financial condition and cash flows by decreasing the proceeds we receive for our oil and gas production in comparison to what we would receive if not for the differential.
The oil and gas business involves numerous uncertainties and operating risks that can prevent us from realizing profits and can cause substantial losses.
Our development, exploitation and exploration activities may be unsuccessful for many reasons, including weather, cost overruns, equipment shortages and mechanical difficulties. Moreover, the successful drilling of an oil and gas well does not ensure a profit on investment. A variety of factors, both geological and market-related, can cause a well to become uneconomical or only marginally economical. In addition to their cost, unsuccessful wells can hurt our efforts to replace reserves.
The oil and gas business involves a variety of operating risks, including:
·unexpected operational events and/or conditions;
·reductions in oil and gas prices;
·limitations in the market for oil and gas;
·adverse weather conditions;
·facility or equipment malfunctions;
·title problems;
·oil and gas quality issues;
·pipe, casing, cement or pipeline failures;
·natural disasters;
·fires, explosions, blowouts, surface cratering, pollution and other risks or accidents;
·environmental hazards, such as oil spills, pipeline ruptures and discharges of toxic gases;
·compliance with environmental and other governmental requirements; and
·uncontrollable flows of oil and gas or well fluids
If we experience any of these problems, it could affect well bores, gathering systems and processing facilities, which could adversely affect our ability to conduct operations. We could also incur substantial losses as a result of:
·injury or loss of life;
·severe damage to and destruction of property, natural resources and equipment;
·pollution and other environmental damage;
·clean-up responsibilities;
·regulatory investigation and penalties;
·suspension of our operations; and
·repairs to resume operations
Because we use third-party drilling contractors to drill our wells, we may not realize the full benefit of worker compensation laws in dealing with their employees. Our insurance does not protect us against all operational risks. We do not carry business interruption insurance at levels that would provide enough funds for us to continue operating without access to other funds. For some risks, we may not obtain insurance if we believe the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. If a significant accident or other event occurs and is not fully covered by insurance, it could impact our operations enough to force us to cease our operations.
Drilling wells is speculative, and any material inaccuracies in our forecasted drilling costs, estimates or underlying assumptions will materially affect our business.
Developing and exploring for oil and gas involves a high degree of operational and financial risk, which precludes definitive statements as to the time required and costs involved in reaching certain objectives. The budgeted costs of drilling, completing and operating wells are often exceeded and can increase significantly when drilling costs rise due to a tightening in the supply of various types of oil and gas field equipment and related services. Drilling may be unsuccessful for many reasons, including geological conditions, weather, cost overruns, equipment shortages and mechanical difficulties. Moreover, the successful drilling of an oil and gas well does not ensure a profit on investment. Exploratory wells bear a much greater risk of loss than development wells. Substantially all of our wells drilled through December 31, 2014 have been development wells. A variety of factors, both geological and market-related, can cause a well to become uneconomical or only marginally economic. Our initial drilling and development sites, and any potential additional sites that may be developed, require significant additional exploration and development, regulatory approval and commitments of resources prior to commercial development. If our actual drilling and development costs are significantly more than our estimated costs, we may not be able to continue our business operations as proposed and would be forced to modify our plan of operation.
Development of our reserves, when established, may not occur as scheduled and the actual results may not be as anticipated. Drilling activity and lack of access to economically acceptable capital may result in downward adjustments in reserves or higher than anticipated costs. Our estimates will be based on various assumptions, including assumptions over which we have control and assumptions required by the SEC relating to oil and gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. We have control over our operations that affect, among other things, acquisitions and dispositions of properties, availability of funds, use of applicable technologies, hydrocarbon recovery efficiency, drainage volume and production decline rates that are part of these estimates and assumptions and any variance in our operations that affects these items within our control may have a material effect on reserves. The process of estimating our oil and gas reserves is extremely complex, and requires significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir. Our estimates may not be reliable enough to allow us to be successful in our intended business operations. Our actual production, revenues, taxes, development expenditures and operating expenses will likely vary from those anticipated. These variances may be material.
Unless we replace our oil and gas reserves, our reserves and production will decline, which would adversely affect our cash flows and income.
Unless we conduct successful development, exploitation and exploration activities or acquire properties containing proved reserves, our proved reserves will decline as those reserves are produced. Producing oil and gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Our future oil and gas production, and, therefore our cash flow and income, are highly dependent on our success in efficiently developing and exploiting our current reserves and economically finding or acquiring additional recoverable reserves. We may be unable to make such acquisitions because we are:
·unable to identify attractive acquisition candidates or negotiate acceptable purchase contracts with them;
·unable to obtain financing for these acquisitions on economically acceptable terms; or
·outbid by competitors.
If we are unable to develop, exploit, find or acquire additional reserves to replace our current and future production, our cash flow and income will decline as production declines, until our existing properties would be incapable of sustaining commercial production.
In order to exploit successfully our current oil and gas leases and others that we acquire in the future, we will need to generate significant amounts of capital.
The oil and gas exploration, development and production business is a capital-intensive undertaking. In order for us to be successful in acquiring, investigating, developing, and producing oil and gas from our current mineral leases and other leases that we may acquire in the future, we will need to generate an amount of capital in excess of that generated from our results of operations. In order to generate that additional capital, we may need to obtain an expanded debt facility and issue additional shares of our equity securities. There can be no assurance that we will be successful in either obtaining that expanded debt facility or issuing additional shares of our equity securities, and our inability to generate the needed additional capital may have a material adverse effect on our prospects and financial results of operations. If we are able to issue additional equity securities in order to generate such additional capital, then those issuances may occur at prices that represent discounts to our trading price, and will dilute the percentage ownership interest of those persons holding our shares prior to such issuances. Unless we are able to generate additional enterprise value with the proceeds of the sale of our equity securities, those issuances may adversely affect the value of our shares that are outstanding prior to those issuances.
A significant portion of our potential future reserves and our business plan depend upon secondary recovery techniques to establish production. There are significant risks associated with such techniques.
We anticipate that a significant portion of our future reserves and our business plan will be associated with secondary recovery projects that are either in the early stage of implementation or are scheduled for implementation subject to availability of capital. We anticipate that secondary recovery will affect our reserves and our business plan, and the exact project initiation dates and, by the very nature of waterflood operations, the exact completion dates of such projects are uncertain. In addition, the reserves and our business plan associated with these secondary recovery projects, as with any reserves, are estimates only, as the success of any development project, including these waterflood projects, cannot be ascertained in advance. If we are not successful in developing a significant portion of our reserves associated with secondary recovery methods, then the project may be uneconomic or generate less cash flow and reserves than we had estimated prior to investing the capital. Risks associated with secondary recovery techniques include, but are not limited to, the following:
·higher than projected operating costs;
·lower-than-expected production;
·longer response times;
·higher costs associated with obtaining capital;
·unusual or unexpected geological formations;
·fluctuations in oil and gas prices;
·regulatory changes;
·shortages of equipment; and
·lack of technical expertise.
If any of these risks occur, it could adversely affect our financial condition or results of operations.
Any acquisitions we complete are subject to considerable risk.
Even when we make acquisitions that we believe are good for our business, all acquisitions involve potential risks, including, among other things:
·the validity of our assumptions about reserves, future production, revenues and costs, including synergies;
·an inability to integrate successfully the businesses we acquire;
·a decrease in our liquidity by using our available cash or borrowing capacity to finance acquisitions;
·a significant increase in our interest expense or financial leverage if we incur additional debt to finance acquisitions;
·the assumption of unknown liabilities, losses or costs for which we are not indemnified or for which our indemnity is inadequate;
·the diversion of management's attention from other business concerns;
·an inability to hire, train or retain qualified personnel to manage the acquired properties or assets;
·the incurrence of other significant charges, such as impairment of goodwill or other intangible assets, asset devaluation or restructuring charges;
·unforeseen difficulties encountered in operating in new geographic or geological areas; and
·customer or key employee losses at the acquired businesses.
Our decision to acquire a property will depend in part on the evaluation of data obtained from production reports and engineering studies, geophysical and geological analyses and seismic and other information, the results of which are often incomplete or inconclusive.
Our reviews of acquired properties can be inherently incomplete because it is not always feasible to perform an in-depth review of the individual properties 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. Inspections may not always be performed on every well, and environmental problems, such as ground water contamination, plugging or orphaned well liability are not necessarily observable even when an inspection is undertaken.
We must obtain governmental permits and approvals for drilling operations, which can result in delays in our operations, be a costly and time consuming process, and result in restrictions on our operations.
Regulatory authorities exercise considerable discretion in the timing and scope of permit issuances in the regions in which we operate. Compliance with the requirements imposed by these authorities can be costly and time consuming and may result in delays in the commencement or continuation of our exploration or production operations and/or fines. Regulatory or legal actions in the future may materially interfere with our operations or otherwise have a material adverse effect on us. In addition, we are often required to prepare and present to federal, state or local authorities data pertaining to the effect or impact that a proposed project may have on the environment, threatened and endangered species, and cultural and archaeological artifacts. Accordingly, the permits we need may not be issued, or if issued, may not be issued in a timely fashion, or may involve requirements that restrict our ability to conduct our operations or to do so profitably.
Due to our lack of geographic diversification, adverse developments in our operating areas would materially affect our business.
We currently only lease and operate oil and gas properties located in Colorado, Nebraska, Kansas and Texas. As a result of this concentration, we may be disproportionately exposed to the impact of delays or interruptions of production from these properties caused by significant governmental regulation, transportation capacity constraints, curtailment of production, natural disasters, adverse weather conditions or other events which impact this area.
We depend on a small number of customers for all, or a substantial amount of our sales. If these customers reduce the volumes of oil and gas they purchase from us, our revenue and cash flow will decline to the extent we are not able to find new customers for our production.
We currently sell oil to two purchasers in Kansas: Coffeyville Resources and Plains Marketing, LP. There are approximately five potential purchasers of oil in Kansas. If a key purchaser were to reduce the volume of oil it purchases from us, our revenue and cash available for operations will decline to the extent we are not able to find new customers to purchase our production at equivalent prices.
We currently sell oil to Sunoco, Inc. in Texas. There are numerous purchasers in Texas, but increased production volumes from extensive shale drilling activity in the area may result in reduced purchases by several of our purchasers.
We currently sell oil to Plains Marketing, LP in Colorado. There are a number of potential purchasers of our oil in Colorado but increased production volumes from the DJ basin may result in reduced purchases by our purchasers. If a key purchaser were to reduce the volume of oil it purchases from us, our revenue and cash available for operations will decline to the extent we are not able to find new customers to purchase our production at equivalent prices.
We sell natural gas to United Energy Trading and Western Operating Company in Colorado. There are other purchasers for our natural gas in Colorado. If a key purchaser were to reduce the volume of gas it purchases from us, our revenue and cash available for operations will decline to the extent we are not able to find new customers to purchase our production at equivalent prices.
We are not the operator of some of our properties and we have limited control over the activities on those properties.
We are not the operator of our Mississippian Project, and our dependence on the operator of this project limits our ability to influence or control the operation or future development of this project. Such limitations could materially adversely affect the realization of our targeted returns on capital related to exploration, drilling or production activities and lead to unexpected future costs.
We may suffer losses or incur liability for events for which we or the operator of a property have chosen not to obtain insurance.
Our operations are subject to hazards and risks inherent in producing and transporting oil and gas, such as fires, natural disasters, explosions, pipeline ruptures, spills, and acts of terrorism, all of which can result in the loss of hydrocarbons, environmental pollution, personal injury claims and other damage to our and others' properties. As protection against operating hazards, we maintain insurance coverage against some, but not all, potential losses. In addition, pollution and environmental risks generally are not fully insurable. As a result of market conditions, existing insurance policies may not be renewed and other desirable insurance may not be available on commercially reasonable terms, if at all. The occurrence of an event that is not covered, or not fully covered, by insurance could have a material adverse effect on our business, financial condition and results of operations.
Our hedging activities could result in financial losses or could reduce our available funds or income and therefore adversely affect our financial position.
To achieve more predictable cash flow and to reduce our exposure to adverse fluctuations in the prices of oil and gas, we have entered into derivative contracts through June 30, 2016 for approximately 175,000 barrels of crude oil. The settlement of and the mark to market of these contracts could result in both realized and unrealized hedging losses. For the year ended December 31, 2014, we incurred realized and unrealized gains of approximately $5,000,000. The extent of our commodity price exposure is related largely to the effectiveness and scope of our derivative activities. For example, the derivative instruments we may utilize may be based on posted market prices, which may differ significantly from the actual crude oil prices we realize in our operations.
Our actual future production may be significantly higher or lower than we estimate at the time we enter into derivative transactions for such period. If the actual amount is higher than we estimate, we will have greater commodity price exposure than we intended. If the actual amount is lower than the nominal amount that is subject to our derivative financial instruments, we might be forced to satisfy all or a portion of our derivative transactions without the benefit of the cash flow from our sale or purchase of the underlying physical commodity, resulting in a substantial diminution of our liquidity. As a result of these factors, our derivative activities may not be as effective as we intend in reducing the volatility of our cash flows, and in certain circumstances may actually increase the volatility of our cash flows. In addition, while we believe our existing derivative activities are with creditworthy counterparties, deterioration in the credit markets may cause a counterparty not to perform its obligation under the applicable derivative instrument or impact their willingness to enter into future transactions with us. If that occurred, then any hedging arrangement with such counterparty would not provide any effective hedge against changes in market conditions.
Our business depends in part on processing facilities owned by others. Any limitation in the availability of those facilities could interfere with our ability to market our oil and gas production and could harm our business.
The marketability of our oil and gas production will depend in part on the availability, proximity and capacity of pipelines and oil and gas processing facilities. The amount of oil and gas that can be produced and sold is subject to curtailment in certain circumstances, such as pipeline interruptions due to scheduled and unscheduled maintenance, excessive pressure, physical damage or lack of available capacity on such systems. The curtailments arising from these and similar circumstances may last from a few days to several months. In many cases, we will be provided only with limited, if any, notice as to when these circumstances will arise and their duration. Any significant curtailment in pipeline capacity or the capacity of processing facilities could significantly reduce our ability to market our oil and gas production and could materially harm our business.
Cost and availability of drilling rigs, equipment, supplies, personnel and other services could adversely affect our ability to execute on a timely basis our development, exploitation and exploration plans.
Shortages or an increase in cost of drilling rigs, equipment, supplies or personnel could delay or interrupt our operations, which could impact our financial condition and results of operations. Drilling activity in the geographic areas in which we conduct drilling activities may increase, which would lead to increases in associated costs, including those related to drilling rigs, equipment, supplies and personnel and the services and products of other vendors to the industry. Increased drilling activity in these areas may also decrease the availability of rigs. We do not have any contracts for drilling rigs and drilling rigs may not be readily available when we need them. Drilling and other costs may increase further and necessary equipment and services may not be available to us at economical prices.
Our exposure to possible leasehold defects and potential title failure could materially adversely impact our ability to conduct drilling operations.
We obtain the right and access to properties for drilling by obtaining oil and gas leases either directly from the hydrocarbon owner, or through a third party that owns the lease. The leases may be taken or assigned to us without title insurance. There is a risk of title failure with respect to such leases, and such title failures could materially adversely impact our business by causing us to be unable to access properties to conduct drilling operations.
Our reserves are subject to the risk of depletion because many of our leases are in mature fields that have produced large quantities of oil and gas to date.
A significant portion of our operations are located in or near established fields in Colorado, Nebraska, Kansas and Texas. As a result, many of our leases are in, or directly offset, areas that have produced large quantities of oil and gas to date. As such, our reserves may be negatively impacted by offsetting wells or previously drilled wells, which could significantly harm our business.
Our lease ownership may be diluted due to financing strategies we may employ in the future.
To accelerate our development efforts we may take on working interest partners who will contribute to the costs of drilling and completion operations and then share in any cash flow derived from production. In addition, we may in the future, due to a lack of capital or other strategic reasons, establish joint venture partnerships or farm out all or part of our development efforts. These economic strategies may have a dilutive effect on our lease ownership and could significantly reduce our operating revenues.
We may face lease expirations on leases that are not currently held-by-production.
We have numerous leases that are not currently held-by-production, some of which have near term lease expirations and are likely to expire. Although we believe that we can maintain our most desirable leases by conducting drilling operations or by negotiating lease extensions, we can make no guarantee that we can maintain these leases.
We are subject to complex laws and regulations, including environmental regulations, which can adversely affect the cost, manner or feasibility of doing business.
Development, production and sale of oil and gas in the United States are subject to extensive laws and regulations, including environmental laws and regulations. We may be required to make large expenditures to comply with environmental and other governmental regulations. Matters subject to regulation include, but are not limited to:
·location and density of wells;
·the handling of drilling fluids and obtaining discharge permits for drilling operations;
·accounting for and payment of royalties on production from state, federal and Indian lands;
·bonds for ownership, development and production of oil and gas properties;
·transportation of oil and gas by pipelines;
·operation of wells and reports concerning operations; and
·taxation.
Under these laws and regulations, we could be liable for personal injuries, property damage, oil and gas spills, discharge of hazardous materials, remediation and clean-up costs and other environmental damages. Failure to comply with these laws and regulations also may result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties. Moreover, these laws and regulations could change in ways that substantially increase our costs. Accordingly, any of these liabilities, penalties, suspensions, terminations or regulatory changes could materially adversely affect our financial condition and results of operations enough to possibly force us to cease our business operations.
Our operations may expose us to significant costs and liabilities with respect to environmental, operational safety and other matters.
We may incur significant costs and liabilities as a result of environmental and safety requirements applicable to our oil and gas production activities. We may also be exposed to the risk of costs associated with Kansas Corporation Commission, the Texas Railroad Commission and the State of Colorado Oil and Gas Conservation Commission requirements to plug orphaned and abandoned wells on our oil and gas leases from wells previously drilled by third parties. In addition, we may indemnify sellers or lessors of oil and gas properties for environmental liabilities they or their predecessors may have created. These costs and liabilities could arise under a wide range of federal, state and local environmental and safety laws and regulations, including regulations and enforcement policies, which have tended to become increasingly strict over time. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, imposition of cleanup and site restoration costs, liens and to a lesser extent, issuance of injunctions to limit or cease operations. In addition, claims for damages to persons or property may result from environmental and other impacts of our operations.
Strict, joint and several liability may be imposed under certain environmental laws, which could cause us to become liable for the conduct of others or for consequences of our own actions that were in compliance with all applicable laws at the time those actions were taken. New laws, regulations or enforcement policies could be more stringent and impose unforeseen liabilities or significantly increase compliance costs. If we are not able to recover the resulting costs through insurance or increased revenues, our ability to operate effectively could be adversely affected.
We operate in a highly competitive environment and our competitors may have greater resources than do we.
The oil and gas industry is intensely competitive and we compete with other companies, many of which are larger and have greater financial, technological, human and other resources. Many of these companies not only explore for and produce crude oil and gas but also carry on refining operations and market petroleum and other products on a regional, national or worldwide basis. Such companies may be able to pay more for productive oil and gas properties and exploratory prospects or define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. In addition, such companies may have a greater ability to continue exploration activities during periods of low oil and gas market prices. Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. If we are unable to compete, our operating results and financial position may be adversely affected.
We may incur substantial write-downs of the carrying value of our oil and gas properties, which would adversely impact our earnings.
We review the carrying value of our oil and gas properties under the full cost method of accounting. Under the full cost method of accounting, the net book value of oil and gas properties, less deferred income taxes, may not exceed a calculated “ceiling.” The ceiling limitation is (a) the present value of future net revenues computed by applying current prices of oil & gas reserves (with consideration of price changes only to the extent provided by contractual arrangements) to estimated future production of proved oil & gas reserves as of the date of the latest balance sheet presented, less estimated future expenditures (based on current costs) to be incurred in developing and producing the proved reserves computed using a discount factor of 10 percent and assuming continuation of existing economic conditions plus (b) the cost of properties not being amortized plus (c) the lower of cost or estimated fair value of unproven properties included in the costs being amortized less (d) income tax effects related to differences between book and tax basis of properties. Future cash outflows associated with settling accrued retirement obligations are excluded from the calculation. Estimated future cash flows are calculated using end-of-period costs and an un-weighted arithmetic average of commodity prices in effect on the first day of each of the previous 12 months held flat for the life of the production, except where prices are defined by contractual arrangements.
Revisions to estimates of oil and gas reserves and/or an increase or decrease in current prices can have a material impact on the present value of estimated future net revenues. Any excess of the net book value of proved oil and gas properties, less related deferred income taxes, over the ceiling is charged to expense and reflected as additional depreciation, depletion, and amortization in the statement of operations.
During the years ended December 31, 2014 and 2013 there were no impairments resulting from the quarterly ceiling tests.
Risks Associated with our Debt Financing
Significant and prolonged declines in commodity prices may negatively impact our borrowing base and our ability to borrow overall.
Our borrowing base, which is based on our oil and gas reserves and is subject to review and adjustment on a semi-annual basis and other interim adjustments, may be reduced when it is reviewed. A reduction in our base results in a "loan excess" which is required to be eliminated through payment of a portion of the loan and/or cash collateralization of Letters of Credit obligations; or adding properties to the borrowing base sufficient to offset the "loan excess". A reduction in our borrowing base or the ability to borrow under our Credit Facility, combined with a reduction in cash flow from operations resulting from a decline in oil and gas prices, would likely require us to further reduce our capital expenditures and our operating activities.
Until we repay the full amount of our outstanding Credit Facility, we may continue to have substantial indebtedness, which is secured by substantially all of our assets.
On December 31, 2014, we had $23,000,000 of bank loans outstanding. If we defaulted on our obligations with respect to the secured debt, the lenders may enforce their rights as secured parties and we may lose all or a portion of our assets or be forced to materially reduce our business activities.
Our substantial indebtedness could make it more difficult for us to fulfill our obligations under our Credit Facility and, therefore, adversely affect our business.
On August 15, 2014, the Company entered into an Eighth Amendment to the Amended and Restated Credit Agreement. The Eighth Amendment reflects the following changes: (i) increased the Borrowing Base from $38,000,000 to $40,000,000; (ii) extended the maturity of the facility by three years to October 3, 2018.
As of December 31, 2014, we had total indebtedness of $23,000,000 under the Credit Facility. Our substantial indebtedness, and the related interest expense, could have important consequences to us, including:
·our ability to borrow additional amounts for working capital, capital expenditures, debt service requirements, execution of our business strategy, or other general corporate purposes;
·being forced to use cash flow to reduce our outstanding balance as a result of an unfavorable borrowing base redetermination;
·our ability to use operating cash flow in other areas of our business because we must dedicate a substantial portion of these funds to service our indebtedness;
·increasing our vulnerability to general adverse economic and industry conditions;
·placing us at a competitive disadvantage as compared to our competitors that have less leverage;
·our ability to capitalize on business opportunities and to react to competitive pressures and changes in government regulation;
·our ability to, or increasing the cost of, refinancing our indebtedness; and
·our ability to enter into marketing, hedging, optimization and trading transactions by reducing the number of counterparties with whom we can enter into such transactions as well as the volume of those transactions.
The covenants in our Credit Facility impose significant operating and financial restrictions on us.
The Credit Facility imposes significant operating and financial restrictions on us. These restrictions limit our ability and the ability of our subsidiaries, among other things, to:
·incur additional indebtedness and provide additional guarantees;
·pay dividends and make other restricted payments;
·create or permit certain liens;
·use the proceeds from the sales of our oil and gas properties;
·use the proceeds from the unwinding of certain financial hedges;
·engage in certain transactions with affiliates; and
·consolidate, merge, sell or transfer all or substantially all of our assets or the assets of our subsidiaries.
The Credit Facility also contains various affirmative covenants with which we are required to comply. We were in compliance with these covenants as of December 31, 2014. We may be unable to comply with some or all of these covenants in the future. If we do not comply with these covenants and are unable to obtain waivers from our lenders, we would be unable to make additional borrowings under these facilities; our indebtedness under these agreements would be in default and repayment of debt could be accelerated by our lenders. If our indebtedness is accelerated, we may not be able to repay our indebtedness or borrow sufficient funds to refinance it. In addition, if we incur additional indebtedness in the future, we may be subject to additional covenants, which may be more restrictive than those to which we are currently subject.
Risks Associated with our Common Stock
We do not expect to pay dividends to holders of our common stock because of the terms of our debt facility, and our need to reinvest cash flow from operations in our business.
It is unlikely that we will pay any dividends to the holders of our common stock in the foreseeable future. The terms of our debt facility require that the lender approve any such distributions, and the lender is unlikely to provide that consent so long as we have significant unpaid indebtedness outstanding.
Ownership of our common stock is highly concentrated, and such concentration may prevent other stockholders from influencing significant corporate decisions and may result in conflicts of interest that could cause our stock price to decline.
Our directors, officers and principal stockholders (stockholders owning 10% or more of our common stock) and their affiliates beneficially owned approximately 4,348,381 shares or 58.5% of the outstanding shares of common stock, stock options, and derivatives that could have been converted to common stock at December 31, 2014, and 53.2% of the outstanding shares of common stock, options and derivatives that could have been converted to common stock as of the filing of this Annual Report on Form 10-K. Such stockholders will have significant influence over the outcome of all matters submitted to our stockholders for approval, including the election of directors and other corporate actions.
Two of our Directors, Ryan A. Lowe and Lance Helfert, serve on the investment committee of West Coast Asset Management, Inc. West Coast Asset Management is the managing member of West Coast Opportunity Fund, LLC, a private investment vehicle formed for the purpose of investing in a wide variety of securities and financial instruments. West Coast Asset Management's principals also manage Montecito Venture Partners, LLC. West Coast Opportunity Fund and Montecito Venture Partners, LLC together beneficially owned 51% of our common stock and 15% of our Series A preferred stock at December 31, 2014. Currently they own 46.4% of our common stock and 15% of our Series A preferred stock.
In addition, we engage from time to time in transactions with certain of these significant stockholders.
As discussed more fully in Note 5 to the financial statements, on September 27, 2013, West Coast Opportunity Fund, LLC exchanged 123,539,227 Black Raven Energy, Inc. common shares for 41,327,516 common shares of our common stock.
As stated above, West Coast Opportunity Fund and Montecito Venture Partners, affiliates of our directors Mr. Lowe and Mr. Helfert, beneficially own, as of December 31, 2014, 51% of our common stock and 7.6% of our Series A preferred stock.
The interests of West Coast Opportunity Fund and Montecito Venture Partners, and their affiliates, may differ from those of our other stockholders. West Coast Opportunity Fund and Montecito Venture Partners, and their affiliates are in the business of making investments in companies and maximizing the return on those investments. They currently have, and may from time to time in the future acquire, interests in businesses that directly or indirectly compete with certain aspects of our business or our suppliers' or customers' businesses.
As of December 31, 2014, West Coast Opportunity Fund and Montecito Venture Partners were parties to an irrevocable voting and proxy agreement, by which Montecito Venture Partners granted to West Coast Opportunity Fund a proxy to vote Montecito Venture Partners shares with regard to the election of our board of directors. That irrevocable voting and proxy agreement gave West Coast Opportunity Fund the power to elect a majority of the members of our board of directors. These stockholders also may exert influence in delaying or preventing a change in control of the Company, even if such change in control would benefit the other stockholders of the Company. In addition, the significant concentration of stock ownership may affect adversely the market value of EnerJex's common stock and Series A preferred stock due to investors' perception that conflicts of interest may exist or arise. On March 23, 2015, the irrevocable voting and proxy agreement was terminated pursuant to written agreement.
We have derivative securities currently outstanding and we may issue derivative securities in the future. Exercise of the derivatives will cause dilution to existing and new stockholders.
The exercise of our outstanding options and warrants, will cause additional shares of common stock to be issued, resulting in dilution to our existing and future common stockholders
We have the ability to issue additional shares of our common stock and preferred stock without asking for stockholder approval, which could cause your investment to be diluted.
Our amended and restated articles of incorporation authorize the board of directors to issue up to 250,000,000 shares of common stock and 25,000,000 shares of preferred stock. The power of the board of directors to issue shares of common stock, preferred stock or warrants or options to purchase shares of common stock or preferred stock is generally not subject to shareholder approval. Accordingly, any additional issuance of our common stock, or preferred stock that may be convertible into common stock, or debt instruments that may be convertible into common or preferred stock, may have the effect of diluting one's investment.
Although our common stock and Series A preferred stock are traded on the NYSE MKT, daily trading volumes are small making it difficult for investors to sell their shares.
Our common stock and our Series A preferred stock trade on the NYSE MKT under the symbol "ENRJ," and “ENRJ.P,” respectively but trading volume has been minimal. Therefore, the market for our common stock is limited. The trading price of our stock could be subject to wide fluctuations. Investors may not be able to purchase additional shares or sell their shares within the time frame or at a price they desire.
The price of our common stock and Series A preferred stock may be volatile and you may not be able to resell your shares at a favorable price.
Regardless of whether an active trading market for our stock develops, the market price of our stock may be volatile and you may not be able to resell your shares at or above the price you paid for such shares. Many factors beyond our control, including but not limited to the following factors could affect our stock price:
· our operating and financial performance and prospects;
· quarterly variations in the rate of growth of our financial indicators, such as net income or loss per share, net income or loss and revenues;
· changes in revenue or earnings estimates or publication of research reports by analysts about us or the exploration and production industry;
· potentially limited liquidity;
· actual or anticipated variations in our reserve estimates and quarterly operating results;
· changes in oil and gas prices;
· sales of our common stock by significant stockholders and future issuances of our common stock;
· increases in our cost of capital;
· changes in applicable laws or regulations, court rulings and enforcement and legal actions;
· commencement of or involvement in litigation;
· changes in market valuations of similar companies;
· additions or departures of key management personnel;
· general market conditions, including fluctuations in and the occurrence of events or trends affecting the price of oil and gas; and
· domestic and international economic, legal and regulatory factors unrelated to our performance.
Our amended and restated articles of incorporation, restated bylaws and Nevada Law contain provisions that could discourage an acquisition or change of control of us.
Our amended and restated articles of incorporation authorize our board of directors to issue preferred stock and common stock without stockholder approval. The election by our board of directors to issue Series A preferred stock, and any future election to issue more preferred stock, could make it more difficult for a third party to acquire control of us. In addition, provisions of the articles of incorporation and bylaws could also make it more difficult for a third party to acquire control of us. In addition, Nevada's "Combination with Interested Stockholders' Statute" and its "Control Share Acquisition Statute" may have the effect in the future of delaying or making it more difficult to effect a change in control of us.
These statutory anti-takeover measures may have certain negative consequences, including an effect on the ability of our stockholders or other individuals to (i) change the composition of the incumbent board of directors; (ii) benefit from certain transactions which are opposed by the incumbent board of directors; and (iii) make a tender offer or attempt to gain control of us, even if such attempt were beneficial to us and our stockholders. Since such measures may also discourage the accumulations of large blocks of our common stock by purchasers whose objective is to seek control of us or have such common stock repurchased by us or other persons at a premium, these measures could also depress the market price of our common stock. Accordingly, our stockholders may be deprived of certain opportunities to realize the "control premium" associated with take-over attempts.
We have no plans to pay dividends on our common stock. You may not receive funds without selling your stock.
We do not anticipate paying any cash dividends on our common stock in the foreseeable future. We currently intend to retain future earnings, if any, to finance the expansion of our business. Our future dividend policy with regard to our common stock is within the discretion of our board of directors and will depend upon various factors, including our business, financial condition, results of operations, capital requirements, investment opportunities and restrictions imposed by our debentures and Credit Facility.
Additional Risks and Uncertainties
We are an oil and gas acquisition, exploration and development company. If any of the risks that we face actually occur, irrespective of whether those risks are described in this section or elsewhere in this report, our business, financial condition and operating results could be materially adversely affected.
ITEM 1B.
ITEM 1B. UNRESOLVED STAFF COMMENTS.
Not applicable.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS.
None
ITEM 4.
ITEM 4. MINE SAFETY DISCLOSURE
None
PART II
ITEM 5.
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES.
Market Information for Common Stock
Our common stock trades on the NYSE MKT under the symbol "ENRJ." The following table lists the quotations for the high and low sales prices of our common stock for the years ended December 31, 2013 and December 31, 2014. The market price of our common stock has been volatile. For an additional discussion, see "Item 1A: Risk Factors" of this Annual Report on Form 10-K.
Holders
As of March 31, 2015, there were 362 holders of record of our common stock, and 16 holders of record of our Series A preferred stock.
Dividends
We have never paid or declared any cash dividends on our common stock. We pay a monthly dividend of $.20833 per share or $2.50 annual dividend per share on the Company’s non-convertible 10.0% Series A Cumulative Redeemable Perpetual Preferred Stock. We currently intend to retain any future earnings in excess of debt repayments and Series A preferred stock dividends to finance the growth and development of our business and we do not expect to pay any cash dividends on our common stock in the foreseeable future. In addition, we are contractually prohibited by the terms of our outstanding debt from paying cash dividends on our common stock. Payment of future dividends on common stock, if any, will be at the discretion of our Board of Directors and will depend on our financial condition, results of operations, capital requirements, restrictions contained in current or future financing instruments, including the consent of debt holders and holders of Series A Shares, if applicable at such time, and other factors our Board of Directors deems relevant.
Securities Authorized for Issuance under Equity Compensation Plans
The following table sets forth information as of fiscal year ended December 31, 2014, regarding outstanding options granted under our stock option plans and options reserved for future grant under the plans.
Recent Sales of Unregistered Securities
None.
Issuer Purchases of Equity Securities
None.
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA.
Not applicable.
ITEM 7.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
This Management's Discussion and Analysis of Financial Condition and Results of Operations section should read in conjunction with the other sections of this Annual Report on Form 10-K, including "Items 1 and 2. Business and Properties" and "Item 8: Financial Statements and Supplementary Data". This section includes forward-looking statements within the meaning of Section 27A of the Securities Act, and Section 21E of the Exchange Act. Forward-looking statements such as "will", "believe," "are projected to be" and similar expressions are statements regarding future events or our future performance, and include statements regarding projected operating results. These forward-looking statements are based on current expectations, beliefs, intentions, strategies, forecasts and assumptions and involve a number of risks and uncertainties that could cause actual results to differ materially from those anticipated by these forward-looking statements. These risks include, but are not limited to: our ability to deploy capital in a manner that maximizes stockholder value; the ability to identify suitable acquisition candidates or business and investments opportunities; the ability to reduce our operating costs; general economic conditions and our expected liquidity in future periods. These forward-looking statements are based on our current expectations and could be affected by the uncertainties and risk factors described throughout this filing and particularly in the "Risk Factors" set forth in Part I, Item 1A of this Annual Report on Form 10-K. As a result, our actual results may differ materially from those anticipated in these forward-looking statements.
Overview
Our principal strategy is to develop, acquire, explore and produce domestic onshore oil and gas properties. Our business activities are currently focused in Kansas, Colorado, Nebraska, and Texas.
Results of Operations
The following table presents selected information regarding our operating results from continuing operations. For the year ended December 31, 2013, only the results of operations for the fourth quarter for Black Raven are included due to the merger with Black Raven Energy, Inc. on September 27, 2013 (see Note 5).
(1) 2014 crude oil revenues increased $2.4 million or 22% to 13.3 million from $10.8 million in fiscal 2013. The crude oil revenue increase was due primarily to increased sales. Sales increased by approximately 43,000 bbls or 38% to 157,089 bbls in 2014 compared to sales of 114,112 in 2013. This increase was due primarily to new production from our Colorado assets that resulted from our acquisition of Black Raven Energy, Inc. on September 27, 2013, as more fully described in Note 5. Revenue increases due to increased sales volumes was partially offset by decreases to our realized prices. Realized prices dropped $10.46 during 2014 from $94.86 per bbl in 2013 to $84.40 per bbl in 2014. 2014 natural gas revenues increased $0.9 million to $1.0 million from $0.1 million in 2013. This increase was due to increased sales of natural gas. Sales of natural gas increased by approximately 290,000 mcf in 2014 from 39,135 mcf in 2013 to 325,894 mcf in 2014. Again, this increase was due new production from our Colorado assets that resulted from our acquisition of Black Raven Energy, Inc. on September 27, 2013 (see note 5 to our financial statements).
(2) 2014 lease operating expenses increased $2.7 million or 65% to $6.8 million from $4.1 million in 2013. However, lease operating expenses per boe decreased $1.96 per boe or 5.8% to $31.99 in 2014 from $33.95 per boe in 2013. The 65% increase in lease operating expenses in 2014 was due primarily to increased operating expenses associated with the new Colorado production that resulted from our acquisition of Black Raven Energy, Inc. on September 27, 2013 (see note 5 to financial statements).
(3) 2014 depletion expense increased approximately 93% to approximately $3.3 million compared to $1.7 million for 2013. The depletion expense increase is due primarily to increased production levels as note in (2) above. Depletion expense per boe increased $1.40 or 10% in 2014 compared to 2013.
(4) 2014 professional fees were $1.0 million, compared to $1.1 million during 2013. Professional fees decreased as a result of reduced legal fees partially offset by increased consulting and investor relation fees.
Reserves
Of the 4.4 million BOE of total proved reserves, approximately 50% are classified as proved developed producing, approximately 19% are classified as proved developed non-producing, and approximately 31% are classified as proved undeveloped.
The following table presents summary information regarding our estimated net proved reserves as of December 31, 2014. All calculations of estimated net proved reserves have been made in accordance with the rules and regulations of the SEC, and, except as otherwise indicated, give no effect to federal or state income taxes. The estimates of net proved reserves are based on the reserve reports prepared by MHA Petroleum Consultants LLC, our independent petroleum consultants. For additional information regarding our reserves, please see Note 15 to our audited financial statements as of and for the fiscal year ended December 31, 2014.
Summary of Proved Oil and Gas Reserves
as of December 31, 2014
(1) The following table shows our reconciliation of our PV10 to our standardized measure of discounted future net cash flows (the most direct comparable measure calculated and presented in accordance with GAAP). PV10 is our estimate of the present value of future net revenues from estimated proved oil and gas reserves after deducting estimated production and ad valorem taxes, future capital costs and operating expenses, but before deducting any estimates of future income taxes. The estimated future net revenues are discounted at an annual rate of 10% to determine their "present value." We believe PV10 to be an important measure for evaluating the relative significance of our oil and gas properties and that the presentation of the non-GAAP financial measure of PV10 provides useful information to investors because it is widely used by professional analysts and sophisticated investors in evaluating oil and gas companies. Because there are many unique factors that can impact an individual company when estimating the amount of future income taxes to be paid, we believe the use of a pre-tax measure is valuable for evaluating our company. We believe that most other companies in the oil and gas industry calculate PV10 on the same basis. PV10 should not be considered as an alternative to the standardized measure of discounted future net cash flows as computed under GAAP.
Liquidity and Capital Resources
Liquidity is a measure of a company's ability to meet potential cash requirements. We have historically met our capital requirements through debt financing, revenues from operations and the issuance of equity securities. We believe that our historical means of meeting our capital requirements will provide us with adequate liquidity to fund our operations.
The following table summarizes total current assets, total current liabilities and working capital at year ended December 31, 2014 compared to the year ended December 31, 2013.
Senior Secured Credit Facility
On October 3, 2011, the Company, DD Energy, Inc., EnerJex Kansas, Inc., Black Sable Energy, LLC and Working Interest, LLC ("Borrowers") entered into an Amended and Restated Credit Agreement with Texas Capital Bank, N.A. (“Bank”) and other financial institutions and banks that may become a party to the Credit Agreement from time to time. The facilities provided under the Amended and Restated Credit Agreement were to be used to refinance Borrowers prior outstanding revolving loan facility with Bank, dated July 3, 2008, and for working capital and general corporate purposes.
At our option, loans under the facility will bear stated interest based on the Base Rate plus Base Rate Margin, or Floating Rate plus Floating Rate Margin (as those terms are defined in the Credit Agreement). The Base Rate will be, for any day, a fluctuating rate per annum equal to the higher of (a) the Federal Funds Rate plus 0.50% and (b) the Bank's prime rate. The Floating Rate shall mean, at Borrower's option, a per annum interest rate equal to (i) the Eurodollar Rate plus Eurodollar Margin, or (ii) the Base Rate plus Base Rate Margin (as those terms are defined in the Amended and Restated Credit Agreement). Eurodollar borrowings may be for one, two, three, or six months, as selected by the Borrowers. The margins for all loans are based on a pricing grid ranging from 0.00% to 0.75% for the Base Rate Margin and 2.25% to 3.00% for the Floating Rate Margin based on the Company's Borrowing Base Utilization Percentage (as defined in the Amended and Restated Credit Agreement).
On December 15, 2011, we entered into a First Amendment to Amended and Restated Credit Agreement and Second Amended and Restated Promissory Note in the amount of $50,000,000 with the Bank. The Amendment reflects the addition of Rantoul Partners, as an additional Borrower and adds as additional security for the loans the assets held by Rantoul Partners.
On August 31, 2012, we entered into a Second Amendment to Amended and Restated Credit Agreement with the Bank. The Second Amendment: (i) increased the borrowing base to $7,000,000 (ii) reduced the minimum interest rate to 3.75% and (iii) added additional new leases as collateral for the loan.
On November 2, 2012, we entered into a Third Amendment to Amended and Restated Credit Agreement with the Bank. The Third Amendment (i) increased the borrowing base to $12,150,000 and (ii) clarified certain continuing covenants and provided a limited waiver of compliance with one of the covenants so clarified for the fiscal quarter ended December 31, 2011.
On January 24, 2013, we entered into a Fourth Amendment to Amended and Restated Credit Agreement, which was made effective as of December 31, 2012 with the Bank. The Fourth Amendment reflects the following changes: (i) the Bank consented to the restructuring transactions related to the dissolution of Rantoul Partners, and (ii) the Bank terminated a Limited Guaranty, as defined in the Credit Agreement, executed by Rantoul Partners in favor of the Bank
On April 16, 2013, the Bank increased our borrowing base to $19.5 million.
On September 30, 2013, we entered into a Fifth Amendment to the Amended and Restated Credit Agreement. The Fifth Amendment reflects the following changes: (i) expanded principal commitment amount of the Bank to $100,000,000; (ii) increased the Borrowing Base to $38,000,000; (iii) added Black Raven Energy, Inc. to the Credit Agreement as borrower parties; (iv) added certain collateral and security interests in favor of the Bank; and (v) reduced the Company’s current interest rate to 3.30%.
On November 19, 2013, we entered into a Sixth Amendment to the Amended and Restated Credit Agreement. The Sixth Amendment reflects the following changes: (i) the addition of Iberia Bank as a participant in our credit facility, and (ii) a technical correction to our covenant calculations.
On May 22, 2014, we entered into a Seventh Amendment to the Amended and Restated Credit Agreement. The Seventh Amendment reflects the Bank’s consent to our issuance of up to 850,000 shares of our 10% Series A Cumulative Redeemable Perpetual Preferred Stock.
On August 15, 2014, we entered into an Eighth Amendment to the Amended and Restated Credit Agreement. The Eighth Amendment reflects the following changes: (i) the borrowing base was increased from $38 million to $40 million, and (ii) the maturity of the facility was extended by three years to October 3, 2018.
Summary of product research and development that we will perform for the term of our plan
We do not anticipate performing any significant product research and development under our plan of operation.
Expected purchase or sale of any significant equipment
We anticipate that we will purchase the necessary production and field service equipment required to produce oil and gas during our normal course of operations over the next 12 months.
Significant changes in the number of employees
We currently have 29 full-time employees including field personnel. As production and drilling activities increase or decrease, we will adjust our technical, operational and administrative personnel as appropriate. We use and will continue to use independent consultants and contractors to perform various professional services, particularly in the area of land services, reservoir engineering, geology, drilling, water hauling, pipeline construction, well design, well-site monitoring and surveillance, permitting and environmental assessment. We believe that this use of third-party service providers may enhance our ability to contain operating and general expenses, and capital costs.
Off-Balance Sheet Arrangements
We do not have any off-balance sheet arrangements that have or are reasonably likely to have a current or future effect on our financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that is material to investors.
Critical Accounting Policies and Estimates
Our accounting policies and estimates that are critical to our business operations and understanding of our results of operations include those relating to our oil and gas properties, asset retirement obligations and the value of share-based payments. This is not a comprehensive list of all of the accounting policies. In many cases, the accounting treatment of a particular transaction is specifically dictated by U.S. GAAP, with no need for our judgment in the application. There are also areas in which our judgment in selecting any available alternative would not produce a materially different result. However, certain of our accounting policies are particularly important to the portrayal of our financial position and results of operations and we may use significant judgment in the application; as a result, they are subject to an inherent degree of uncertainty. In applying those policies, we use our judgment to determine the appropriate assumptions to be used in the determination of certain estimates. Those estimates are based on historical experience, observation of trends in the industry, and information available from other outside sources, as appropriate. For a more detailed discussion on the application of these and other accounting policies, see Note 1, Summary of Significant Accounting Policies, to our consolidated financial statements included in this report.
Oil and Gas Properties
We follow the full-cost method of accounting under which all costs associated with property acquisition, exploration and development activities are capitalized. We also capitalize internal costs that can be directly identified with our acquisition, exploration and development activities and do not include costs related to production, general corporate overhead or similar activities.
Proved properties are amortized using the units of production method (UOP). Currently we only have operations in the Unites States of America. The UOP calculation multiplies the percentage of estimated proved reserves produced each quarter by the cost of these reserves. The amortization base in the UOP calculation includes the sum of proved property, net of accumulated depreciation, depletion and amortization (DD&A), estimated future development costs (future costs to access and develop proved reserves) and asset retirement costs, less related salvage value.
The cost of unproved properties are excluded from the amortization calculation until it is determined whether or not proved reserves can be assigned to such properties or until development projects are placed into service. Geological and geophysical costs not associated with specific properties are recorded as proved property immediately. Unproved properties are reviewed for impairment quarterly.
Under the full cost method of accounting, the net book value of oil and gas properties, less deferred income taxes, may not exceed a calculated “ceiling.” The ceiling limitation is (a) the present value of future net revenues computed by applying current prices of oil & gas reserves (with consideration of price changes only to the extent provided by contractual arrangements) to estimated future production of proved oil & gas reserves as of the date of the latest balance sheet presented, less estimated future expenditures (based on current costs) to be incurred in developing and producing the proved reserves computed using a discount factor of 10 percent and assuming continuation of existing economic conditions plus (b) the cost of properties not being amortized plus (c) the lower of cost or estimated fair value of unproven properties included in the costs being amortized less (d) income tax effects related to differences between book and tax basis of properties. Future cash outflows associated with settling accrued retirement obligations are excluded from the calculation. Estimated future cash flows are calculated using end-of-period costs and an unweighted arithmetic average of commodity prices in effect on the first day of each of the previous 12 months held flat for the life of the production, except where prices are defined by contractual arrangements.
Any excess of the net book value of proved oil and gas properties, less related deferred income taxes, over the ceiling is charged to expense and reflected as additional DD&A in the statement of operations. The ceiling calculation is performed quarterly. During the years ended December 31, 2013 and 2012 there were no impairments resulting from the quarterly ceiling tests.
Proceeds from the sale or disposition of oil and gas properties are accounted for as a reduction to capitalized costs unless a significant portion (greater than 25%) of our reserve quantities are sold, in which case a gain or loss is recognized in income.
Asset Retirement Obligations
The asset retirement obligation relates to the plug and abandonment costs when our wells are no longer useful. We determine the value of the liability by obtaining quotes for this service and estimate the increase we will face in the future. We then discount the future value based on an intrinsic interest rate that is appropriate for us. If costs rise more than what we have expected there could be additional charges in the future however we monitor the costs of the abandoned wells and we will adjust this liability if necessary.
Share-Based Payments
The value we assign to the options and warrants that we issue is based on the fair market value as calculated by the Black-Scholes pricing model. To perform a calculation of the value of our options and warrants, we determine an estimate of the volatility of our stock. We need to estimate volatility because there has not been enough trading of our stock to determine an appropriate measure of volatility. We believe our estimate of volatility is reasonable, and we review the assumptions used to determine this whenever we issue a new equity instruments. If we have a material error in our estimate of the volatility of our stock, our expenses could be understated or overstated.
Recent Issued Accounting Standards
See Note 1, Summary of Significant Accounting Policies - Recent Issued Accounting Standards, to our consolidated financial statements included in this report.
Effects of Inflation and Pricing
The oil and gas industry is very cyclical and the demand for goods and services of oil and gas field companies, suppliers and others associated with the industry puts extreme pressure on the economic stability and pricing structure within the industry. Material changes in prices impact revenue stream, estimates of future reserves, borrowing base calculations of bank loans and value of properties in purchase and sale transactions. Material changes in prices can impact the value of oil and gas companies and their ability to raise capital, borrow money and retain personnel. We anticipate business costs and the demand for services related to production and exploration will fluctuate while the commodity price for oil and gas remains volatile.
ITEM 7A.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.
Not applicable.
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
Management Responsibility for Financial Information
We are responsible for the preparation, integrity and fair presentation of our financial statements and the other information that appears in this Annual Report on Form 10-K. The financial statements have been prepared in accordance with accounting principles generally accepted in the United States and include estimates based on our best judgment.
We maintain a comprehensive system of internal controls and procedures designed to provide reasonable assurance, at an appropriate cost-benefit relationship, that our financial information is accurate and reliable, our assets are safeguarded and our transactions are executed in accordance with established procedures.
RBSM LLP, an independent registered public accounting firm, is retained to audit our consolidated financial statements. Its accompanying report is based on audits conducted in accordance with the standards of the Public Company Accounting Oversight Board (United States).
Our consolidated financial statements and notes thereto, and other information required by this Item 8 are included in this report beginning on page.
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE.
None.
ITEM 9A.
ITEM 9A. CONTROLS AND PROCEDURES.
Evaluation of Disclosure Controls and Procedures
Our Chief Executive Officer, Robert G. Watson, Jr., and our Chief Financial Officer, Douglas M. Wright, evaluated the effectiveness of our disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934, as amended) as of the end of the period covered by this Report pursuant to Exchange Act Rule 13a-15(b). Based on the evaluation, Mr. Watson and Mr. Wright concluded that our disclosure controls and procedures are effective.
Management's Report on Internal Control over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as is defined in the Securities Exchange Act of 1934. These internal controls are designed to provide reasonable assurance that the reported financial information is presented fairly, that disclosures are adequate and that the judgments inherent in the preparation of financial statements are reasonable. There are inherent limitations in the effectiveness of any system of internal control, including the possibility of human error and overriding of controls. Consequently, an effective internal control system can only provide reasonable, not absolute, assurance, with respect to reporting financial information.
Management conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework and criteria established in Internal Control - Integrated Framework, issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, management concluded that our internal control over financial reporting was effective as of December 31, 2013.
Changes in Internal Control over Financial Reporting
There were no changes in our internal control over financial reporting that occurred during our most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
ITEM 9B.
ITEM 9B. OTHER INFORMATION.
None.
PART III
ITEM 10.
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE.
Information in response to this item is incorporated by reference from the registrant's definitive proxy statement for its 2015 Annual Meeting of Shareholders to be filed within 120 days after December 31, 2014.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION.
Information in response to this item is incorporated by reference from the registrant's definitive proxy statement for its 2015 Annual Meeting of Shareholders to be filed within 120 days after December 31, 2014.
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS.
Information in response to this item is incorporated by reference from the registrant’s definitive proxy statement for its 2015 Annual Meeting of Shareholders to be filed within 120 days after December 31, 2014.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE.
Information in response to this item is incorporated by reference from the registrant's definitive proxy statement for its 2015 Annual Meeting of Shareholders to be filed within 120 days after December 31, 2014.
ITEM 14.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES.
Information in response to this item is incorporated by reference from the registrant's definitive proxy statement for its 2015 Annual Meeting of Shareholders to be filed within 120 days after December 31, 2014.
PART IV
ITEM 15.
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES.
The following information required under this item is filed as part of this report:
1. Financial Statements
2. Financial Statement Schedules
None.
3. Exhibit Index
Exhibit
No.
Description
2.1
Agreement and Plan of Merger between Millennium Plastics Corporation and Midwest Energy, Inc. filed on August 16, 2006.
2.2
Agreement and Plan of Merger by and among Registrant, BRE Merger Sub, Inc., Black Raven Energy, Inc. and West Coast Opportunity Fund, LLC dated July 23, 2013 (incorporated herein by reference to Exhibit 10.4 on Form 8-K filed July 29, 2013).
3.1
Amended and Restated Articles of Incorporation, as currently in effect (incorporated by reference to Exhibit 3.1 to the Form 10-Q filed on August 14, 2008)
3.2
Amended and Restated Bylaws, as currently in effect (incorporated by reference to Appendix C to Schedule 14A filed on June 6, 2013)
3.3
Certificate of Amendment of Articles of Incorporation as filed with the Nevada Secretary of State on May 29, 2014 (incorporated herein by reference as Exhibit 3.1 on Current Report Form 8-K filed on May 29, 2014)
3.4
Certificate of Amendment of Articles of Incorporation (incorporated by reference as Exhibit 3.1 on Current Report Form 8-K filed on May 29, 2014)
3.5
Amended and Restated Certificate of Designation for Series A Preferred Stock (incorporated by reference to Exhibit 4.6 to the Form S-1/A filed on June 3, 2014)
3.6
Certificate of Designation of Preferences, Rights and Limitations of Series B Convertible Preferred Stock (incorporated herein by reference as Exhibit 4.1 on Current Report Form 8-K filed on March 11, 2015)
4.1
Specimen common stock certificate (incorporated by reference to Exhibit 4.3 to the Form S-1/A filed on May 27, 2008)
4.2
Specimen Series A Preferred Stock Certificate (incorporated by reference to Exhibit 4.4 to the Form S-1/A filed on June 3, 2014)
4.3
Specimen Series B Convertible Preferred Stock Certificate (incorporated herein by reference as Exhibit 4.2 on Current Report Form 8-K filed on March 11, 2015)
4.4
Certificate of Designation for Series A Preferred Stock (incorporated by reference to Exhibit 4.1 to the Form 8-K filed on January 6, 2011).
4.5
Form of Warrant to Purchase Common Stock (incorporated herein by reference as Exhibit 4.3 on Current Report Form 8-K filed on March 11, 2015)
4.6
Form of Placement Agent Warrant (incorporated herein by reference as Exhibit 4.4 on Current Report Form 8-K filed on March 11, 2015)
10.1
Form of Officer and Director Indemnification Agreement (incorporated by reference to Exhibit 10.2 to the Form 8-K filed on October 16, 2008)
10.2
Amendment 4 to Joint Exploration Agreement effective as of November 6, 2008 between MorMeg, LLC and EnerJex Resources, Inc. (incorporated by reference to Exhibit 10.15 to the Form 10-K filed July 14, 2009)
10.3
Amendment 5 to Joint Exploration Agreement effective as of December 31, 2009 between MorMeg LLC and EnerJex Resources, Inc. (incorporated by reference to Exhibit 10.15 to the Form 10-Q filed on February 16, 2010)
10.4
Amendment 6 to Joint Exploration Agreement effective as of March 31, 2010 between MorMeg LLC and EnerJex Resources, Inc. (incorporated by reference to Exhibit 10.24 to the Form 10-K filed on July 15, 2010)
10.5
Amended and Restated EnerJex Resources, Inc. Stock Incentive Plan (incorporated by reference to Exhibit 10.1 to the Form 8-K filed on October 16, 2008)
10.6
Joint Development Agreement between EnerJex Resources, Inc. and Haas Petroleum, LLC dated December 31, 2010 (incorporated by reference to Exhibit 10.1 to the Form 8-K filed on January 27, 2011).
10.7
Joint Operating Agreement between EnerJex Resources, Inc. and Haas Petroleum, LLC and MorMeg, LLC dated December 31, 2010 (incorporated by reference to Exhibit 10.2 to the Form 8-K filed on January 27, 2011).
10.8
Amended and Restated Credit Agreement dated October 3, 2011 (incorporated herein by reference to Exhibit 10.1 on Form 8-K filed on October 6, 2011).
10.9
Option and Joint Development Agreement by and among Registrant and MorMeg, LLC dated August 2011 (incorporated herein by reference to Exhibit 10.1 on Form 8-K filed on November 15, 2011).
10.10
First Amendment to Amended and Restated Credit Agreement dated December 14, 2011 (incorporated herein by reference to Exhibit 10.2 on Form 8-K filed on December 14, 2011).
10.11
Second Amendment to Amended and Restated Credit Agreement dated August 31, 2012 (incorporated herein by reference to Exhibit 10.1 on Form 8-K filed on November 8, 2012).
10.12
Third Amendment to Amended and Restated Credit Agreement dated November 2, 2012 (incorporated herein by reference to Exhibit 10.2 on Form 8-K filed on November 8, 2012).
10.13
Amended and Restated Employment Agreement by and among Registrant and Robert G. Watson, Jr. dated December 31, 2012 (incorporated herein by reference to Exhibit 10.1 on Form 8-K filed on January 4, 2013).
10.14
Fourth Amendment to Amended and Restated Credit Agreement by and among Registrant and Texas Capital Bank dated December 31, 2012 (incorporated herein by reference to Exhibit 10.2 on Form 8-K filed on January 30, 2013).
10.15
First Amendment to Amended & Restated Mortgage Security Agreement, Financing Statement and Assignment of Production by and among Working Interest, LLC and Texas Capital Bank dated December 31, 2012 (incorporated herein by reference to Exhibit 10.3 on Form 8-K filed on January 30, 2013).
10.16
Mortgage, Security Agreement, Financing Statement and Assignment of Production and Revenues by and among Working Interest, LLC and Texas Capital Bank dated December 31, 2012 (incorporated herein by reference to Exhibit 10.4 on Form 8-K filed on January 30, 2013).
10.17
2013 Stock Incentive Plan (incorporated herein by reference to Exhibit 10.1 on Registration Statement on Form S-8 filed on June 12, 2013)
10.18
Fifth Amendment to Amended and Restated Credit Agreement by and among Registrant and Texas Capital Bank, N.A. dated September 30, 2013 (incorporated herein by reference to Exhibit 10.1 on Form 8-K filed October 1, 2013).
10.19
Sixth Amendment to Amended and Restated Credit Agreement by and among Registrant and Texas Capital Bank, N.A. dated November 19, 2013 (incorporated by reference to Exhibit 10.37 on Form 10-Q filed May 13, 2014).
10.20
Exchange Agreement between EnerJex Resources, Inc. and holders of Series A preferred stock (incorporated by reference to Exhibit 10.38 on Form S-1/A Amendment No. 2 filed June 3, 2014).
10.21
Seventh Amendment to Amended and Restated Credit Agreement by and among Registrant and Texas Capital Bank, N.A. dated May 22, 2014 (incorporated by reference to Exhibit 10.1 to Form 8-K filed May 27, 2014).
10.22
Form of Securities Purchase Agreement dated as of March 11, 2015 (incorporated herein by reference as Exhibit 10.1 on Current Report Form 8-K filed on March 11, 2015)
10.23
Eighth Amendment to Amended and Restated Credit Agreement by and among Registrant and Texas Capital Bank, N.A. dated August 13, 2014.*
21.1
Subsidiaries*
23.2
Consent of MHA Petroleum Consultants, LLC*
24.1
Power of Attorney (included with signatures).*
31.1
Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002*
31.2
Certification of Principal Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002*
32.1
Certification of Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002*
32.2
Certificate of Principal Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002*
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*
* Filed herewith.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this amended report to be signed on its behalf by the undersigned, thereunto duly authorized.
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.
Name
Title
Date
/s/ Robert G. Watson, Jr.
President, Chief Executive Officer,
March 31, 2015
Robert G. Watson, Jr.
(Principal Executive Officer), Secretary and Director
/s/ Douglas M. Wright
Chief Financial Officer (Principal Financial Officer)
March 31, 2015
Douglas M. Wright
/s/ Ryan A. Lowe
Director and Senior Vice President of Corporate Marketing
March 31, 2015
Ryan A. Lowe
/s/ Lance W. Helfert
Director
March 31, 2015
Lance Helfert
/s/ James G. Miller
Director
March 31, 2015
James G. Miller
/s/ Richard E. Menchaca
Director
March 31, 2015
Richard E. Menchaca
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders of
EnerJex Resources, Inc.
We have audited the accompanying consolidated balance sheet of EnerJex Resources, Inc. and Subsidiaries as of December 31, 2013, and the related consolidated statements of operations, stockholders’ equity, and cash flows for the year then ended. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the 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 audit provides a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of EnerJex Resources, Inc. and Subsidiaries as of December 31, 2013, and the results of its consolidated operations, stockholders’ equity, and cash flows for the year then ended in conformity with accounting principles generally accepted in the United States of America.
L.L. Bradford & Company, LLC
Leawood, Kansas
March 28, 2014
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders of
EnerJex Resources, Inc.
We have audited the accompanying consolidated balance sheet of EnerJex Resources, Inc. and Subsidiaries as of December 31, 2014, and the related consolidated statements of operations, stockholders’ equity, and cash flows for the year then ended. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the 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 audit provides a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of EnerJex Resources, Inc. and Subsidiaries as of December 31, 2014, and the results of its consolidated operations, stockholders’ equity, and cash flows for the year then ended in conformity with accounting principles generally accepted in the United States of America.
RBSM, LLP
Leawood, Kansas
March 31, 2015
EnerJex Resources, Inc. and Subsidiaries
Consolidated Balance Sheets
See Notes to Consolidated Financial Statements.
EnerJex Resources, Inc. and Subsidiaries
Consolidated Statements of Operations
See Notes to Consolidated Financial Statements.
EnerJex Resources, Inc. and Subsidiaries
Consolidated Statement of Stockholders' Equity
See Notes to Consolidated Financial Statements.
EnerJex Resources, Inc. and Subsidiaries
Consolidated Statements of Cash Flows
See Notes to Consolidated Financial Statements.
EnerJex Resources, Inc.
Notes to Consolidated Financial Statements
Note 1 - Summary of Accounting Policies
Basis of Presentation
Our consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States. Our operations are considered to fall within a single industry segment, which are the acquisition, development, exploitation and production of crude oil and natural gas properties in the United States. Our consolidated financial statements include our wholly owned subsidiaries.
All significant intercompany balances and transactions have been eliminated upon consolidation. Certain reclassifications have been made to the prior year financial statements to conform to the current year presentation.
As discussed further in Note 5, on September 27, 2013, we merged with Black Raven Energy, Inc. (“Black Raven”). The balance sheet accounts of Black Raven, our wholly owned subsidiary, have been consolidated as of September 30, 2013. We did not use the purchase method of accounting due to a common shareholder. Historical costs were used to combine the two entities, accordingly assets and liabilities of Black Raven were not recorded at fair value. The results of operations of Black Raven for the fourth quarter of 2013 are included in the consolidated statement of operations for the year ended December 31, 2013.
Nature of Business
We are an independent energy company engaged in the business of producing and selling crude oil and natural gas. The crude oil and natural gas is obtained primarily by the acquisition and subsequent exploration and development of mineral leases. Development and exploration may include drilling new exploratory or development wells on these leases. These operations are conducted primarily in Kansas, Colorado, Nebraska and Texas.
Use of Estimates in the Preparation of Financial Statements
The preparation of consolidated financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Significant estimates included in the consolidated financial statements are: (1) oil and gas revenues and reserves; (2) depreciation, depletion and amortization; (3) valuation allowances associated with income taxes (4) accrued assets and liabilities; (5) stock-based compensation; (6) asset retirement obligations and (7) valuation of derivative instruments. Although management believes these estimates are reasonable, changes in facts and circumstances or discovery of new information may result in revised estimates. Actual results could differ from those estimates.
Trade Accounts Receivable
Trade accounts receivable are recorded at the invoiced amount and do not bear any interest. We regularly review receivables to insure that the amounts will be collected and establish or adjust an allowance for uncollectible amounts as necessary using the specific identification method. Account balances are charged off against the allowance after all means of collection have been exhausted and the potential for recovery is considered remote.
Share-Based Payments
The value we assign to the options and warrants that we issue is based on the fair market value as calculated by the Black-Scholes pricing model. To perform a calculation of the value of our options and warrants, we determine an estimate of the volatility of our stock. We need to estimate volatility because there has not been enough trading of our stock to determine an appropriate measure of volatility. We believe our estimate of volatility is reasonable, and we review the assumptions used to determine this whenever we issue new equity instruments.
Income Taxes
Income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized when items of income and expense are recognized in the financial statements in different periods than when recognized in the applicable tax return. Deferred tax assets arise when expenses are recognized in the financial statements before the tax returns or when income items are recognized in the tax return prior to the financial statements. Deferred tax assets also arise when operating losses or tax credits are available to offset tax payments due in future years. Deferred tax liabilities arise when income items are recognized in the financial statements before the tax returns or when expenses are recognized in the tax return prior to the financial statements. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the date when the change in the tax rate was enacted.
We routinely assess the reliability of our deferred tax assets. If we conclude that it is more likely than not that some portion or all of the deferred tax assets will not be realized under accounting standards, the tax asset is reduced by a valuation allowance. In addition we routinely assess uncertain tax positions, and accrue for tax positions that are not more-likely-than-not to be sustained upon examination by taxing authorities.
Uncertain Tax Positions
We follow guidance in Topic 740 of the Codification for its accounting for uncertain tax positions. Topic 740 prescribes guidance for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. To recognize a tax position, we determine whether it is more-likely-than-not that the tax position will be sustained upon examination, including resolution of any related appeals or litigation, based solely on the technical merits of the position. A tax position that meets the more-likely-than-not threshold is measured to determine the amount of benefit to be recognized in the financial statements. The amount of tax benefit recognized with respect to any tax position is measured as the largest amount of benefit that is greater than 50 percent likely of being realized upon settlement.
We have no liability for unrecognized tax benefits recorded as of December 31, 2014 and 2013. Accordingly, there is no amount of unrecognized tax benefits that, if recognized, would affect the effective tax rate and there is no amount of interest or penalties currently recognized in the statement of operations or statement of financial position as of December 31, 2014. In addition, we do not believe that there are any positions for which it is reasonably possible that the total amounts of unrecognized tax benefits will significantly increase or decrease within the next twelve months. We recognize related interest and penalties as a component of income tax expense.
Tax years open for audit by federal tax authorities as of December 31, 2014 are the years ended December 31, 2011, 2012, 2013 and 2014. Tax years ending prior to 2011 are open for audit to the extent that net operating losses generated in those years are being carried forward or utilized in an open year.
Fair Value Measurements
Accounting guidance establishes a single authoritative definition of fair value based upon the assumptions market participants would use when pricing an asset or liability and creates a fair value hierarchy that prioritizes the information used to develop those assumptions. Additional disclosures are required, including disclosures of fair value measurements by level within the fair value hierarchy. We incorporate a credit risk assumption into the measurement of certain assets and liabilities.
Cash and Cash Equivalents
We consider all highly liquid investment instruments purchased with original maturities of three months or less to be cash equivalents for purposes of the consolidated statements of cash flows and other statements. We maintain cash on deposit, which, at times, exceeds federally insured limits. We have not experienced any losses on such accounts and believe we are not exposed to any significant credit risk on cash and equivalents.
Revenue Recognition
Oil and gas revenues are recognized net of royalties when production is sold to a purchaser at a fixed or determinable price, when delivery has occurred and title has transferred, and if collection of the revenue is probable. Cash received relating to future revenues is deferred and recognized when all revenue recognition criteria are met.
Fixed Assets
Property and equipment are recorded at cost. At December 31, 2014, Fixed Assets consisted of vehicles $967,483, furniture and equipment of $608,061, building and leasehold improvements of $23,069 and gathering and compression systems of $2,751,697, as well as accumulated depreciation of vehicles of $697,042, accumulated depreciation of furniture and fixtures of $494,333, accumulated depreciation of building and leasehold improvements of $9,386 and accumulated depreciation of gathering and compression systems of $744,846. At December 31, 2013, Fixed Assets consisted of vehicles of $900,952, furniture and equipment of $672,105, building and leasehold improvements of $19,095 and gathering and compression systems of $2,599,841 as well as accumulated depreciation of vehicles $693,093, accumulated depreciation of furniture and fixtures of $118,642, accumulated depreciation of building and leasehold improvements of $4,985 and accumulated depreciation of gathering and compression systems of $968,682.
Depreciation is on a straight-line method using the estimated lives of the assets (3-15 years). Expenditures for maintenance and repairs are charged to expense.
Debt issue costs
Debt issuance costs incurred are capitalized and subsequently amortized over the term of the related debt on the straight-line method of amortization over the estimated life of the debt.
Oil & Gas Properties
We follow the full cost method of accounting under which all costs associated with property acquisition, exploration and development activities are capitalized. We also capitalize internal costs that can be directly identified with our acquisition, exploration and development activities and do not include costs related to production, general corporate overhead or similar activities.
Proved properties are amortized using the units of production method (UOP). Currently we only have operations in the United States of America. The UOP calculation multiplies the percentage of estimated proved reserves produced each quarter by the cost of these reserves. The amortization base in the UOP calculation includes the sum of proved property, net of accumulated depreciation, depletion and amortization (DD&A), estimated future development costs (future costs to access and develop proved reserves) and asset retirement costs, less related salvage value.
The cost of unproved properties are excluded from the amortization calculation until it is determined whether or not proved reserves can be assigned to such properties or until development projects are placed into service. Geological and geophysical costs not associated with specific properties are recorded as proved property immediately. Unproved properties are reviewed for impairment quarterly.
Under the full-cost-method of accounting, the net book value of oil and gas properties, less deferred income taxes, may not exceed a calculated “ceiling.” The ceiling limitation is (a) the present value of future net revenues computed by applying current prices of oil & gas reserves (with consideration of price changes only to the extent provided by contractual arrangements) to estimated future production of proved oil & gas reserves as of the date of the latest balance sheet presented, less estimated future expenditures (based on current costs) to be incurred in developing and producing the proved reserves computed using a discount factor of 10 percent and assuming continuation of existing economic conditions plus (b) the cost of properties not being amortized plus (c) the lower of cost or estimated fair value of unproven properties included in the costs being amortized less (d) income tax effects related to differences between book and tax basis of properties. Future cash outflows associated with settling accrued retirement obligations are excluded from the calculation. Estimated future cash flows are calculated using end-of-period costs and an un-weighted arithmetic average of commodity prices in effect on the first day of each of the previous 12 months held flat for the life of the production, except where prices are defined by contractual arrangements.
Any excess of the net book value of proved oil and gas properties, less related deferred income taxes, over the ceiling is charged to expense and reflected as additional DD&A in the statement of operations. The ceiling calculation is performed quarterly. During the years ended December 31, 2014 and 2013 there were no impairments resulting from the quarterly ceiling tests.
Proceeds from the sale or disposition of oil and gas properties are accounted for as a reduction to capitalized costs unless a significant portion (greater than 25%) of our reserve quantities are sold, in which case a gain or loss is recognized in income.
Long-Lived Assets
Impairment of long-lived assets is recorded when indicators of impairment are present and the undiscounted cash flows estimated to be generated by those assets are less than the assets' carrying value. The carrying value of the assets is then reduced to their estimated fair value that is usually measured based on an estimate of future discounted cash flows.
Asset Retirement Obligations
The asset retirement obligation relates to the plug and abandonment costs when our wells are no longer useful. We determine the value of the liability by obtaining quotes for this service and estimate the increase we will face in the future. We then discount the future value based on an intrinsic interest rate that is appropriate for us. If costs rise more than what we have expected there could be additional charges in the future, however, we monitor the costs of the abandoned wells and we will adjust this liability if necessary.
Major Purchasers
For the years ended December 31, 2014, and 2013 we sold our produced crude oil to Coffeyville Resources, Plains Marketing, L.P., and Sunoco, Inc. on a month-to-month basis and we sold our produced natural gas to United Energy Trading and Western Operating Company.
Marketable Securities Available for Sale
The Company classifies its marketable equity securities as available-for-sale and they are carried at fair market value, with the unrealized gains and losses included in accumulated other comprehensive income and reported in stockholders’ equity. The difference between cost and market totals $552,589 for the years ended December 31, 2014 and 2013.
Net Income Per Common Share
Basic net income per share is computed by dividing net income available to common shareholders by the weighted average number of common shares outstanding during the period. Diluted earnings per share reflect, in periods in which they have a dilutive effect, the impact of common shares issuable upon exercise of stock options and warrants and conversion of convertible debt that are not deemed to be anti-dilutive. The dilutive effect of the outstanding stock options and warrants is computed using the treasury stock method.
For the year ended December 31, 2014, diluted net income per share did not include the effect of 231,332 shares of common stock issuable upon the exercise of outstanding stock options as their effect would be anti-dilutive.
For the year ended December 31, 2013, diluted net income per share did not include the effect of 172,833 shares of common stock issuable upon the exercise of outstanding stock options as their effect would be anti-dilutive.
Reclassifications
Certain reclassifications have been made to prior periods to conform to current presentations.
Recent Accounting Pronouncements Applicable to the Company
The Company does not believe there are any recently issued, but not yet effective; accounting standards that would have a significant impact on the Company’s financial position or results of operations.
Note 2 - Equity Transactions
Stock transactions in fiscal year ended December 31, 2014
In 2014, 7,707 shares were issued to employees of the Company as compensation. The value of those shares was $59,298. Also in 2014, 9,625 shares were issued and 17,500 shares are owed (but not issued) for professional services rendered on behalf of the Company. The value of those share was $175,356.
Effective after the close of trading in EnerJex common stock on May 30, 2014, the Company affected a 1-for-15 reverse stock split, by which each share of EnerJex common stock was reclassified, and changed into 1/15th of a fully paid and non-assessable share of common stock. In lieu of fractions of a share, the Company paid to holders of fractions of a share cash equal to $11.25 per share, which was the minimum value designated in the amended and restated certificate of designations affecting the reverse stock split.
On June 16, 2014, we adopted the Amended and Restated Certificate of Designation modifying the terms of our then-existing Series A preferred stock. Concurrently with filing of that Amended and Restated Certificate of Designation, the holders of our existing Series A preferred stock exchanged each outstanding share of such existing Series A preferred stock for (i) a number of shares of our common stock into which such Series A preferred stock was then convertible immediately prior to the exchange (318,630 shares in the aggregate), and (ii) 112,658 shares of Series A preferred stock which was equal to the quotient determined by dividing (x) that portion of the holder's original Series A preferred stock purchase price that had not yet been paid in dividends, by (y) $23.75.
On June 20, 2014, we closed an underwritten initial public offering of 639,157 shares of our Series A preferred stock at a purchase price of $23.75 per share for gross proceeds of $15,179,938. Costs associated with the offering were $1,832,374 for net proceeds of $13,347,564.
Effective September 30, 2014 the Board of Directors approved the retirement of 383,333 shares in held in the Treasury. Accordingly $2,551,000 was reclassified to Paid-in capital.
Stock transactions in fiscal year ended December 31, 2013
We issued 6,000 shares at $7.50 per share to employees as compensation.
On September 30, 2013 the Company issued 2,755,168 shares to Black Raven Energy, Inc. shareholders in exchange for their shares of Black Raven Energy, Inc. common shares. (See Note 5).
Option transactions
Officers (including officers who are members of the Board of Directors), directors, employees and consultants are eligible to receive options under our stock option plans. We administer the stock option plans and we determine those persons to whom options will be granted, the number of options to be granted, the provisions applicable to each grant and the time periods during which the options may be exercised. No options may be granted more than ten years after the date of the adoption of the stock option plans.
Each option granted under the stock option plans will be exercisable for a term of not more than ten years after the date of grant. Certain other restrictions will apply in connection with the plans when some awards may be exercised. In the event of a change of control (as defined in the stock option plans), the vesting date on which all options outstanding under the stock option plans may first be exercised will be accelerated. Generally, all options terminate 90 days after a change of control.
Stock Incentive Plan
The Board of Directors approved the EnerJex Resources, Inc. Stock Option Plan on August 1, 2002 (the "2002-2003 Stock Option Plan"). Originally, the total number of options that could be granted under the 2002-2003 Stock Option Plan was not to exceed 26,666 shares. In September 2007 our stockholders approved a proposal to amend and restate the 2002-2003 Stock Option Plan to increase the number of shares issuable to 66,666. On October 14, 2008 our stockholders approved a proposal to amend and restate the 2002-2003 Stock Option Plan to (i) rename it the EnerJex Resources, Inc. Stock Incentive Plan (the "Stock Incentive Plan"), (ii) increase the maximum number of shares of our common stock that may be issued under the Stock Incentive Plan to 83,333, and (iii) add restricted stock as an eligible award that can be granted under the Stock Incentive Plan.
On December 31, 2010 we granted 60,000 options that vest ratably over a 48 month period and are exercisable at $6.00 per share to an Officer of the company. The term of the options is 5 years. The fair value of the options as calculated using the Black-Scholes model was $307,751. The amount recognized as expense in each of the years ended December 31, 2014 and 2013 was $76,938.
2013 Stock Incentive Plan
The Board and stockholders approved the adoption of the 2013 Stock Incentive Plan (“Plan”). The Plan reserves 333,300 shares of our common stock for the granting of options and issuance of restricted shares to our employees, officers, directors, and consultants. The Plan increases reserved shares annually based on plan provisions.
In 2013, we granted 119,133 options to employees. Thirty-three percent of these options vest one year after the date of the grant. The remaining options vest ratably each month over a two year period. The fair value of the option on the date of the grant calculated using the Black-Scholes model was $675,344 using the following weighted average assumptions: exercise price of $10.50 per share; common stock price of ranging from $7.95 to $8.40 per share; volatility ranging from 67% to 72%; term of three years; dividend yield of 0%; interest rate of .47%.
In 2014, we granted 2,367 options to employees. Thirty-three percent of these options vest one year after the date of the grant. The remaining options vest ratably each month over a two year period. The fair value of the option on the date of the grant calculated using the Black-Scholes model was $12,178 using the following weighted average assumptions: exercise price of $10.50 per share; common stock price of $7.95 per share; volatility of 72%; term of three years; dividend yield of 0%; interest rate of .47%.
We expensed $326,579 and $72,434 for the years ended December 31, 2014 and December 31, 2013 respectively for options granted. We also expensed $76,938 in each of the years ended December 31, 2014 and December 31, 2013 for options recorded as prepaid assets.
Warrant Transactions
On May 31, 2012, we granted 16,667 Warrants to a consultant for services to be performed over the next two years. Each warrant was exercisable until May 31, 2014. The fair value at the date of grant was calculated using the Black-Scholes model and totaled approximately $86,000. On January 3, 2013, we granted 20,000 Warrants to a consultant for services to be performed over the next year. The fair value at the date of grant was calculated using the Black-Scholes model and totaled approximately $41,000. In the fourth quarter of 2013 all 36,667 warrants were cancelled unexercised.
A summary of stock options and warrants is as follows:
The number of options that were vested at December 31, 2014 was 150,843. The number of options that were not vested at December 31, 2014 was 80,489.
Note 3 - Asset Retirement Obligation
Our asset retirement obligations relate to the abandonment of oil and gas wells. The amounts recognized are based on numerous estimates and assumptions, including future retirement costs, inflation rates and credit adjusted risk-free interest rates. The following shows the changes in asset retirement obligations:
Note 4 - Long-Term Debt
Senior Secured Credit Facility
On October 3, 2011, the Company, DD Energy, Inc., EnerJex Kansas, Inc., Black Sable Energy, LLC and Working Interest, LLC ("Borrowers") entered into an Amended and Restated Credit Agreement with Texas Capital Bank, and other financial institutions and banks that may become a party to the Credit Agreement from time to time. The facilities provided under the Amended and Restated Credit Agreement are to be used to refinance Borrowers prior outstanding revolving loan facility with Bank, dated July 3, 2008, and for working capital and general corporate purposes.
At our option, loans under the facility will bear stated interest based on the Base Rate plus Base Rate Margin, or Floating Rate plus Floating Rate Margin (as those terms are defined in the Credit Agreement). The Base Rate will be, for any day, a fluctuating rate per annum equal to the higher of (a) the Federal Funds Rate plus 0.50% and (b) the Bank's prime rate. The Floating Rate shall mean, at Borrower's option, a per annum interest rate equal to (i) the Eurodollar Rate plus Eurodollar Margin, or (ii) the Base Rate plus Base Rate Margin (as those terms are defined in the Amended and Restated Credit Agreement). Eurodollar borrowings may be for one, two, three, or six months, as selected by the Borrowers. The margins for all loans are based on a pricing grid ranging from 0.00% to 0.75% for the Base Rate Margin and 2.25% to 3.00% for the Floating Rate Margin based on the Company's Borrowing Base Utilization Percentage (as defined in the Amended and Restated Credit Agreement).
We entered into a First Amendment to Amended and Restated Credit Agreement and Second Amended and Restated Promissory Note in the amount of $50,000,000 with Texas Capital Bank, which closed on December 15, 2011. The Amendment reflects the addition of Rantoul Partners, as an additional Borrower and adds as additional security for the loans the assets held by Rantoul Partners.
On August 31, 2012, we entered into a Second Amendment to Amended and Restated Credit Agreement with Texas Capital Bank. The Second Amendment: (i) increased the borrowing base to $7,000,000 (ii) reduced the minimum interest rate to 3.75% and (iii) added additional new leases as collateral for the loan.
On November 2, 2012, we entered into a Third Amendment to Amended and Restated Credit Agreement with Texas Capital Bank. The Third Amendment (i) increased the borrowing base to $12,150,000 and (ii) clarified certain continuing covenants and provided a limited waiver of compliance with one of the covenants so clarified for the fiscal quarter ended December 31, 2011.
On January 24, 2013, we entered into a Fourth Amendment to Amended and Restated Credit Agreement, which was made effective as of December 31, 2012 with Texas Capital Bank. The Fourth Amendment reflects the following changes: (i) the Bank consented to the restructuring transactions related to the dissolution of Rantoul Partners, and (ii) the Bank terminated a Limited Guaranty, as defined in the Credit Agreement, executed by Rantoul Partners in favor of the Bank
On April 16, 2013, the Bank increased our borrowing base to $19.5 million.
On September 30, 2013, the Company entered into a Fifth Amendment to the Amended and Restated Credit Agreement. The Fifth Amendment reflects the following changes: (i) an expanded principal commitment amount of the Bank to $100,000,000; (ii) increased the Borrowing Base to $38,000,000; (iii) added Black Raven Energy, Inc. to the Credit Agreement as borrower parties; (iv) added certain collateral and security interests in favor of the Bank; and (v) reduced the Company’s current interest rate to 3.30%.
On November 19, 2013, we entered into a Sixth Amendment to the Amended and Restated Credit Agreement. The Sixth Amendment reflects the following changes: (i) the addition of Iberia Bank as a participant in our credit facility, and (ii) a technical correction to our covenant calculations.
On May 22, 2014, we entered into a Seventh Amendment to the Amended and Restated Credit Agreement. The Seventh Amendment reflects the Bank’s consent to our issuance of up to 850,000 shares of our 10% Series A Cumulative Redeemable Perpetual Preferred Stock.
On August 15, 2014 we entered into an Eighth Amendment to the Amended and Restated Credit Agreement. The Eighth Amendment reflects the following changes: (i) the borrowing base was increased from $38 million to $40 million, and (ii) the maturity of the facility was extended by three years to October 3, 2018.
Our Current borrowing base is $40 million, of which we had borrowed $23.0 million as of December 31, 2014. We intend to conduct an additional borrowing base review in the third quarter of 2015. For the year ended December 31, 2014 the interest rate was 3.3 %. This facility expires on October 3, 2018.
We financed the purchase of vehicles through a bank. The notes are for four years and the vehicles collateralize these notes. The long term balance on the notes at December 31, 2014 was $11,660.
Note 5 - Merger
On July 23, 2013, EnerJex, BRE Merger Sub, Inc., a Delaware corporation and a wholly owned subsidiary of EnerJex (Merger Sub), and Black Raven Energy, Inc., a Nevada corporation, entered into an agreement and plan of merger (Merger Agreement) pursuant to which Black Raven would be merged with and into Merger Sub and after which Black Raven would be a wholly owned subsidiary of EnerJex.
On September 27, 2013, the transactions contemplated by the Merger Agreement were successfully completed.
The following transactions were executed on September 27, 2013 per the terms of the Merger Agreement (i) shares of capital stock of Black Raven were converted into (a) cash totaling $207,067 and (b) 41,327,516 shares of EnerJex common stock, (ii) all options under the Black Raven option plan were cancelled, and (iii) all warrants or other rights to purchase shares of capital stock of Black Raven were converted into warrants to purchase EnerJex common stock. No fractional shares of EnerJex common stock were issued in connection with the Merger, and holders of Black Raven common stock were entitled to receive cash in lieu thereof. The board of directors and executive officers of EnerJex remained unchanged as a result of the closing of the Merger.
At closing of the transactions contemplated by the Merger Agreement, the previous stockholders of Black Raven owned approximately 38% of the outstanding voting stock of EnerJex and the previous stockholders of EnerJex owned approximately 62% of the outstanding voting stock of EnerJex.
The following selected pro forma condensed financial information of EnerJex and Black Raven combines the consolidated financial information of EnerJex for the twelve month period ended December 31, 2013 with the financial information of Black Raven for the twelve months ended December 31, 2013.
EnerJex and Black Raven present the unaudited pro forma condensed consolidated financial information for informational purposes only. The pro forma information is not necessarily indicative of what the combined company’s financial position or results of operations actually would have been had EnerJex and Black Raven completed the merger on January 1, 2013. In addition the unaudited pro forma condensed consolidated financial information does not purport to project the future financial position or operating results of the combined company. The unaudited pro forma condensed consolidated financial information does not give effect to any potential cost savings or other operating efficiencies that could result from the merger. The unaudited pro forma condensed consolidated financial information is not adjusted for any merger related transaction costs or other non-recurring expenses.
The unaudited pro forma condensed consolidated financial information includes estimates of Black Raven had it accounted for its investments in oil and gas assets using the full cost method of accounting and not the successful efforts method of accounting. The unaudited pro forma consolidated financial information was prepared using the full cost method of accounting for oil and gas activities.
Pro Forma Consolidated Combined Statements of Operations (Unaudited)
For the Year Ended December 31, 2013
Note 6 - Related party transactions
In the normal course of business we utilize the services of stockholders who perform work for us at normal business rates.
Note 7 - Commitments and Contingencies
Rent expense for the years ended December 31, 2014 and 2013 was approximately $159,000 and $185,000 respectively. Future non-cancellable minimum lease payments are approximately $150,000 for 2015, $147,000 for 2016, $145,000 for 2017, $91,000 for 2018 and $77,000 for 2019. We received rental income from sub rentals of $37,000 in 2013.
We, as a lessee and operator of oil and gas properties, are subject to various federal, state and local laws and regulations relating to discharge of materials into, and protection of, the environment. These laws and regulations may, among other things, impose liability on the lessee under an oil and gas lease for the cost of pollution clean-up resulting from operations and subject to the lessee to liability for pollution damages. In some instances, the Company may be directed to suspend or cease operations in the affected area. As of December 31, 2014, we have no reserve for environmental remediation and are not aware of any environmental claims.
As of December 31, 2014, the Company has an outstanding irrevocable letter of credit in the amount of $50,000 issued in favor of the Texas Railroad Commission. This letter of credit is required by the Commission by all companies operating in the state in accordance with limits prescribed by the Texas Railroad Commission.
Note 8 - Income Taxes
There was no current or deferred income tax expense (benefit) for the years ended December 31, 2014 and December 31, 2013.
The following table sets forth a reconciliation of the provision for income taxes to the statutory federal rate:
Significant components of the deferred tax assets and liabilities are as follows:
At December 31, 2014, we have a net operating loss carry forward of approximately $76 million expiring in 2021-2035 that is subject to certain limitations on an annual basis. A valuation allowance has been established against net operating losses where it is more likely than not that such losses will expire before they are utilized.
The Company incurred a change of control as defined by the Internal Revenue Code. Accordingly, the rules will limit the utilization of the Company’s net operating losses. The limitation is determined by multiplying the value of the stock immediately before the ownership change by the applicable long-term exempt rate. It is estimated that approximately $40.9 million of net operating losses may be subject to an annual limitation. Any unused annual limitation may be carried over to later years. The amount of the limitation may under certain circumstances be increased by the built-in gains in assets held by the Company at the time of the change that are recognized in the five-year period after the change.
Note 9 - Fair Value Measurements
We hold certain financial assets which are required to be measured at fair value on a recurring basis in accordance with the Statement of Financial Accounting Standard No. 157, “Fair Value Measurements” (“ASC Topic 820-10”). ASC Topic 820-10 establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements). ASC Topic 820-10 defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants on the measurement date. A fair value measurement assumes that the transaction to sell the asset or transfer the liability occurs in the principal market for the asset or liability. The three levels of the fair value hierarchy under ASC Topic 820-10 are described below:
Level 1. Valuations based on quoted prices in active markets for identical assets or liabilities that an entity has the ability to access. We believe receivables, payables and our debt approximate fair value at December 31, 2014.
Level 2. Valuations based on quoted prices for similar assets or liabilities, quoted prices for identical assets or liabilities in markets that are not active, or other inputs that are observable or can be corroborated by observable data for substantially the full term of the assets or liabilities. We consider the derivative liability to be Level 2. We determine the fair value of the derivative liability utilizing various inputs, including NYMEX price quotations and contract terms.
Level 3. Valuations based on inputs that are supported by little or no market activity and that are significant to the fair value of the assets or liabilities. We consider the marketable securities to be a Level 3. Our derivative instruments consist of fixed price commodity swaps.
Note 10 - Derivative Instruments
We have entered into certain derivative or physical arrangements with respect to portions of our crude oil production to reduce our sensitivity to volatile commodity prices and/or to meet hedging requirements under our Credit Facility. We believe that these derivative arrangements, although not free of risk, allow us to achieve a more predictable cash flow and to reduce exposure to commodity price fluctuations. However, derivative arrangements limit the benefit of increases in the prices of crude oil. Moreover, our derivative arrangements apply only to a portion of our production.
We have an Intercreditor Agreement in place between the Company; our counterparties, BP Corporation North America, Inc. and Cargill Incorporated and our agent, Texas Capital Bank, N.A., which allows Texas Capital Bank to also act as agent for the counterparties for the purpose of holding and enforcing any liens or security interests resulting from our derivative arrangements. Therefore, we generally are not required to post additional collateral, including cash.
The following derivative contracts were in place at December 31, 2014:
(1) Monthly volumes are the weighted average throughout the period.
The total fair value of derivative contracts is shown in both current and non-current assets and liabilities on the balance sheet. We recorded gains on the derivative contracts for the year ended December 31, 2014 of $4,993,262 and losses for the year ended December 31, 2013 of $740,456.
Note 11 - Net Income Per Common Share
The Company reports earnings per share in accordance with ASC Topic 260-10, "Earnings per Share." Basic earnings per share is computed by dividing income available to common shareholders by the weighted average number of common shares available. Diluted earnings per share is computed similar to basic earnings per share except that the denominator is increased to include the number of additional common shares that would have been outstanding if the potential common shares had been issued and if the additional common shares were dilutive.
Note 12 - Subsequent Events
On March 13, 2015 the Company issued in a registered offering 763,547 registered shares of its common stock together with 1,242.17099 shares of its newly designated Series B Convertible Preferred Stock (the "Preferred Stock") convertible into 709,812 shares of common stock. We also issued in an unregistered offering, 521.62076 shares of Preferred Stock convertible into 298,069 shares of common stock, and warrants to purchase 1,771,428 shares of its common stock. The shareholder’s ability to convert a portion of the Preferred Stock and to exercise the warrant are restricted: (i) prior to the Company obtaining approval of the offering by its shareholders, which we expect to obtain before May 31, 2015, and (ii) pursuant to customary “blocker” provisions restricting the investor’s ownership to 9.99% of our outstanding common stock.
The Preferred Stock has a liquidation preference of $1,000 per share, and will be convertible at the option of the shareholder at a conversion ratio equal to approximately 571 shares of common stock for each one (1) share of Preferred Stock, subject to customary adjustments and anti-dilution price protection. Dividends are payable on the shares of Preferred Stock only if and to the extent that dividends are payable on the common stock into which the Preferred Stock is convertible. The Preferred Stock has no maturity date and can be redeemed by the Company beginning twelve months after the closing of the offering or upon a change of control. Each warrant will be exercisable for one share of common stock, for a period of five years beginning six months after March 13, 2015, at a cash exercise price of $2.75 per share, and may be exercised on a cashless basis after that six-month period if no effective registration statement covers the warrant shares by that time.
On January 15, 2015, 52,000 options were issued to employees.
Note 13 - Supplemental Oil and gas Reserve Information (Unaudited)
Results of operations from oil and gas producing activities
The following table shows the results of operations from the Company’s oil and gas producing activities. Results of operations from these activities are determined using historical revenues, production costs and depreciation and depletion. The results of operations from the Company’s oil and gas producing activities below exclude non-oil and gas revenues, general and administrative expenses, interest income and interest expense. Income tax expense was determined by applying the statutory rates to pretax operating results.
Capitalized costs
The following table summarizes the Company’s capitalized costs of oil and gas properties.
Cost incurred in property acquisition, exploration and development activities
Estimated quantities of proved reserves
Our ownership interests in estimated quantities of proved oil and gas reserves and changes in net proved reserves all of which are located in the United States are summarized below. Proved reserves are estimated quantities of oil and gas that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are those that are expected to be recovered through existing wells with existing equipment and operating methods. Reserves are stated in barrels of oil equivalent. Geological and engineering estimates by MHA Petroleum Consultants, LLC of proved oil and gas reserves at one point in time are highly interpretive, inherently imprecise and subject to ongoing revisions that may be substantial in amount. Although every reasonable effort is made to ensure that the reserve estimates are accurate, by their nature reserve estimates are generally less precise than other estimates presented in connection with financial statement disclosures.
Proved developed reserves at December 31, 2014 consisted of 77% oil and 23% natural gas and totaled 3,048.3 MBOEs. Proved developed reserves for December 31, 2013 consisted of 83% oil and 17% natural gas and totaled 3,824.9 MBOEs. Proved undeveloped reserves for December 31, 2014 were 1,351.9 MBOEs. Proved undeveloped reserves at December 31, 2013 were 1,979.9 MBOEs.
Standardized measure of discounted future net cash flows
The standardized measure of discounted future net cash flows from our proved reserves for the periods presented in the financial statements is summarized below.
Changes in standardized measure of discounted future net cash flows
The following is a summary of a standardized measure of discounted net future cash flows related to the Company’s proved oil and gas reserves. The information presented is based on a calculation of estimated proved reserves using discounted cash flows based on the 12-month average price for oil and gas calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month prior period. The additions to estimated proved reserves from new discoveries and extensions could vary significantly from year to year. Additionally, the impact of changes to reflect current prices and costs of reserves proved in prior years could also be significant.