SRCI SRC Energy Inc

RISK FACTORS

         An investment in our common stock offered by this prospectus supplement and the accompanying prospectus involves a high degree of risk. You should carefully consider the following risk factors in addition to the remainder of this prospectus supplement and the accompanying prospectus, including the information incorporated by reference, including under the heading "Risk Factors" in the accompanying prospectus and in our Annual Report on Form 10-K for the year ended August 31, 2015, which is incorporated herein by reference, before making an investment decision. The risks and uncertainties described in these incorporated documents and described below are not the only risks and uncertainties that we face. Additional risks and uncertainties not presently known to us or which we currently consider to be immaterial may also impair our business operations. If any of these risks actually occurs, our business, financial condition and results of operations would suffer. In that event, the trading price of our common stock could decline, and you may lose all or part of your investment in our common stock. The risks discussed below also include forward-looking statements, and our actual results may differ substantially from those discussed in these forward-looking statements. Please see the section entitled "Special Note Regarding Forward-Looking Statements" in this prospectus supplement.

Risks Relating to Our Business and the Industry

An extended or further decline in oil and natural gas prices may adversely affect our business, financial condition, or results of operations and our ability to meet our financial commitments. Additionally, the value of our proved reserves calculated using SEC pricing may be higher than the estimated or fair market value of our proved reserves using more recent prices.

        The prices we receive for our oil and natural gas significantly affects many aspects of our business, including our revenue, profitability, access to capital, quantity and present value of proved reserves and future rate of growth. Oil and natural gas are commodities, and their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for oil and natural gas have been volatile. In the recent past, benchmark oil prices have fallen from highs of over $100 per Bbl to lows below $30 per Bbl, and natural gas prices have experienced declines of comparable magnitude. Oil and natural gas prices will likely continue to be volatile in the future and will depend on numerous factors beyond our control. These factors include the following:

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worldwide and regional economic conditions impacting the global supply and demand for oil and natural gas;



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the actions of OPEC;



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the price and quantity of imports of foreign oil and natural gas;



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political conditions in or hostilities in oil-producing and natural gas-producing regions and related sanctions, including current conflicts in the Middle East and conditions in Africa, South America, and Russia;



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the level of global oil and domestic natural gas exploration and production;



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the level of global oil and domestic natural gas inventories;



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prevailing prices on local oil and natural gas price indexes in the areas in which we operate;



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localized supply and demand fundamentals and gathering, processing, and transportation availability;



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weather conditions and natural disasters;



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domestic and foreign governmental regulations;



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exports from the United States of liquefied natural gas or oil;

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speculation as to the future price of oil and the speculative trading of oil and natural gas futures contracts;



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price and availability of competitors' supplies of oil and natural gas;



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technological advances affecting energy consumption; and



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the price and availability of alternative fuels.

        Lower oil and natural gas prices will reduce our cash flows and our borrowing ability. Our business has historically relied on the availability of additional capital, including proceeds from the sale of equity and convertible securities, to execute our business strategy. Further, our future growth strategy requires substantial additional capital, the availability of which will depend in significant part on current and expected commodity prices. If we are unable to raise capital on acceptable terms in the future, we may be unable to pursue our future acquisition, drilling, and development plans. While our current revolving credit facility provides for commitments of up to $500 million, actual borrowings may not exceed our borrowing base in effect at any time, which is subject to re-determination on a semi-annual basis. Our borrowing base is based in substantial part on the value of our oil and natural gas reserves which are, in turn, impacted by prevailing oil and natural gas prices. Accordingly, declining oil and natural gas prices have a direct impact on the amount that we can borrow under our revolving credit facility, which could affect our cash flows and ability to execute on our business plans. In January 2016, the borrowing base under our revolving credit facility was reduced from $163 million to $145 million. As of March 31, 2016, $145 million is unused and available for future borrowing. The next semi-annual redetermination is scheduled to occur on May 1, 2016. We may experience further decreases in our borrowing base if oil and natural gas prices stay at current levels or continue to decline. If our borrowing base declines significantly, we would have to either raise additional capital or adjust our drilling plan.

        In addition, lower prices have reduced and may further reduce the amount of oil and natural gas that we can produce economically and may cause the value of our estimated proved reserves at future reporting dates to decline compared to the value of our estimated proved reserves at August 31, 2015. Our estimated proved reserves as of August 31, 2015, and related PV-10 and standardized measure values, were calculated under SEC rules using twelve-month trailing average benchmark prices of $53.27 per barrel of oil (West Texas Intermediate Cushing ("WTI") and $3.28 per MMBtu (Henry Hub). The twelve-month trailing average benchmark prices to be used in calculating proved reserves as of December 31, 2015 were $41.33 per barrel of oil (WTI) and $2.60 per MMBtu (Henry Hub). These lower prices adversely affected the estimated quantity and value of our proved reserves.

        Furthermore, sustained periods with oil and natural gas prices at recent or lower levels and the resultant effect such prices will have on our drilling economics and our ability to raise capital would likely require us to re-evaluate and postpone or eliminate our development drilling, which would likely result in the further reduction of some of our proved undeveloped reserves and PV-10 and standardized measure values, and would make it more difficult for us to achieve expected levels of production. At current commodity prices, it will be difficult to generate acceptable rates of return from drilling activities unless we are able to achieve additional cost savings and/or efficiencies.

        To attempt to reduce our price risk, we periodically enter into hedging transactions with respect to a portion of our expected future production. We cannot assure you that such transactions will reduce the risk or minimize the effect of any decline in oil or natural gas prices. To the extent that oil and natural gas prices remain at current levels or decline further, we will not be able to hedge future production at the same pricing level as our current hedges and our results of operations and financial condition would be negatively impacted. In addition, hedging arrangements can expose us to risk of financial loss in some circumstances, including when production is less than expected, a counterparty to a hedging contract fails to perform under the contract, or there is a change in the expected differential between the underlying price in the hedging contract and the actual prices received.

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        Accordingly, any substantial or extended decline in the prices that we receive for our production would have a material adverse effect on our financial condition, liquidity, ability to meet our financial obligations, and our results of operations.

Operating hazards may adversely affect our ability to conduct business.

        Our operations are subject to risks inherent in the oil and natural gas industry, such as:

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unexpected drilling conditions including blowouts, cratering, and explosions;



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uncontrollable flows of oil, natural gas, or well fluids;



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equipment failures, fires, or accidents;



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pollution, releases of hazardous materials, and other environmental risks; and



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shortages in experienced labor or shortages or delays in the delivery of equipment.

        These risks could result in substantial losses to us from injury and loss of life, damage to and destruction of property and equipment, pollution and other environmental damage, and suspension of operations. We do not maintain insurance for all of these risks, nor in amounts that cover all of the losses to which we may be subject, and the insurance that we have may not continue to be available on acceptable terms. Moreover, some risks that we face are not insurable. Also, we could in some circumstances have liability for actions taken by third parties over which we have no or limited control, including operators of properties in which we have an interest. The occurrence of an uninsured or underinsured loss could result in significant costs that could have a material adverse effect on our financial condition and liquidity. In addition, maintenance activities undertaken to reduce operational risks can be costly and can require exploration, exploitation, and development operations to be curtailed while those activities are being completed.

Our actual production, revenues, and expenditures related to our reserves are likely to differ from our estimates of proved reserves. We may experience production that is less than estimated, and drilling costs that are greater than estimated, in our reserve report. These differences may be material.

        Although the estimates of our oil and natural gas reserves and future net cash flows attributable to those reserves were prepared by Ryder Scott, our independent petroleum and geological engineers, we are ultimately responsible for the disclosure of those estimates. Reserve engineering is a complex and subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner. Estimates of economically recoverable oil and natural gas reserves and of future net cash flows necessarily depend upon a number of variable factors and assumptions, including:

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historical production from the area compared with production from similar producing wells;



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the assumed effects of regulations by governmental agencies;



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assumptions concerning future oil and natural gas prices; and



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assumptions concerning future operating costs, severance and excise taxes, development costs, and work-over and remedial costs.

        Because all reserve estimates are to some degree subjective, each of the following items may differ from those assumed in estimating proved reserves:

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the quantities of oil and natural gas that are ultimately recovered;



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the production and operating costs incurred;



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the amount and timing of future development expenditures; and

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future oil and natural gas sales prices.

        Historically, there has been a difference between our actual production and the production estimated in a prior year's reserve report. We cannot assure you that these differences will not be material in the future.

        Approximately 73% of our estimated proved reserves at December 31, 2015 are undeveloped. Recovery of undeveloped reserves requires significant capital expenditures and successful drilling operations. Our estimates of proved undeveloped reserves reflect our plans to make significant capital expenditures to convert those reserves into proved developed reserves, including approximately $309.1 million in estimated capital expenditures during the four years ending December 31, 2019. The estimated development costs may not be accurate, development may not occur as scheduled, and results may not be as estimated. If we choose not to develop proved undeveloped reserves, or if we are not otherwise able to successfully develop them, we will be required to remove the associated volumes from our reported proved reserves. In addition, under the SEC's reserve reporting rules, proved undeveloped reserves generally may be booked only if they relate to wells scheduled to be drilled within five years of the date of initial booking, and we may, therefore, be required to downgrade to probable or possible any proved undeveloped reserves that are not developed or expected to be developed within this five-year time frame.

        You should not assume that the standardized measure of discounted cash flows is the current market value of our estimated oil and natural gas reserves. In accordance with SEC requirements, the standardized measure of discounted cash flows from proved reserves at December 31, 2015 is based on twelve-month average prices and costs as of the date of the estimate. These prices and costs will change and may be materially higher or lower than the prices and costs as of the date of the estimate. Any changes in consumption by oil and natural gas purchasers or in governmental regulations or taxation may also affect actual future net cash flows. The timing of both the production and the expenses from the development and production of oil and natural gas properties will affect the timing of actual future net cash flows from proved reserves and their present value. In addition, the 10% discount factor we use when calculating standardized measure of discounted cash flows for reporting requirements in compliance with accounting requirements is not necessarily the most appropriate discount factor. The effective interest rate at various times and the risks associated with our operations or the oil and natural gas industry in general will affect the accuracy of our estimates of our oil and gas reserves. Each of the foregoing considerations also impacts the PV-10 values of our reserves.

Seasonal weather conditions, wildlife restrictions, and other constraints could adversely affect our ability to conduct operations.

        Our operations could be adversely affected by weather conditions and wildlife restrictions. In the Rocky Mountains, certain activities cannot be conducted as effectively during the winter months. Winter and severe weather conditions limit and may temporarily halt operations. These constraints and resulting shortages or high costs could delay or temporarily halt our operations and materially increase our operational and capital costs, which could have a material adverse effect on our business, financial condition and results of operations.

        Similarly, some of our properties are located in relatively populous areas in the Wattenberg Field, and our operations in those areas may be subject to additional expenses and limitations. For example, we may incur additional expenses in those areas to mitigate noise and odor issues relating to our operations, and we may find it more difficult to obtain drilling permits and other governmental approvals. In addition, the risk of litigation related to our operations may be higher in those areas. Any of these factors could have a material impact on our operations in the Wattenberg Field and could have a material adverse effect on our business, financial condition, and results of operations.

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        Furthermore, a critical habitat designation for certain wildlife under the U.S. Endangered Species Act or similar state laws could result in material restrictions to public or private land use and could delay or prohibit land access or development. The listing of certain species as threatened or endangered could have a material adverse effect on our operations in areas where such listed species are found.

Our future success depends upon our ability to find, develop, produce, and acquire additional oil and natural gas reserves that are economically recoverable. Drilling activities may be unsuccessful or may be less successful than anticipated.

        In order to maintain or increase our reserves, we must locate and develop or acquire new oil and natural gas reserves to replace those being depleted by production. We must do this even during periods of low oil and natural gas prices when it is difficult to raise the capital necessary to finance our exploration, development, and acquisition activities. Without successful exploration, development, or acquisition activities, our reserves and revenues will decline rapidly. We may not be able to find and develop or acquire additional reserves at an acceptable cost or have access to necessary financing for these activities, either of which would have a material adverse effect on our financial condition.

        Our management has identified and scheduled drilling locations as an estimation of our future multi-year drilling activities on our existing acreage. These identified drilling locations represent a significant part of our strategy. Our ability to drill and develop these locations depends on a number of uncertainties, including the availability of capital, seasonal conditions, regulatory approvals, oil and natural gas prices, costs, drilling results, and the accuracy of our assumptions and estimates regarding potential well communication issues and other matters affecting the spacing of our wells. Because of these uncertainties, we do not know if the numerous potential drilling locations that we have identified will ever be drilled or if we will be able to produce oil and natural gas from these or any other potential drilling locations. Many factors may cause us to curtail, delay, or cancel scheduled drilling projects, including factors relating to our receipt of drilling permits and other governmental approvals, shortages or delays in obtaining necessary equipment or services, equipment failures or accidents, adverse weather, environmental hazards, and title problems. As such, our actual drilling activities may differ materially from those presently identified, which could adversely affect our business and reserves.

        Drilling for oil and natural gas may involve unprofitable efforts, not only from dry wells but also from wells that are productive but do not produce sufficient quantities to cover drilling, operating, and other costs. In addition, even a commercial well may have production that is less, or costs that are greater, than we projected. The cost of drilling, completing, and operating a well is often uncertain, and many factors can adversely affect the economics of a well or property. There can be no assurance that proved or unproved property acquired by us or undeveloped acreage leased by us will be profitably developed, that new wells drilled by us in prospects that we pursue will be productive or that we will recover all or any portion of our investment in such proved or unproved property or wells.

We may not be able to obtain adequate financing when the need arises to execute our long-term operating strategy.

        Our ability to execute our long-term operating strategy is highly dependent on our having access to capital when the need arises. We historically have addressed our liquidity needs through credit facilities, issuances of equity and convertible securities, sales of assets, joint ventures, and cash provided by operating activities. We will examine the following alternative sources of capital in light of economic conditions in existence at the relevant time:

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borrowings from banks or other lenders;



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the sale of non-core assets;

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the issuance of debt securities;



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the sale of common stock, preferred stock, or other equity securities;



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joint venture financing; and



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production payments.

        The availability of these sources of capital when the need arises will depend upon a number of factors, some of which are beyond our control. These factors include general economic and financial market conditions, oil and natural gas prices, our credit ratings, interest rates, market perceptions of us or the oil and gas industry, our market value, and our operating performance. We may be unable to execute our long-term operating strategy if we cannot obtain capital from these sources when the need arises, which would adversely affect our production, cash flows, and capital expenditure plans.

Oil and natural gas prices may be affected by local and regional factors.

        The prices to be received for our production will be determined to a significant extent by factors affecting the local and regional supply of and demand for oil and natural gas, including the adequacy of the pipeline and processing infrastructure in the region to process and transport our production and that of other producers. Those factors result in basis differentials between the published indices generally used to establish the price received for regional natural gas production and the actual (frequently lower) price that we receive for our production. Our average differential for the four months ended December 31, 2015 was $(8.17) per barrel for oil and $0.17 per Mcf for gas. These differentials are difficult to predict and may widen or narrow in the future based on market forces. The unpredictability of future differentials makes it more difficult for us to effectively hedge our production. Our hedging arrangements are generally based on benchmark prices and therefore do not protect us from adverse changes in the differential applicable to our production.

Lower oil and natural gas prices and other adverse market conditions may cause us to record ceiling test write-downs or other impairments, which could negatively impact our results of operations.

        We use the full cost method of accounting to account for our oil and natural gas operations. Accordingly, we capitalize the cost to acquire, explore for, and develop oil and natural gas properties. Under full cost accounting rules, the net capitalized costs of oil and natural gas properties may not exceed a "full cost ceiling" which is based upon the present value of estimated future net cash flows from proved reserves, including the effect of hedges in place, discounted at 10%, plus the lower of cost or fair market value of unproved properties. If, at the end of any fiscal period, we determine that the net capitalized costs of oil and natural gas properties exceed the full cost ceiling, we must charge the amount of the excess to earnings in the period then ended. This is called a "ceiling test write-down." This charge does not impact cash flow from operating activities, but does reduce our net income and stockholders' equity. Once incurred, a write-down of oil and natural gas properties is not reversible at a later date.

        We review the net capitalized costs of our properties quarterly, using a single price based on the beginning-of-the-month average of oil and natural gas prices for the preceding 12 months. We also assess investments in unproved properties periodically to determine whether impairment has occurred. The risk that we will be required to further write down the carrying value of our oil and gas properties increases when oil and natural gas prices are low or volatile. In addition, write-downs may occur if we experience substantial downward adjustments to our estimated proved reserves or our unproved property values, or if estimated future development costs increase.

        In preparing our financial statements as of December 31, 2015 and the four months then ended, we expect to use average realized prices of $41.33 per barrel and $2.60 per Mcf in performing the ceiling test calculation. The oil prices to be used at December 31, 2015 are approximately 22% lower

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than the August 31, 2015 price of $53.27 per barrel, and the gas prices are approximately 21% lower than the August 31, 2015 price of $3.28 per Mcf. We compare our net capitalized costs for oil and natural gas properties to the ceiling amount at various points during the year. At May 31, 2015 and August 31, 2015, our net capitalized costs for oil and natural gas properties exceeded the ceiling amount by $3.0 million and $13.0 million, respectively, resulting in a total ceiling test write-down of $16.0 million for the year ended August 31, 2015. At November 30, 2015, our prior fiscal first quarter, our net capitalized costs for oil and natural gas properties exceeded the ceiling amount by $125.2 million, resulting in immediate recognition of a ceiling test impairment of $125.2 million as of that date and for the four months ended December 31, 2015. We also compared our net capitalized costs for oil and natural gas properties to the ceiling amount at November 30, 2014, February 28, 2015, and December 31, 2015, noting that the ceiling amount was greater than our net capitalized costs for oil and natural gas properties. Oil prices continued to decline after December 31, 2015. As of March 31, 2016, the SEC price of oil was lower than the December 31, 2015 SEC oil price. As a result, we anticipate that we will experience further ceiling test write-downs for the quarter ending March 31, 2016, and we may experience further ceiling test write-downs in the future. Any future ceiling test cushion, and the risk we may incur further write-downs or impairments, will be subject to fluctuation as a result of acquisition or divestiture activity. In addition, declining commodity prices or other adverse market conditions, such as declines in the market price of our common stock, could result in goodwill impairments or reductions in proved reserve estimates that would adversely affect our results of operation or financial condition.

We cannot control the activities on properties that we do not operate, and we are unable to ensure the proper operation and profitability of these non-operated properties.

        We do not operate all of the properties in which we have an interest. As a result, we have limited ability to exercise influence over, and control the risks associated with, the operation of these properties. The success and timing of drilling and development activities on our partially owned properties operated by others, therefore, will depend upon a number of factors outside of our control, including the operator's:

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timing and amount of capital expenditures;



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expertise and diligence in adequately performing operations and complying with applicable agreements;



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financial resources;



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inclusion of other participants in drilling wells; and



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use of technology.

        As a result of any of the above or an operator's failure to act in ways that are in our best interest, our allocated production revenues and results of operations could be adversely affected. In addition, our lack of control over non-operated properties makes it more difficult for us to forecast future capital expenditures and production.

We are dependent on third party pipeline, trucking, and rail systems to transport our production and gathering and processing systems to prepare our production. These systems have limited capacity and, at times, have experienced service disruptions. Curtailments, disruptions, or lack of availability in these systems interfere with our ability to market the oil and natural gas that we produce, and could materially and adversely affect our cash flow and results of operations.

        Market conditions or the unavailability of satisfactory oil and natural gas transportation arrangements may hinder our access to oil and natural gas markets or delay our production. The marketability of our oil and natural gas production depends in part on the availability, proximity, and

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capacity of gathering, processing, pipeline, trucking, and rail systems. The amount of oil and natural gas that can be produced and sold is subject to limitation in certain circumstances, such as pipeline interruptions due to scheduled and unscheduled maintenance, accidents, excessive pressure, physical damage to the gathering or transportation system, lack of contracted capacity on such systems, inclement weather, labor or regulatory issues, or other interruptions. A portion of our production may be interrupted, or shut in, from time to time as a result of these factors. Curtailments and disruptions in these systems may last from a few days to several months or longer. These risks are greater for us than for some of our competitors because our operations are focused on areas where there has been a substantial amount of development activity in recent years and resulting increases in production, and this has increased the likelihood that there will be periods of time in which there is insufficient midstream capacity to accommodate the increased production. For example, the gas gathering systems serving the Wattenberg Field have in recent years experienced high line pressures, and at times, this has reduced capacity and caused gas production to either be shut in or flared. In addition, we might voluntarily curtail production in response to market conditions. Any significant curtailment in gathering, processing or pipeline system capacity, significant delay in the construction of necessary facilities, or lack of availability of transport, would interfere with our ability to market the oil and natural gas that we produce, and could materially and adversely affect our cash flow and results of operations and the expected results of our drilling program.

We may be unable to satisfy our contractual obligations, including obligations to deliver oil from our own production or other sources.

        We have entered into agreements that require us to deliver minimum amounts of crude oil to three counterparties that transport crude oil via pipelines. Pursuant to these agreements, we must deliver specific amounts, either from our own production or from oil we acquire, over the next five years. Since October 2015, we have been obligated to deliver a combined volume of 6,157 Bbls of oil per day to two of these counterparties. We have also committed to deliver 5,000 Bbls of oil per day to a third counterparty for five years beginning in the latter half of the 2016 calendar year. If we are unable to fulfill all of our contractual delivery obligations from our own production, we may be required to pay penalties or damages pursuant to these agreements, or we may have to purchase oil from third parties to fulfill our delivery obligations. We incurred such a charge, in the amount of $2.8 million, during the four months ended December 31, 2015. We have also entered into a six-month rig commitment which began in January 2016 that provides for a penalty upon early termination by us. Any future penalties or damages of the type described above could adversely impact our cash flows, profit margins, net income, and reserve values.

We face strong competition from larger oil and natural gas companies that may negatively affect our ability to carry on operations.

        We operate in the highly competitive areas of oil and natural gas exploration, development, and production. Factors that affect our ability to compete successfully in the marketplace include:

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the availability of funds for, and information relating to, properties;



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the standards established by us for the minimum projected return on investment; and



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the transportation of natural gas and crude oil.

        Our competitors include major integrated oil companies, substantial independent energy companies, affiliates of major interstate and intrastate pipelines, and national and local natural gas gatherers, many of which possess greater financial and other resources than we do. If we are unable to successfully compete against our competitors, our business, prospects, financial condition, and results of operations may be adversely affected.

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We may be unable to successfully identify, execute, or effectively integrate future acquisitions, which may negatively affect our results of operations.

        Acquisitions of oil and gas businesses and properties have been an important element of our business, and we will continue to pursue acquisitions in the future. In particular, we are bidding on, or are in discussion with respect to, several possible acquisitions, as described under "Use of Proceeds." Although we regularly engage in discussions with, and submit proposals to, acquisition candidates, suitable acquisitions may not be available in the future on reasonable terms. If we do identify an appropriate acquisition candidate, we may be unable to successfully negotiate the terms of an acquisition, finance the acquisition, or if the acquisition occurs, effectively integrate the acquired business into our existing business. Negotiations of potential acquisitions and the integration of acquired business operations may require a disproportionate amount of management's attention and our resources. Even if we complete additional acquisitions, any new businesses may not generate revenues comparable to our existing business, the anticipated cost efficiencies or synergies may not be realized, and these businesses may not be integrated successfully or operated profitably. The success of any acquisition will depend on a number of factors, including our ability to estimate accurately the recoverable volumes of reserves associated with the acquired assets, rates of future production and future net revenues attainable from the reserves and possible environmental liabilities. Our inability to successfully identify, execute, or effectively integrate future acquisitions may negatively affect our results of operations.

        Even though we perform due diligence reviews (including a review of title and other records) of the major properties that we seek to acquire that we believe is consistent with industry practices, these reviews are inherently incomplete. It is generally not feasible for us to perform an in-depth review of every individual property and all records involved in each acquisition. Moreover, even an in-depth review of records and properties may not necessarily reveal existing or potential liabilities or other problems or permit us to become familiar enough with the properties to assess fully their deficiencies and potential. We may assume known and unknown environmental and other risks and liabilities in connection with the acquired businesses and properties. The discovery of any material liabilities associated with our acquisitions could materially and adversely affect our business, financial condition, and results of operations.

        In addition, acquisitions of businesses, including the several possible acquisitions that we are bidding on and/or in discussions with respect to, may require additional debt or equity financing, resulting in additional leverage or dilution of ownership. Our credit facility contains, and future debt agreements may contain, covenants that limit our ability to complete acquisitions.

We may incur substantial costs to comply with the various federal, state, and local laws and regulations that affect our oil and natural gas operations.

        We are affected significantly by a substantial number of governmental regulations that increase costs related to the drilling, completion, production, and abandonment of wells, the transportation and processing of oil and natural gas, the management and disposal of waste, and other aspects of our operations. It is possible that the number and extent of these regulations, and the costs to comply with them, will increase significantly in the future. In Colorado, for example, significant governmental regulations have been adopted in recent years to address well siting, well construction, hydraulic fracturing, water quality, public safety, air emissions, aesthetics, waste management, spill reporting, land reclamation, wildlife protection, and data collection. These government regulatory requirements may result in substantial costs that are not possible to pass through to our customers and could impact the profitability of our operations.

        Our oil and natural gas operations are subject to stringent federal, state, and local laws and regulations relating to the release or disposal of materials into the environment or otherwise relating to

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health and safety, land use, environmental protection, or the oil and natural gas industry generally. Legislation affecting the industry is under constant review for amendment or expansion, frequently increasing our regulatory burden. Compliance with such laws and regulations often increases our cost of doing business and, in turn, decreases our profitability. Failure to comply with these laws and regulations may result in the assessment of administrative, civil, and criminal penalties, the incurrence of investigatory or remedial obligations, or the issuance of cease and desist orders.

        The environmental laws and regulations to which we are subject may, among other things:

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require us to apply for and receive a permit before drilling commences or certain associated facilities are developed;



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restrict the types, quantities, and concentrations of substances that can be released into the environment in connection with drilling, hydraulic fracturing, and production activities;



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limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other "waters of the United States," threatened and endangered species habitat, and other protected areas;



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require remedial measures to mitigate pollution from former operations, such as plugging abandoned wells; and



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impose substantial liabilities for pollution resulting from our operations.

        Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent or costly waste handling, storage, transport, disposal, or cleanup requirements could require us to make significant expenditures to maintain compliance, and may otherwise have a material adverse effect on our earnings, results of operations, competitive position, or financial condition. Changes to the requirements for drilling, completing, operating, and abandoning wells and related facilities could have similar adverse effects on us.

New environmental legislation or regulatory initiatives, including those related to hydraulic fracturing, could result in increased costs and additional operating restrictions or delays.

        We are subject to extensive federal, state, and local laws and regulations concerning health, safety, and environmental protection. Government authorities frequently add to those requirements, and both oil and gas development generally and hydraulic fracturing specifically are receiving increased regulatory attention. Our operations utilize hydraulic fracturing, an important and commonly used process in the completion of oil and natural gas wells in low-permeability formations. Hydraulic fracturing involves the injection of water, proppant, and chemicals under pressure into rock formations to stimulate hydrocarbon production.

        In 2012, the Environmental Protection Agency ("EPA") issued final rules that establish new air emission controls for natural gas processing operations, as well as for oil and natural gas production. Among other things, the latter rules cover the completion and operation of hydraulically fractured gas wells and associated equipment. After several parties challenged the new air regulations in court, the EPA reconsidered certain requirements and amended the rules in 2013 and 2014. In August 2015, the EPA proposed new regulations that set methane and VOC emission standards for new and modified oil and natural gas production and natural gas processing and transmission facilities as part of an effort to reduce methane emissions from the oil and natural gas sector by up to 45 percent from 2012 levels by 2025. EPA is expected to finalize this proposal in 2016. At this point, we cannot accurately predict the final regulatory requirements or the cost to comply with them. In addition, on March 10, 2016, EPA announced that it will begin a formal process under CAA § 111(d) to require companies operating existing oil and gas sources to provide information to assist EPA in developing comprehensive regulations to reduce methane emissions. EPA will send Information Collection Requests (ICRs) to

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operators to gather information on existing sources of methane emissions, technologies to reduce those emissions, and the costs of those technologies in the production, gathering, processing, and transmission and storage segments of the oil and gas sector. In addition, in October 2015, the EPA lowered the national ambient air quality standard ("NAAQS") for ozone under the CAA from 75 parts per billion to 70 parts per billion. Any resulting expansion of the ozone nonattainment areas in Colorado could cause our oil and natural gas operations in such areas to become subject to more stringent emissions controls, emission offset requirements and increased permitting delays and costs. In addition, the EPA has proposed to "bump up" Colorado from "marginal" to "moderate" ozone non-attainment status for the Denver Metro North Front Range Ozone Nonattainment Area as a result of the area failing to attain the 2008 ozone NAAQS by the applicable attainment date of July 20, 2015. This bump-up in attainment status will trigger additional obligations for the State under the CAA and will result in a state rulemaking to address the new "moderate" status. This rulemaking may result in more stringent standards or additional control requirements applicable to our operations.

        Several governmental reviews are underway assessing the impact of hydraulic fracturing on the environment and human health and safety, including potential adverse effects on drinking water supplies as well as migration of methane and other hydrocarbons. As a result, the federal government is studying the environmental risks associated with hydraulic fracturing and evaluating whether to adopt additional regulatory requirements. For example, the EPA has commenced a multi-year study of the potential impacts of hydraulic fracturing on drinking water resources, and the draft results were released for public and peer review in June 2015. In addition, in February 2014, the EPA issued final guidance for underground injection permits that regulate hydraulic fracturing using diesel fuel, where the EPA has permitting authority under the Safe Drinking Water Act, or SDWA. This guidance eventually could encourage other regulatory authorities to adopt permitting and other restrictions on the use of hydraulic fracturing. In May 2014, the EPA issued an advance notice of proposed rulemaking under the Toxic Substances Control Act to obtain data on chemical substances and mixtures used in hydraulic fracturing. In October 2015, EPA also granted, in part, a petition filed by several national environmental advocacy groups to add the oil and gas extraction industry to the list of industries required to report releases of certain "toxic chemicals" under the Toxics Release Inventory ("TRI") program under EPCRA. EPA determined that natural gas processing facilities may be appropriate for addition to the scope of TRI and will conduct a rulemaking process to propose such action. In April 2015, the EPA proposed regulations under the Clean Water Act to impose pretreatment standards on wastewater discharges associated with hydraulic fracturing activities. Aside from the EPA, the Bureau of Land Management has issued new rules, which are currently stayed pending further litigation, for hydraulic fracturing activities involving federal and tribal lands and minerals that, in general, would cover disclosure of fracturing fluid components, wellbore integrity, and handling of flowback and produced water. On March 26, 2016, the U.S. Occupational Safety and Health Administration ("OSHA") issued a final rule, with effective dates of 2018 and in 2021 for the hydraulic fracturing industry, which imposes stricter standards for worker exposure to silica, including worker exposure to sand in hydraulic fracturing. In addition, OSHA and the National Institute of Occupational Safety and Health have issued hazard alerts to the hydraulic fracturing industry regarding risks to workers from silica exposure and other hazards, which include recommendations to reduce those risks and proposals for additional study of the industry. In December 2015, the U.S. Department of Labor and the U.S. Department of Justice released a Memorandum of Understanding ("MOU"), announcing an interagency effort to increase enforcement of worker endangerment violations under environmental statutes (such as the Clean Water Act, the Clean Air Act, and the Resource Conservation and Recovery Act) and Title 18 criminal statutes that carry harsher penalties that the Occupational Safety and Health Act of 1970. Consistent with this MOU, where appropriate, DOJ will seek felony charges (such as false statements, conspiracy, and obstruction of justice) when prosecuting worker endangerment violations.

        In the United States Congress, bills have been introduced from time to time that would amend the SDWA to eliminate an existing exemption for certain hydraulic fracturing activities from the definition

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of "underground injection," thereby requiring the oil and natural gas industry to obtain SDWA permits for fracturing not involving diesel fuels, and to require disclosure of the chemicals used in the process. If adopted, such legislation could establish an additional level of regulation and permitting at the federal level, but some form of chemical disclosure is already required by most oil and gas producing states. At this time, it is not clear what action, if any, the United States Congress will take on hydraulic fracturing.

        Apart from these ongoing federal initiatives, state governments where we operate have moved to impose stricter requirements on hydraulic fracturing and other aspects of oil and gas production. Colorado, for example, comprehensively updated its oil and gas regulations in 2008 and adopted significant additional amendments in 2011, 2013, 2014 and 2015. Among other things, the updated and amended regulations require operators to reduce methane emissions associated with hydraulic fracturing, compile and report additional information regarding wellbore integrity, satisfy more stringent reclamation and remediation standards, avoid certain wildlife habitat, publicly disclose the chemical ingredients used in hydraulic fracturing, increase the minimum distance between occupied structures and oil and gas wells, undertake additional mitigation for nearby residents, implement additional groundwater testing, and take additional actions to prevent blowouts and avoid subsurface well communication. Colorado has also adopted new regulations for air emissions from oil and gas operations as well as new legislation and implementing regulations increasing the monetary penalties for regulatory violations and lowering the threshold for reporting spills. Additionally, local governments are adopting new requirements on hydraulic fracturing and other oil and gas operations, including local county and city governments in Colorado.

        Colorado currently is conducting a rulemaking addressing local government collaboration with oil and gas operators concerning locations for "Large Scale Oil and Gas Facilities" in Urban Mitigation Areas. The proposed rules would require oil and gas operators that are registered with the state also to register with municipalities in which they operate and, if requested by the municipality, provide certain information about current and planned drilling operations in the municipality.

        In October 2015, the U.S. Department of Transportation Pipeline and Hazardous Materials Safety Administration proposed to expand its regulations in a number of ways, including increased regulation of gathering lines, even in rural areas. The public comment period closed January 8, 2016. In addition, in August 2015, the EPA proposed new regulations to reduce methane emissions from oil and gas operations, including hydraulically fractured wells, in an effort to reduce methane emissions from the oil and gas sector by up to forty-five percent by 2025.

        The trend toward stricter standards and greater enforcement in environmental legislation and regulation is likely to continue. For example, concern has recently arisen in several states over increasing numbers of earthquakes that may be associated with underground injection wells used for the disposal of oil and gas wastewater. Such concerns could eventually limit the use of such wells in certain areas and increase the cost of disposal in others. Similarly, concerns have recently been expressed over the flaring of natural gas associated with crude oil production in certain areas. These concerns and regulations could limit or increase the cost of crude oil production in certain areas. Other environmental issues and concerns may periodically arise in the future and lead to new and additional legislative and regulatory initiatives.

        The adoption of future federal, state, or local laws or implementing regulations or orders imposing new environmental obligations on, or otherwise limiting, our operations could make it more difficult and more expensive to complete oil and natural gas wells, increase our costs of compliance and doing business, delay or prevent the development of certain resources (including especially shale formations that are not commercial without the use of hydraulic fracturing), or alter the demand for and consumption of our products and services. We cannot assure you that any such outcome would not be

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material, and any such outcome could have a material and adverse impact on our cash flows and results of operations.

Any local moratoria or bans on our activities could have a negative impact on our business, financial condition, and results of operations.

        Some local governments are adopting new requirements and restrictions on hydraulic fracturing and other oil and gas operations. Some local governments in Colorado, for instance, have amended their land use regulations to impose new requirements on oil and gas development, while other local governments have entered memoranda of agreement with oil and gas producers to accomplish the same objective. Beyond that, during the past few years, a total of five Colorado cities have passed voter initiatives temporarily or permanently prohibiting hydraulic fracturing. The oil and gas industry and the State of Colorado have challenged four of these initiatives in court, and the trial courts in three of the cases have invalidated the initiatives. In September 2015, the Colorado Supreme Court announced that it would review two of these cases for the purpose of deciding whether local hydraulic fracturing bans are preempted. The Court heard oral argument in December 2015, and a decision is expected in 2016.

        In addition, during 2014, opponents of hydraulic fracturing sought statewide ballot initiatives that would have restricted oil and gas development in Colorado. These initiatives were withdrawn in return for the creation of a task force to craft recommendations for minimizing land use conflicts over the location of oil and gas facilities. Although the task force has completed its work, in December 2015, interest groups filed a package of 11 potential ballot initiatives focused on restricting oil and gas development. Among other things, these initiatives, if successful, could require mandatory setbacks of up to 4,000 feet, more local control over drilling, and prohibitions on drilling. If we are required to cease operating in any of the areas in which we now operate as the result of bans or moratoria on drilling or related oilfield services activities, it could have a material effect on our business, financial condition, and results of operations.

Climate change laws and regulations restricting emissions of greenhouse gases could result in increased operating costs and reduced demand for the oil and natural gas that we produce while potential physical effects of climate change could disrupt our production and cause us to incur significant costs in preparing for or responding to those effects.

        In 2009, the EPA published its findings that emissions of carbon dioxide, methane, and other greenhouse gases ("GHGs") present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the Earth's atmosphere and other climatic conditions. Based on these findings, the EPA has adopted regulations under the CAA that, among other things, establish Prevention of Significant Deterioration ("PSD"), construction and Title V operating permit reviews for GHG emissions from certain large stationary sources that are already major sources of emissions of regulated pollutants. Our operations and those of our customers could become subject to these Title V and PSD permitting reviews and be required to install "best available control technology" to limit emissions of GHGs from any new or significantly modified facilities if such facilities emitted volumes of GHGs in excess of threshold permitting levels. In addition, the EPA has adopted rules requiring the monitoring and annual reporting of GHG emissions from specified GHG emission sources in the United States, including certain onshore oil and natural gas production sources, which include certain of our operations. While Congress has not enacted significant legislation relating to GHG emissions, it may do so in the future, and moreover, several state and regional initiatives have been enacted aimed at monitoring and/or reducing GHG emissions through cap and trade programs.

        The adoption of new laws, regulations, or other requirements limiting or imposing other obligations on GHG emissions from our equipment and operations, and the implementation of requirements that have already been adopted, could require us to incur costs to reduce emissions of

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GHGs associated with our operations, including those regulating methane emissions from the oil and gas industry. See the risk factor above entitled "New environmental legislation or regulatory initiatives, including those related to hydraulic fracturing, could result in increased costs and additional operating restrictions or delays" for further information regarding methane emissions regulations. In addition, substantial limitations on GHG emissions in other sectors, such as the power sector under EPA's August 2015 Clean Power Plan, could adversely affect demand for the oil and natural gas that we produce. Further, GHG regulation may result from the December 2015 agreement reached at the United Nations climate change conference in Paris. Pursuant to the agreement, the United States made an initial pledge to a 26-28% reduction in its GHG emission by 2025 against a 2005 baseline and committed to periodically update its pledge in five yearly intervals starting in 2020. GHG emissions in the earth's atmosphere have also been shown to produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods, and other climatic events, any of which could have an adverse effect on our operations.

Environmental liabilities could have a material adverse effect on our financial condition and operations.

        Our operations could result in liability for personal injuries, property damage, oil spills, discharge of hazardous materials, remediation and clean-up costs, and other environmental damages. We could also be liable for environmental damages caused by previous property owners. As a result, we could incur substantial liabilities to third parties or governmental entities, which could have a material adverse effect on our financial condition and results of operations. We maintain insurance coverage for our operations, but this insurance may not extend to the full potential liability to which we may be subject and further may not cover all potential environmental damages. Accordingly, we may be subject to liability or may lose the ability to continue exploration or production activities upon substantial portions of our properties if certain environmental damages occur.

        For example, over the years, we have owned or leased numerous properties for oil and natural gas activities upon which petroleum hydrocarbons or other materials may have been released by us or by predecessor property owners or lessees who were not under our control. Under applicable environmental laws and regulations, including the Comprehensive Environmental Response, Compensation, and Liability Act, the Resource Conservation and Recovery Act, and state laws, we could be held liable for the removal or remediation of previously released materials or property contamination at such locations, or at third-party locations to which we have sent waste, regardless of whether we were responsible for the release or whether the operations at the time of the release were standard industry practice.

        Similarly, the Oil Pollution Act, or OPA, imposes a variety of regulations on "responsible parties" related to the prevention of oil spills. The implementation of new, or the modification of existing, environmental laws or regulations, including regulations promulgated pursuant to the OPA, could have a material adverse impact on us.

The adoption and implementation of new statutory and regulatory requirements for derivative transactions could have an adverse impact on our ability to hedge risks associated with our business and increase the working capital requirements to conduct these activities.

        The Dodd-Frank Act authorizes federal oversight and regulation of the over-the-counter derivatives market and entities that participate in that market. Regulations under the Dodd-Frank Act may, among other things, require us to comply with margin requirements in connection with our derivative activities. If we are required to post cash collateral in connection with some or all of our derivative positions, this would make it difficult or impossible to pursue our current hedging strategy. The regulations may also require the counterparties to our derivative instruments to spin off some of their derivatives activities to separate entities, which may not be as creditworthy as the current

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counterparties. The regulations may also reduce the number of potential counterparties in the market, which could make hedging more expensive.

        If we reduce our use of derivatives as a result of the Dodd-Frank Act and its implementing regulations, our results of operations may be more volatile, and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Any of these consequences could have a material adverse effect on our financial position, results of operations, and cash flows. In addition, derivative instruments create a risk of financial loss in some circumstances, including when production is less than the volume covered by the instruments.

Proposed changes to U.S. tax laws, if adopted, could have an adverse effect on our business, financial condition, results of operations, and cash flows.

        From time to time, legislative proposals are made that would, if enacted, result in significant changes to U.S. tax laws. These proposed changes have included, among others, eliminating the immediate deduction for intangible drilling and development costs, eliminating the deduction from income for domestic production activities relating to oil and natural gas exploration and development, repealing the percentage depletion allowance for oil and natural gas properties and extending the amortization period for certain geological and geophysical expenditures. Such proposed changes in the U.S. tax laws, if adopted, or other similar changes that reduce or eliminate deductions currently available with respect to oil and natural gas exploration and development, could adversely affect our business, financial condition, results of operations, and cash flows.

Potential indebtedness may adversely affect our cash flow and our ability to operate our business, remain in compliance with debt covenants and make payments on our debt.

        We are currently able to borrow up to $145 million under our credit facility with our primary lenders. Our indebtedness could have important consequences for investors, including the following:

•

the covenants contained in our credit facility limit our ability to borrow money in the future for acquisitions, capital expenditures, or to meet our operating expenses or other general corporate obligations and may limit our flexibility in operating our business;



•

the amount of our interest expense may increase because amounts borrowed under our credit facility bear interest at variable rates, payable either quarterly or at the end of a specified interest period; if interest rates increase, this could result in higher interest expense;



•

we may have a higher level of debt than some of our competitors, which may put us at a competitive disadvantage;



•

we may be more vulnerable to economic downturns and adverse developments in our industry or the economy in general, especially extended or further declines in oil and natural gas prices; and



•

our debt level could limit our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate.

        The lenders under our credit facility have the ability to unilaterally lower the borrowing base. In January 2016, our borrowing base was reduced from $163 million to $145 million. The next semi-annual redetermination is scheduled to occur on May 1, 2016. We may experience further decreases in our borrowing base if oil and natural gas prices stay at current levels or continue to decline. If the lenders reduce the borrowing base below the then-outstanding balance, we will be required to repay the difference between the outstanding balance and the reduced borrowing base, and we may not have or be able to obtain the funds necessary to do so.

        Our ability to meet our expenses and debt obligations will depend on our future performance, which will be affected by financial, business, economic, regulatory, and other factors. We will not be

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able to control many of these factors, such as economic conditions and governmental regulation. We cannot be certain that our cash flow from operations will be sufficient to allow us to pay the principal and interest on our debt and meet our other obligations. If we do not have enough cash to service our debt, we may be required to refinance all or part of our existing debt, sell assets, borrow more money, or raise equity. We may not be able to refinance our debt, sell assets, borrow more money, or raise equity on terms acceptable to us, if at all.

A significant amount of cash may be required to service our indebtedness. Our ability to generate cash depends on many factors beyond our control, and any failure to meet our debt obligations could harm our business, financial condition, and results of operations.

        Our ability to make payments on and to refinance indebtedness we may incur and to fund planned capital expenditures will depend on our ability to generate sufficient cash flow from operations in the future. To a significant extent, this is subject to general economic, financial, competitive, legislative and regulatory conditions, and other factors that are beyond our control, including the prices that we receive for our oil and natural gas production.

        We cannot assure you that our business will generate sufficient cash flow from operations or that future borrowings will be available to us under our credit facility in an amount sufficient to enable us to pay principal and interest on our indebtedness or to fund our other liquidity needs. For example, decreases in oil and gas prices in the recent past, and any further decreases in oil and gas prices, will adversely affect our ability to generate cash flow from operations. If our cash flow and existing capital resources are insufficient to fund our debt obligations, we may be forced to reduce our planned capital expenditures, sell assets, seek additional equity or debt capital, or restructure our debt, and any of these actions, if completed, could adversely affect our business and/or our shareholders. We cannot assure you that any of these remedies could, if necessary, be effected on commercially reasonable terms, in a timely manner or at all. In addition, any failure to make scheduled payments of interest and principal on our outstanding indebtedness could harm our ability to incur additional indebtedness on acceptable terms. Our cash flow and capital resources may be insufficient for payment of interest on and principal of our debt in the future, and any such alternative measures may be unsuccessful or may not permit us to meet scheduled debt service obligations, which could cause us to default on our obligations and could impair our liquidity.

Restrictive debt covenants could limit our growth and our ability to finance our operations, fund our capital needs, respond to changing conditions, and engage in other business activities that may be in our best interests.

        Our credit facility contains, and future debt agreements may contain, covenants that restrict or limit our ability to:

•

pay dividends or distributions on our capital stock or issue preferred stock;



•

repurchase, redeem, or retire our capital stock or subordinated debt;



•

make certain loans and investments;



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sell assets;



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enter into certain transactions with affiliates;



•

create or assume certain liens on our assets;



•

enter into sale and leaseback transactions;



•

merge or to enter into other business combination transactions; or



•

engage in certain other corporate activities.

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        Our credit facility requires us to maintain compliance with specified financial ratios and satisfy certain financial tests. Our ability to comply with these ratios and tests may be affected by events beyond our control, and we cannot assure you that we will meet these ratios and tests in the future. These restrictions could limit our ability to obtain future financings, make needed capital expenditures, withstand a future downturn in our business or the economy in general, or otherwise conduct necessary corporate activities. We may also be prevented from taking advantage of business opportunities that arise because of the restrictive covenants under our credit facility. Future debt agreements may have similar, or more restrictive, provisions.

        A breach of any of the covenants in our debt agreements or our inability to comply with the required ratios or tests could result in a default under the agreement. A default, if not cured or waived, could result in all indebtedness outstanding under the agreement becoming immediately due and payable. If that should occur, we may not be able to pay all such debt or borrow sufficient funds to refinance it. Even if new financing were then available, it may not be on terms that are acceptable to us. If we were unable to repay those amounts, the lenders could accelerate the maturity of the debt or proceed against any collateral granted to them to secure such defaulted debt.

We participate in oil and gas leases with third parties who may not be able to fulfill their commitments to our projects.

        We frequently own less than 100% of the working interest in the oil and gas leases on which we conduct operations, and other parties own the remaining portion of the working interest. Financial risks are inherent in any operation where the cost of drilling, equipping, completing and operating wells is shared by more than one person. We could be held liable for joint activity obligations of other working interest owners, such as nonpayment of costs and liabilities arising from the actions of other working interest owners. In addition, declines in commodity prices may increase the likelihood that some of these working interest owners, particularly those that are smaller and less established, will not be able to fulfill their joint activity obligations. A partner may be unable or unwilling to pay its share of project costs, and, in some cases, a partner may declare bankruptcy. In the event any of our project partners do not pay their share of such costs, we would likely have to pay those costs, and we may be unsuccessful in any efforts to recover these costs from our partners, which could materially adversely affect our financial position.

Our disclosure controls and procedures may not prevent or detect potential acts of fraud.

        Our disclosure controls and procedures are designed to provide reasonable assurance that information required to be disclosed by us in reports we file or submit under the Exchange Act is accumulated and communicated to management, and recorded, processed, summarized, and reported within the time periods specified in the SEC rules and forms.

        Our management, including our Chief Executive Officer and Chief Financial Officer, believes that any disclosure controls and procedures or internal controls and procedures, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, they cannot provide absolute assurance that all control issues and instances of fraud, if any, within our company have been prevented or detected. These inherent limitations include the realities that judgments in decision-making can be faulty, and that breakdowns can occur because of a simple error or mistake. Additionally, controls can be circumvented by the individual acts of some persons, by collusion of two or more people, or by an unauthorized override of the controls. The design of any system of controls also is based in part upon certain assumptions about the likelihood of future events, and we cannot assure you that any design will succeed in achieving its stated goals under all potential future conditions. Accordingly, because of the

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inherent limitations in a cost effective control system, misstatements due to error or fraud may occur and not be detected.

Failure to maintain an effective system of internal control over financial reporting may have an adverse effect on our stock price.

        Pursuant to Section 404 of the Sarbanes-Oxley Act of 2002, and the rules and regulations promulgated by the SEC to implement Section 404, we are required to furnish a report by our management in our annual report on Form 10-K regarding the effectiveness of our internal control over financial reporting. The report includes, among other things, an assessment of the effectiveness of our internal control over financial reporting as of the end of our fiscal year, including a statement as to whether or not our internal control over financial reporting is effective. This assessment must include disclosure of any material weaknesses in our internal control over financial reporting identified by management. If we are unable to assert that our internal control over financial reporting is effective now or in any future period, or if our auditors are unable to express an opinion on the effectiveness of our internal controls, investors could lose confidence in the accuracy and completeness of our financial reports, which could have an adverse effect on our stock price.

Substantially all of our producing properties are located in the D-J Basin in Colorado, making us vulnerable to risks associated with operating in one major geographic area.

        Our operations have been focused on the D-J Basin in Colorado, which means our current producing properties and new drilling opportunities are geographically concentrated in that area. Because our operations are not as diversified geographically as many of our competitors, the success of our operations and our profitability may be disproportionately exposed to the effect of any regional events, including fluctuations in prices of oil and natural gas produced from the wells in the region, natural disasters, restrictive governmental regulations, transportation capacity constraints, weather, curtailment of production, or interruption of transportation and processing services, and any resulting delays or interruptions of production from existing or planned new wells.

The inability of one or more of our customers to meet their obligations may adversely affect our financial results.

        Substantially all of our accounts receivable result from oil and natural gas sales or joint interest billings to third parties in the energy industry. We sell production to a small number of customers, as is customary in the industry. For the four months ended December 31, 2015, we had three major customers, which represented 57%, 15%, and 12% of our estimated revenue during the period. This concentration of customers and joint interest owners may impact our overall credit risk in that these entities may be similarly affected by changes in economic and other conditions. In addition, our oil and natural gas hedging arrangements expose us to credit risk in the event of nonperformance by counterparties.

Failure to adequately protect critical data and technology systems could materially affect our operations.

        Information technology solution failures, network disruptions, and breaches of data security could disrupt our operations by causing delays or cancellation of customer orders, impeding processing of transactions and reporting financial results, resulting in the unintentional disclosure of customer, employee, or other information, or damage to our reputation. A system failure or data security breach may have a material adverse effect on our financial condition, results of operations, or cash flows.

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Our operations are substantially dependent on the availability of water. Restrictions on our ability to obtain water may have a material adverse effect on our financial condition, results of operations, and cash flows.

        Water is an essential component of shale oil and natural gas production during both the drilling and hydraulic fracturing processes. Historically, we have been able to purchase water from local land owners for use in our operations. When drought conditions occur, governmental authorities may restrict the use of water subject to their jurisdiction for hydraulic fracturing to protect local water supplies. If we are unable to obtain water to use in our operations from local sources, we may be unable to produce oil, natural gas, and NGLs economically, which could have a material adverse effect on our financial condition, results of operations, and cash flows.

Our undeveloped acreage must be drilled before lease expiration to hold the acreage by production. In highly competitive markets for acreage, failure to drill sufficient wells to hold acreage could result in a substantial lease renewal cost, or if renewal is not feasible, loss of our lease and prospective drilling opportunities.

        Unless production is established within the spacing units covering the undeveloped acres on which some of our drilling locations are identified, our leases for such acreage will expire. The cost to renew such leases may increase significantly, and we may not be able to renew such leases on commercially reasonable terms or at all. As such, our actual drilling activities may differ materially from our current expectations, which could materially and adversely affect our business. The risk of lease expiration typically increases at times when commodity prices are depressed, as the pace of our exploration and development activity tends to slow during such periods.

We may incur losses as a result of title defects in the properties in which we invest.

        It is our practice in acquiring oil and gas leases or interests not to incur the expense of retaining lawyers to examine the title to the mineral interest at the time of acquisition. Rather, we rely upon the judgment of oil and gas lease brokers or landmen who perform the fieldwork in examining records in the appropriate governmental office before attempting to acquire a lease in a specific mineral interest. The existence of a material title deficiency can render a lease worthless and can adversely affect our results of operations and financial condition. While we typically obtain title opinions prior to commencing drilling operations on a lease or in a unit, the failure of title may not be discovered until after a well is drilled, in which case we may lose the lease and the right to produce all or a portion of the minerals under the property.

Part of our strategy involves drilling using the latest available horizontal drilling and completion techniques, which involve risks and uncertainties in their application.

        Our operations involve utilizing the latest drilling and completion techniques as developed by us and our service providers. As of December 31, 2015, we operated 86 gross horizontal producing wells, with an additional 18 horizontal wells waiting on completion, and therefore are subject to increased risks associated with horizontal drilling as compared to companies that have greater experience in horizontal drilling activities. Risks that we face while drilling include, but are not limited to, failing to land our wellbore in the desired drilling zone, not staying in the desired drilling zone while drilling horizontally through the formation, not running our casing the entire length of the wellbore, and not being able to run tools and other equipment consistently through the horizontal wellbore. Risks that we face while completing our wells include, but are not limited to, not being able to fracture stimulate the planned number of stages, not being able to run tools the entire length of the wellbore during completion operations, and not successfully cleaning out the wellbore after completion of the final fracture stimulation stage. In addition, our horizontal drilling activities may adversely affect our ability to successfully drill in one or more of our identified vertical drilling locations. Ultimately, the success of these drilling and completion techniques can only be evaluated over time as more wells are drilled and production profiles are established over a sufficiently long time period. If our drilling results are less

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than anticipated or we are unable to execute our drilling program because of capital constraints, lease expirations, access to gathering systems, and/or commodity prices decline, the return on our investment in these areas may not be as attractive as we anticipate. Further, as a result of any of these developments, we could incur material write-downs of our oil and natural gas properties, and the value of our undeveloped acreage could decline in the future.

Risks Relating to our Common Stock

We do not intend to pay dividends on our common stock, and our ability to pay dividends on our common stock is restricted.

        Since inception, we have not paid any cash dividends on common stock. Cash dividends are restricted under the terms of our credit facility, and we presently intend to continue the policy of using retained earnings for expansion of our business. Any future dividends also may be restricted by future agreements. Because we have no plans to pay dividends on our common stock, investors must look solely to stock appreciation for a return on their investment in us.

The price of our stock price has been and may continue to be highly volatile, which may make it difficult for shareholders to sell our common stock when desired or at attractive prices.

        The market price of our common stock is highly volatile, and we expect it to continue to be volatile for the foreseeable future. Adverse events, including, among others:

•

changes in production volumes, worldwide demand and prices for crude oil and natural gas;



•

changes in market prices of crude oil and natural gas;



•

changes in securities analysts' estimates of our financial performance;



•

fluctuations in stock market prices and volumes, particularly among securities of energy companies;



•

changes in market valuations of similar companies;



•

changes in interest rates;



•

announcements regarding adverse timing or lack of success in discovering, acquiring, developing and producing crude oil and natural gas resources;



•

announcements by us or our competitors of significant contracts, new acquisitions, discoveries, commercial relationships, joint ventures, or capital commitments;



•

decreases in the amount of capital available to us;



•

operating results that fall below market expectations or variations in our quarterly operating results;



•

loss of a major customer;



•

loss of a relationship with a partner;



•

the identification of and severity of environmental events and governmental and other third-party responses to the events; or



•

additions or departures of key personnel,

could trigger significant declines in the price of our common stock. For example, the market price of our common stock has been adversely affected by the recent declines in commodity prices. In addition, external events, such as news concerning economic conditions, counterparties to our natural gas or oil derivatives arrangements, changes in government regulations impacting the oil and natural gas

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exploration and production industries, or the movement of capital into or out of our industry, also are likely to affect the price of our common stock, regardless of our operating performance. Furthermore, general market conditions, including the level of, and fluctuations in, the trading prices of stocks generally could affect the price of our common stock. Recently, the stock markets have experienced price and volume volatility that has affected many companies' stock prices. Stock prices for many companies have experienced wide fluctuations that have often been unrelated to the operating performance of those companies. These fluctuations may affect the market price of our common stock.

Investors in this offering may experience future dilution.

        In order to raise additional capital, effect acquisitions, or for other purposes, we may in the future offer additional shares of our common stock or other securities convertible into, or exchangeable for, our common stock at prices that may not be the same as the price per share of this offering. We have an effective shelf registration statement from which additional shares of common stock and other securities can be offered. We cannot assure you that we will be able to sell shares or other securities in any other offering at a price per share that is equal to or greater than the price per share paid by investors in this offering. If the price per share at which we sell additional shares of our common stock or related securities in future transactions is less than the price per share in this offering, investors who purchase our common stock in this offering will suffer a dilution of their investment.

Sales of a significant number of shares of our common stock in the public markets, or the perception that such sales could occur, could depress the market price of our common stock.

        Sales of a substantial number of shares of our common stock could depress the market price of our common stock, and impair our ability to raise capital through the sale of additional equity securities. We, our directors and our executive officers have agreed not to dispose of or hedge any common stock or securities convertible into or exchangeable for shares of common stock during the period from the date of this prospectus supplement continuing through the date 45 days after the date of this prospectus supplement, subject to certain exceptions. The underwriters may release the restrictions on any such shares at any time without notice. We cannot predict the effect that future sales of our common stock or perceptions of such sales following the expiration of the 45-day period referred to above would have on the market price of our common stock.

Equity compensation plans may cause a future dilution of our common stock.

        To the extent options to purchase common stock under our equity incentive plans are exercised, or shares of restricted stock or other equity awards are issued based on satisfaction of vesting requirements, holders of our common stock will experience dilution.

        As of December 31, 2015, there were 10,065,067 shares reserved for issuance under our equity compensation plans, of which 915,867 restricted shares have been granted and are subject to issuance in the future based on the satisfaction of certain vesting criteria established pursuant to the respective awards and 5,056,000 of which are issuable upon the exercise of outstanding options to purchase common stock. Our outstanding options have a weighted average exercise price of $9.71 per share.

Non-U.S. holders of our common stock, in certain situations, could be subject to U.S. federal income tax upon sale, exchange or disposition of our common stock.

        It is likely that we are, and will remain for the foreseeable future, a U.S. real property holding corporation for U.S. federal income tax purposes because our assets consist primarily of "United States real property interests" as defined in the applicable Treasury regulations. As a result, under the Foreign Investment in Real Property Tax Act, or FIRPTA, certain non-U.S. investors may be subject to U.S. federal income tax on gain from the disposition of shares of our common stock, in which case they

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would also be required to file U.S. tax returns with respect to such gain, and may be subject to a withholding tax. In general, whether these FIRPTA provisions apply depends on the amount of our common stock that such non-U.S. investors hold and whether, at the time they dispose of their shares, our common stock is regularly traded on an established securities market within the meaning of the applicable Treasury regulations. So long as our common stock continues to be regularly traded on an established securities market, only a non-U.S. investor who has owned, actually or constructively, more than 5% of our common stock at any time during the shorter of (i) the five-year period ending on the date of disposition and (ii) the non-U.S. investor's holding period for its shares may be subject to U.S. federal income tax on the disposition of our common stock under FIRPTA. See "Material United States Federal Income Tax Considerations to Non-U.S. Holders."

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RISK FACTORS

        An investment in our securities involves a high degree of risk. You should carefully consider the risk factors and all of the other information included in, or incorporated by reference into, this prospectus, including those risk factors included in our Annual Report on Form 10-K for the year ended August 31, 2014 and in our Quarterly Reports on Form 10-Q for the quarterly periods ended November 30, 2014, February 28, 2015, and May 31, 2015, and in our subsequent Commission filings, in evaluating an investment in our securities. If any of these risks were to occur, our business, financial condition or results of operations could be adversely affected. In that case, the trading price of our common stock could decline and you could lose all or part of your investment. When any securities are offered and sold pursuant to a prospectus supplement, we may include additional risk factors relevant to such securities in the prospectus supplement.

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