CRBO Carbon Energy Corporation (CE)

RISK FACTORS

Investing in our common stock involves a high degree of risk. You should carefully consider the risks described below with all of the other information included in this prospectus before deciding to invest in our common stock. If any of the following risks actually occur, they may materially and adversely affect our business, financial condition, cash flows, and results of operations. In this event, we might have to decrease, or may not be able to pay, dividends on our common stock, the trading price of our common stock could decline, and you could lose part or all of your investment. We may experience additional risks and uncertainties not currently known to us; or, as a result of developments occurring in the future, conditions that we currently deem to be immaterial may also materially and adversely affect our business, financial condition, cash flows, and results of operations.

Risks Related to Our Business

Oil, NGL and natural gas prices and differentials are highly volatile. Declines in commodity prices, especially steep declines in the price of oil, have adversely affected, and in the future will adversely affect, our financial condition and results of operations, cash flow, access to the capital markets and ability to grow.

The oil, NGL and natural gas markets are highly volatile, and we cannot predict future oil, NGL and natural gas prices. Prices for oil, NGL and natural gas may fluctuate widely in response to relatively minor changes in the supply of and demand for oil, NGLs and natural gas, market uncertainty and a variety of additional factors that are beyond our control, such as:

Oil, NGL and natural gas prices do not necessarily fluctuate in direct relationship to each other. On a pro forma basis after giving effect to the Pro Forma Adjustments, our oil, NGL and natural gas accounted for approximately 14.3%, 1.9% and 83.8% of our estimated proved reserves as of December 31, 2017, respectively, and approximately 8.4%, 0.9% and 90.7% of our 2017 production on an Mcfe basis, respectively. Accordingly, our financial results will be sensitive to movements in oil, NGL and natural gas prices.

In the past, prices of oil and natural gas have been extremely volatile, and we expect this volatility to continue. For example, during the year ended December 31, 2017, the monthly average NYMEX WTI spot price ranged from a high of $61 per Bbl in December to a low of $46 per Bbl in June while the monthly average Henry Hub natural gas price ranged from a high of $3.30 per MMBtu in January to a low of $2.81 per MMBtu in December. During the year ended December 31, 2016, the monthly average NYMEX WTI spot price ranged from a high of $52 per Bbl in December to a low of $30 per Bbl in February while the monthly average Henry Hub natural gas price ranged from a high of $3.59 per MMBtu in December to a low of $1.73 per MMBtu in March. For April 2018, the NYMEX WTI spot price averaged $62.89 per Bbl and the natural gas spot price at Henry Hub averaged approximately $3.08 per MMBtu. Price discounts or differentials between NYMEX WTI spot prices and what we actually receive are also historically very volatile. 

In addition, the market price for natural gas in the Appalachian Basin continues to be lower relative to NYMEX Henry Hub as a result of the significant increases in the supply of natural gas in the Northeast region in recent years. Due to the volatility of commodity prices, we are unable to predict future potential movements in the market prices for natural gas, including Appalachian and other market point basis, NGLs and oil and thus cannot predict the ultimate impact of prices on our operations.

Our revenue, profitability and cash flow depend upon the prices and demand for oil, NGLs and natural gas. A drop in prices similar to those observed in recent years would significantly affect our financial results and impede our growth. In particular, a significant or prolonged decline in oil, NGL or natural gas prices or a lack of related storage will negatively impact:

Historically, higher oil, NGL and natural gas prices generally stimulate increased demand and result in increased prices for drilling equipment, crews and associated supplies, equipment and services, as well as higher lease operating expenses and increased end-user conservation or conversion to alternative fuels. However, commodity price declines do not result in similarly rapid declines of costs associated with drilling. Accordingly, a high cost environment could adversely affect our ability to pursue our drilling program and our results of operations.

The refining industry may be unable to absorb rising U.S. oil and condensate production; in such a case, the resulting surplus could depress prices and restrict the availability of markets, which could materially and adversely affect our results of operations.

Absent an expansion of U.S. refining and export capacity, rising U.S. production of oil and condensates could result in a surplus of these products in the U.S., which would likely cause prices for these commodities to fall and markets to constrict. Although U.S. law was changed in 2015 to permit the export of oil, exports may not occur if demand is lacking in foreign markets or the price that can be obtained in foreign markets does not support associated export capacity expansions, transportation and other costs. In such circumstances, the returns on our capital projects would decline, possibly to levels that would make execution of our drilling plans uneconomical, and a lack of market for our products could require that we shut in some portion of our production. If this were to occur, our production and cash flow could decrease, or could increase less than forecasted, which could have a material adverse effect on our cash flow and profitability.

We are a holding company with no oil and gas operations of our own, and we depend on subsidiaries for cash to fund all of our operations and expenses.

Our operations are conducted entirely through subsidiaries, and our ability to generate cash to meet our debt service obligations is dependent on the earnings and the receipt of funds from our subsidiaries through distributions or intercompany loans. Our subsidiaries’ ability to generate adequate cash depends on a number of factors, including development of reserves, successful acquisitions of complementary properties, advantageous drilling conditions, oil and natural gas prices, compliance with all applicable laws and regulations and other factors.

We do not solely control certain subsidiaries.

We have no significant assets other than our ownership interest in entities that own and operate oil and natural gas and oil interests. We do not fully own, and in many cases do not solely control, such entities. More specifically:

Our level of indebtedness may increase and reduce our financial flexibility.

We have a $100.0 million bank credit facility with LegacyTexas Bank with a current borrowing base of $25.0 million, the outstanding balance of which was approximately $23.2 million at March 31, 2018. In addition, Carbon Appalachia Enterprises, LLC, a Delaware limited liability company and indirect subsidiary of Carbon Appalachia (“ Carbon Appalachia Enterprises ”), has a 4-year $100.0 million senior secured asset-based revolving credit facility with LegacyTexas Bank (the “ CAE Credit Facility ”), which has been used to partially fund each of Carbon Appalachia’s acquisitions. The current borrowing base under the CAE Credit Facility is $70.0 million. We are not a guarantor of the CAE Credit Facility. As of March 31, 2018, there was approximately $38.0 million outstanding under the CAE Credit Facility. We are currently in discussions with LegacyTexas Bank to replace our existing credit facility and the CAE Credit Facility with the New Revolving Credit Facility. Entry into the New Revolving Credit Facility will be conditioned upon, among other things, the completion of this offering.

In addition, Carbon California sold certain Senior Secured Revolving Notes to Prudential Legacy Insurance Company of New Jersey and Prudential Insurance Company of America with a revolving borrowing capacity of $41.0 million, of which $13.0 million was outstanding as of March 31, 2018. We are not a guarantor of the Senior Secured Revolving Notes.

We, Carbon Appalachia and Carbon California may incur significant additional indebtedness in the future in order to make acquisitions or to develop our properties.

Our level of indebtedness could affect our operations in several ways, including the following:

A high level of indebtedness increases the risk that we may default on our debt obligations. Our ability to meet our debt obligations and to reduce our level of indebtedness depends on our future performance. General economic conditions, commodity prices, and financial, business, and other factors affect our operations and our future performance. Many of these factors are beyond our control. We may not be able to generate sufficient cash flows to pay the interest on our debt and future working capital, borrowings, or equity financing may not be available to pay or refinance such debt. Factors that will affect our ability to raise cash through an offering of our capital stock or a refinancing of our debt include financial market conditions, the value of our assets, and our performance at the time we need capital.

We may not be able to generate enough cash flow to meet our debt obligations or fund our other liquidity needs.

At March 31, 2018, our debt consisted of approximately $23.2 million in borrowings under our current $25.0 million borrowing base under our credit facility, approximately $13.0 million outstanding under Carbon California’s Senior Revolving Notes due 2022 and approximately $10.0 million outstanding under Carbon California’s Subordinated Notes due 2024. In addition to interest expense and principal on our long-term debt and the $750,000 minimum liquidity requirement under our credit agreement, we have demands on our cash resources including, among others, operating expenses and capital expenditures.

Our ability to pay the principal and interest on our long-term debt and to satisfy our other liabilities will depend upon future performance and our ability to repay or refinance our debt as it becomes due. Our future operating performance and ability to refinance will be affected by economic and capital market conditions, results of operations and other factors, many of which are beyond our control. Our ability to meet our debt service obligations also may be impacted by changes in prevailing interest rates, as borrowing under our existing credit facility bears interest at floating rates.

We may not generate sufficient cash flow from operations. Without sufficient cash flow, there may not be adequate future sources of capital to enable us to service our indebtedness or to fund our other liquidity needs. If we are unable to service our indebtedness and fund our operating costs, we will be required to adopt alternative strategies that may include:

We may not be able to complete such alternative strategies on satisfactory terms, if at all. Our inability to generate sufficient cash flows to satisfy our debt obligations and fund our liquidity needs, or to refinance our indebtedness on commercially reasonable terms, would materially and adversely affect our financial condition and results of operations and may reduce our ability to pay dividends on our common stock. The formation of joint ventures or other similar arrangements to finance operations may result in dilution of our interest in the properties affected by such arrangements.

A deterioration in general economic, business or industry conditions would materially adversely affect our results of operations, financial condition and ability to pay dividends on our common stock.

In recent years, concerns over global economic conditions, energy costs, geopolitical issues, inflation, the availability and cost of credit, and slow economic growth in the United States have contributed to economic uncertainty and diminished expectations for the global economy. Meanwhile, continued hostilities in the Middle East and the occurrence or threat of terrorist attacks in the United States or other countries could adversely affect the economies of the United States and other countries. Concerns about global economic growth have had a significant adverse impact on global financial markets and commodity prices. An oversupply of crude oil in 2015 led to a severe decline in worldwide oil prices. If the economic climate in the United States or abroad deteriorates, worldwide demand for petroleum products could materially decrease, which could impact the price at which oil, natural gas and natural gas liquids from our properties are sold, affect the ability of vendors, suppliers and customers associated with our properties to continue operations and ultimately materially adversely impact our results of operations, financial condition and ability to pay dividends on our common stock.

We have made several significant acquisitions in recent years, and our proportionate interests in our equity investees have recently increased or is expected to increase upon the closing of this offering.  As a result, our historical reserve, operating and financial data are not comparable from period to period or to the unaudited pro forma reserve, operating financial information included in this prospectus, which may make it more difficult for you to evaluate our business or our ability to pay dividends.

Consistent with our acquisition strategy, we, together with Carbon Appalachia and Carbon California, have completed seven significant acquisitions since October 2016.  Additionally, our proportionate interest in Carbon California increased during 2018 from 17.81% to 53.92%.  This resulted in a change from treating Carbon California as an equity method investment to consolidating Carbon California’s results into our results beginning with the first quarter of 2018.  Further, if the Old Ironsides Buyout is completed at the closing of this offering, our proportionate interest in Carbon Appalachia will increase from 27.24% to 100%, and Carbon Appalachia’s results will be consolidated into our results.

As a result of the execution of our acquisition strategy and the increase in interests in Carbon Appalachia and Carbon California, the historical reserve, operating and financial data included in this prospectus are not comparable (i) from period to period or (ii) to the reserve, operating or financial data presented in this prospectus on a pro forma basis.  For example, as of and for the years ended December 31, 2016 and 2017 on a historical basis and for the year ended December 31, 2017 on a pro forma basis, our total revenue was $8.2 million, $22.4 million, and $117.4 million, respectively, our total assets were $42.7 million, $60.0 million and $297.2 million, respectively and our total liabilities were $33.7 million, $43.5 million, and $177.8 million, respectively.  Our total proved reserves (excluding non-controlling interests) as of December 31, 2017 were 189.4 Bcfe on a historical basis and 517.8 Bcfe on a pro forma basis. As a result, the utility of historical reserve, operating and financial data included in this prospectus may be limited, and thus you may find it difficult to evaluate our business and results of operations to date and to assess our future prospects and ability to pay dividends.

The agreements governing our indebtedness contain restrictive covenants that may limit our ability to respond to changes in market conditions or pursue business opportunities.

Our credit agreement contains restrictive covenants that limit our ability to, among other things:

In addition, our credit agreement requires us to maintain certain financial ratios and tests. The requirement that we comply with these provisions may materially adversely affect our ability to react to changes in market conditions, take advantage of business opportunities we believe to be desirable, obtain future financing, fund needed capital expenditures, or withstand a continuing or future downturn in our business. We expect the New Revolving Credit Facility to have similar restrictive covenants, financial ratios and tests as described above.

If we are unable to comply with the restrictions and covenants in our credit agreement, there could be an event of default under the terms of such agreement, which could result in an acceleration of repayment.

If we are unable to comply with the restrictions and covenants in our credit agreement, there could be an event of default. Our ability to comply with these restrictions and covenants, including meeting the financial ratios and tests, may be affected by events beyond our control. As a result, we cannot assure that we will be able to comply with these restrictions and covenants or meet such financial ratios and tests. In the event of a default under our credit agreement, the lenders could terminate their commitments to lend or accelerate the loans and declare all amounts borrowed due and payable. If any of these events occur, our assets might not be sufficient to repay in full all of our outstanding indebtedness and we may be unable to find alternative financing. Even if we could obtain alternative financing, it might not be on terms that are favorable or acceptable to us. Additionally, we may not be able to amend our credit agreement or obtain needed waivers on satisfactory terms.

Our borrowings under our credit agreement and the Carbon California Senior Revolving Notes expose us to interest rate risk.

Our results of operations are exposed to interest rate risk associated with borrowings under our credit agreement, which bear interest at a rate elected by us that is based on the prime, LIBOR, or federal funds rate plus margins ranging from 0.50% to 4.50% depending on the type of loan used and the amount of the loan outstanding in relation to the borrowing base. As of March 31, 2018, there was approximately $23.2 million outstanding under our credit agreement. In addition, interest on borrowings under the Carbon California Senior Revolving Notes is payable quarterly and accrues at a rate per annum equal to either (i) the prime rate plus an applicable margin of 4.00% or (ii) the LIBOR rate plus an applicable margin of 5.00% at our option. As of March 31, 2018, there was approximately $13.0 million outstanding under the Carbon California Senior Revolving Notes. If interest rates increase, so will our interest costs, which may have a material adverse effect on our results of operations and financial condition.

Any significant reduction in our borrowing base under our credit agreement or the Carbon California Senior Revolving Notes as a result of the periodic borrowing base redeterminations or otherwise may negatively impact our ability to fund our operations.

Under (i) our credit agreement, which as of March 31, 2018 provides for a $25.0 million borrowing base and (ii) the Carbon California Senior Revolving Notes, which as of May 1, 2018 provide for a $41.0 million borrowing base, we are subject to collateral borrowing base redeterminations based on our proved reserves. We expect the New Revolving Credit Facility will also be subject to periodic borrowing base redeterminations. Declines in oil and natural gas prices have in the past adversely impacted the value of our estimated proved developed reserves and, in turn, the market values used by our lenders to determine our borrowing base. Any significant reduction in our borrowing base as a result of such borrowing base redeterminations or otherwise may negatively impact our liquidity and our ability to fund our operations and, as a result, may have a material adverse effect on our financial condition, results of operations, and cash flows.

Our estimates of proved reserves at December 31, 2017 and 2016 have been prepared under SEC rules which could limit our ability to book additional proved undeveloped reserves in the future.

Estimates of our proved reserves as of December 31, 2017 and 2016 have been prepared and presented under the SEC’s rules relating to the reporting of oil and natural gas exploration activities. These rules require that, subject to limited exceptions, proved undeveloped reserves may only be booked if they relate to wells scheduled to be drilled within five years of the date of booking. This rule has limited and may continue to limit our potential to book additional proved undeveloped reserves. Moreover, we may be required to write down any proved undeveloped reserves that are not developed within the required five-year timeframe. In addition, we based the discounted future net cash flows from our proved reserves on the twelve month unweighted arithmetic average of the first-day-of-the-month price for the preceding twelve months without giving effect to derivative transactions. Actual future net cash flows from our properties will be affected by factors such as the actual prices we receive for oil, NGLs and natural gas, the amount, timing and cost of actual production and changes in governmental regulations or taxation.

Neither the estimated quantities of proved reserves nor the discounted present value of future net cash flows attributable to those reserves included in this prospectus are intended to represent their fair, or current, market value.

Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our proved reserves.

Oil and natural gas reserve engineering is not an exact science and requires subjective estimates of underground accumulations of reserves and assumptions concerning future commodity prices, production levels, estimated ultimate recoveries, and operating and development costs. As a result, estimated quantities of proved reserves, projections of future production rates, and the timing of development expenditures may be incorrect. Our, Carbon Appalachia’s and Carbon California’s estimates of proved reserves and related valuations as of December 31, 2017 and 2016 are based on proved reserve reports prepared by CGA, an independent engineering firm. CGA conducted a well-by-well review of all our, Carbon Appalachia’s and Carbon California’s properties for the periods covered by its proved reserve reports using information provided by us, Carbon Appalachia or Carbon California. Over time, we may make material changes to proved reserve estimates taking into account the results of actual drilling, testing, and production. Also, certain assumptions regarding future commodity prices, production levels, and operating and development costs may prove incorrect. Any significant variance from these assumptions to actual figures could greatly affect our estimates of proved reserves, the economically recoverable quantities of reserves attributable to any particular group of properties, the classifications of reserves based on risk of recovery, and estimates of the future net cash flows. Numerous changes over time to the assumptions on which our reserve estimates are based, as described above, often result in the actual quantities of reserves we ultimately recover being different from our estimates.

The estimates of proved reserves as of December 31, 2017 and 2016 included in this registration statement were prepared using an average price equal to the unweighted arithmetic average of hydrocarbon prices received on a field-by-field basis on the first day of each month within the 12 months ended December 31, 2017 and 2016, respectively, in accordance with the SEC guidelines applicable to reserve estimates for these periods. Reserve estimates do not include any value for probable or possible reserves that may exist, nor do they include any value for unproved acreage. The reserve estimates represent our, Carbon Appalachia’s and Carbon California’s net revenue interest in such properties.

The present value of future net cash flows from estimated proved reserves is not necessarily the same as the current market value of estimated proved oil and natural gas reserves. We, Carbon Appalachia and Carbon California base the current market value of estimated proved reserves on prices and costs in effect on the day of the estimate. However, actual future net cash flows from our oil and natural gas properties also will be affected by factors such as:

The timing of our production and incurrence of expenses in connection with the development and production of oil and natural gas properties will affect the timing of actual future net cash flows from proved reserves and thus their actual present value.  In addition, the 10% discount factor we use when calculating discounted future net cash flows in compliance with GAAP may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and gas industry in general.

Lower oil and natural gas prices and other factors have resulted in, and in the future may result in, ceiling test write-downs and other impairments of our asset carrying values.

We use the full cost method of accounting to report our oil and natural gas operations. Under this method, we capitalize the cost to acquire, explore for, and develop oil and natural gas properties, including capitalizing the costs of abandoned properties, dry holes, geophysical costs, and annual lease rentals. All general and administrative corporate costs unrelated to drilling activities are expensed as incurred. Sales or other dispositions of oil and natural gas properties are accounted for as adjustments to capitalized costs, with no gain or loss recorded unless the ratio of cost to proved reserves would significantly change. Depletion of evaluated oil and natural gas properties is computed on the units of production method based on proved reserves. The average depletion rate per Mcfe of production associated with our reserves was $0.76 for the three months ended March 31, 2018. Total depletion expense for oil and natural gas properties was approximately $1.3 million for the three months ended March 31, 2018.

Under full cost accounting rules, the net capitalized costs of proved oil and natural gas properties may not exceed a “ceiling limit,” which is based upon the present value of estimated future net cash flows from proved reserves, discounted at 10%. If net capitalized costs of proved oil and natural gas properties exceed the ceiling limit, we must charge the amount of the excess to earnings. This is called a “ceiling test write-down.” Under GAAP, we are required to perform a ceiling test each quarter. Because the ceiling calculation requires a rolling 12-month average commodity price, due to the effect of lower prices in 2016, we recognized an impairment of approximately $4.3 million for the year ended December 31, 2016. We did not recognize an impairment for the year ended December 31, 2017 or for the three months ended March 31, 2018. Impairment charges do not affect cash flows from operating activities, but do adversely affect earnings and stockholders’ equity.

Investments in unproved properties are assessed periodically to ascertain whether impairment has occurred. Unproved properties whose costs are individually significant are assessed individually by considering the primary lease terms of the properties, the holding period of the properties, and geographic and geologic data relating to the properties. The amount of impairment assessed, if any, is added to the costs to be amortized in the appropriate full cost pool. If an impairment of unproved properties results in a reclassification to proved reserves, the amount by which the ceiling limit exceeds the capitalized costs of proved reserves would be reduced.

In addition, GAAP requires us to write down, as a non-cash charge to earnings, the carrying value of our oil and natural gas properties for impairments, which 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. We are required to perform impairment tests on our assets periodically and whenever events or changes in circumstances warrant a review of our assets. To the extent such tests indicate a reduction of the estimated useful life or estimated future cash flows of our assets, the carrying value may not be recoverable and therefore requires a write-down. Future write-downs of our full cost pool may be required if oil and natural gas prices decline, unproved property values decrease, estimated proved reserve volumes are revised downward or costs incurred in exploration, development, or acquisition activities in our full cost pool exceed the discounted future net cash flows from the additional reserves, if any, attributable to our cost pool. Any recorded impairment is not reversible at a later date.

Our exploration and development projects and acquisitions require substantial capital expenditures. We may be unable to obtain required capital or financing on satisfactory terms, which could lead to a decline in our reserves.

The oil and natural gas industry is capital intensive. We make and expect to continue to make substantial capital expenditures for the development, exploitation, production and acquisition of oil and natural gas reserves. Our cash used in investing activities related to acquisition, development and exploration expenditures (not including Carbon Appalachia and Carbon California) was approximately $474,000 and $1.6 million for the three months ended March 31, 2018 and the year ended December 31, 2017, respectively. Carbon Appalachia’s cash used in investing activities related to acquisition, development and exploration expenditures was approximately $302,000 and $74.2 million for the three months ended March 31, 2018 and the period ended December 31, 2017, respectively. Carbon California’s cash used in investing activities related to acquisition, development and exploration expenditures was approximately $400,000 and $42.2 million for the three months ended March 31, 2018 and the period ended December 31, 2017, respectively. We contribute our proportionate share, as a holder of Class A units that require capital contributions, of the capital expenditure obligations of Carbon Appalachia and Carbon California.

We anticipate that the budget for exploration and development work on existing acreage will range between $0.5 million and $2.5 million for us in 2018, between $0 million and $2.0 million for Carbon Appalachia in 2018, and between $3.0 million and $5.0 million for Carbon California in 2018. The budget will be highly dependent on prices that we receive for our oil and natural gas sales. We intend to finance future capital expenditures through cash on hand, cash flow from operations, and from borrowings under bank credit facilities. Our cash flows from operations and access to capital are subject to a number of variables, including:

However, our financing needs, especially in regard to potential acquisitions, may exceed those resources, and our actual capital expenditures in 2018 could exceed our budget. The Seneca Acquisition closed in May 2018 with a purchase price of $43.0 million, of which our portion was approximately $5.0 million. Other opportunities may arise during 2018 that could cause our capital expenditures to exceed the budget. In the event our capital expenditure requirements at any time are greater than the amount of capital we have available, we may be required to seek additional sources of capital, which may include the issuance of debt or equity securities, sale of assets, delays in planned exploration, development and completion activities or the use of outside capital through equity investees or similar arrangements.

Our business and operating results can be harmed by factors such as the availability, terms, and cost of capital, increases in interest rates, or a reduction in our credit rating. Changes in any one or more of these factors could cause our cost of doing business to increase, limit our access to capital, limit our ability to pursue acquisition opportunities, reduce our cash flows available for drilling, and place us at a competitive disadvantage. In addition, our ability to access the private and public debt or equity markets is dependent upon a number of factors outside our control, including oil and natural gas prices as well as economic conditions in the financial markets. Continuing disruptions and volatility in the global financial markets may lead to an increase in interest rates or a contraction in credit availability impacting our ability to finance operations. We cannot assure you that we will be able to obtain debt or equity financing on terms favorable to us, or at all.

If we are unable to fund our capital requirements, we may be required to curtail our operations relating to the exploration and development of our prospects, which in turn could lead to a possible loss of properties and a decline in our reserves, or may be otherwise unable to implement our development plan, complete acquisitions, or otherwise take advantage of business opportunities or respond to competitive pressures, any of which could have a material adverse effect on our production, revenues, and results of operations. In addition, a delay in or the failure to complete proposed or future infrastructure projects could delay or eliminate potential efficiencies and related cost savings.

Carbon California may require its members, including us, to make additional capital contributions to it. If we fail to make a required capital contribution to Carbon California, (i) we would be considered a defaulting member, (ii) we would lose our representative on the Board of Directors, and (iii) Prudential would have the option to pay our pro rata portion of the capital contribution and receive the pro rata share of Class A Units in Carbon California that we otherwise would have received.

Our identified drilling locations are scheduled for development only if oil and gas prices warrant drilling over a substantial number of years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.

At an appropriate level of oil and natural gas prices, we have a multi-year drilling inventory of horizontal and vertical drilling locations on existing acreage. These drilling locations, including those without PUDs, represent a significant part of our growth strategy. Our ability to drill and develop these locations depends on a number of uncertainties, including the availability of capital, construction of infrastructure, inclement weather, regulatory changes and approvals, commodity prices, lease expirations, our ability to secure rights to drill at deeper formations, costs, and drilling results.

Further, our identified potential drilling locations are in various stages of evaluation, ranging from locations that are ready to drill to locations that will require substantial additional analysis of data. We cannot predict in advance of drilling and testing whether any particular drilling location will yield oil or natural gas reserves in sufficient quantities to recover drilling or completion costs or to be economically viable or whether wells drilled on 20-acre spacing will produce at the same rates as those on 40-acre spacing. The use of reliable technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling whether oil or natural gas reserves will be present or, if present, whether oil or natural gas reserves will be present in sufficient quantities to be economically viable. Even if sufficient amounts of oil or natural gas reserves exist, we may damage the potentially productive hydrocarbon bearing formation or experience mechanical difficulties while drilling or completing the well, possibly resulting in a reduction in production from the well or abandonment of the well. If we drill dry holes in our current and future drilling locations, our drilling success rate may decline and materially harm our business. We cannot assure you that the analogies we draw from available data from other wells, more fully explored locations, or producing fields will be applicable to our drilling locations. Further, initial production rates reported by us or other operators in the Appalachian Basin and Ventura Basin may not be indicative of future or long-term production rates.

Because of these uncertainties, we do not know if the potential drilling locations we have identified will ever be drilled or if we will be able to produce oil or natural gas reserves from these or any other potential drilling locations. As such, our actual drilling activities may materially differ from those presently identified, which could adversely affect our business, financial condition, and results of operations.

Our acreage must be drilled before lease expiration, generally within three to five years, in order to hold the acreage by production. In a highly competitive market for acreage, failure to drill sufficient wells to hold acreage may result in a substantial lease renewal cost, or if renewal is not feasible, loss of our lease and prospective drilling opportunities.

Leases on oil and natural gas properties typically have a term of three to five years, after which they expire unless prior to expiration, production is established within the spacing units covering the undeveloped acres. 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. Any reduction in our current drilling program, either through a reduction in capital expenditures or the unavailability of drilling rigs, could result in the loss of acreage through lease expirations. We cannot assure you that we will have the liquidity to deploy these rigs when needed, or that commodity prices will warrant operating such a drilling program. Any such losses of leases could materially and adversely affect the growth of our asset base, cash flows, and results of operations.

Unless we replace our reserves, our reserves and production will decline, which would adversely affect our future cash flows and results of operations.

Producing oil and natural gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. As a result, we must locate, acquire and develop new reserves to replace those being depleted by production. Our business strategy is to grow production and reserves through acquisitions and through exploration and development drilling. Unless we conduct successful exploration, development and production activities or acquire properties containing proved reserves, our proved reserves will decline as our existing reserves are produced. Our future oil and natural gas reserves and production, and therefore our future cash flow and results of operations, are highly dependent on our success in efficiently developing our reserves and economically finding or acquiring additional recoverable reserves. We have made, and expect to make in the future, substantial capital expenditures in our business and operations for the development, production, exploration, and acquisition of reserves. We may not have sufficient resources to undertake our exploration, development, and production activities. In addition, we may not be able to develop, exploit, find or acquire sufficient additional reserves to replace our current and future production. If we are unable to replace our current and future production, the value of our reserves will decrease, and our business, financial condition and results of operations will be adversely affected.

Drilling for and producing oil and natural gas are high risk activities with many uncertainties that could adversely affect our business, financial condition and results of operations.

Our future financial condition and results of operations will depend on the success of our acquisition, exploration, development and production activities. These activities are subject to numerous risks beyond our control, including the risk that drilling will not result in commercially viable oil and natural gas production. Our decision to purchase, explore, develop or otherwise exploit prospects or properties will depend in part on the evaluation of data obtained through geophysical and geological analyses, production data and engineering studies, the results of which are often inconclusive or subject to varying interpretations. For a discussion of the uncertainty involved in these processes, see “— Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our proved reserves .” The costs of exploration, exploitation, and development activities are subject to numerous uncertainties beyond our control, and increases in those costs can adversely affect the economics of a project. In addition, drilling and completion costs may increase prior to completion of any particular project. Many factors may curtail, delay or cancel scheduled drilling and production projects, including:

Additionally, drilling, transportation and processing of hydrocarbons bear an inherent risk of loss of containment. Potential consequences include loss of reserves, loss of production, loss of economic value associated with an affected wellbore, contamination of soil, ground water, and surface water, as well as potential fines, penalties, or damages associated with any of the foregoing consequences.

Part of our strategy involves drilling in existing or emerging shale plays 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. Risks that we may 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 may 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, to the extent we engage in horizontal drilling, those activities may adversely affect our ability to successfully drill in one or more of our identified vertical drilling locations.

Our experience with horizontal drilling utilizing the latest drilling and completion techniques is limited. 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 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.

A significant portion of our business is conducted in basins with established production histories. The mature nature of these region could result in lower production.

The Appalachian and Ventura Basins are mature oil and natural gas production regions that have experienced substantial exploration and development activity for many years. Because a large number of oil and natural gas prospects in this region have already been drilled, additional prospects of sufficient size and quality could be more difficult to identify. We cannot assure you that our future drilling activities in these plays will be successful or, if successful, will achieve the potential reserve levels that we currently anticipate based on the drilling activities that have been completed, or that we will achieve the anticipated economic returns based on our current cost models.

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

Water is an essential component of deep 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. As a result of severe drought, some local water districts have begun restricting the use of water subject to their jurisdiction for hydraulic fracturing to protect the availability of local water supply. If we are unable to obtain water to use in our operations from local sources, we may be unable to economically produce our reserves, which could have an adverse effect on our financial condition, results of operations, and cash flows.

We may face unanticipated water and other waste disposal costs.

We may be subject to regulation that restricts our ability to discharge water produced as part of our natural gas production operations. Productive zones frequently contain water that must be removed in order for the natural gas to produce, and our ability to remove and dispose of sufficient quantities of water from the various zones will determine whether we can produce natural gas in commercial quantities. The produced water must be transported from the production site and injected into disposal wells. The capacity of the disposal wells we own may not be sufficient to receive all of the water produced from our wells and may affect our ability to produce our wells. Also, the cost to transport and dispose of that water, including the cost of complying with regulations concerning water disposal, may reduce our profitability.

Where water produced from our projects fails to meet the quality requirements of applicable regulatory agencies, our wells produce water in excess of the applicable volumetric permit limits, the disposal wells fail to meet the requirements of all applicable regulatory agencies, or we are unable to secure access to disposal wells with sufficient capacity to accept all of the produced water, we may be required to shut in wells, reduce drilling activities, or upgrade facilities for water handling or treatment. The costs to dispose of this produced water may increase if any of the following occur:

Our insurance may not protect us or them against all of the operating risks to which our business is exposed.

The crude oil and natural gas business involves numerous operating hazards such as well blowouts, mechanical failures, explosions, uncontrollable flows of crude oil, natural gas or well fluids, fires, formations with abnormal pressures, hurricanes, flooding, pollution, releases of toxic gas and other environmental hazards and risks, which can result in (i) damage to or destruction of wells and/or production facilities, (ii) damage to or destruction of formations, (iii) injury to persons, (iv) loss of life, or (v) damage to property, the environment or natural resources. While we and our subsidiaries carry general liability, control of well, and operator’s extra expense coverage typical in our industry, we are not fully insured against all risks incidental to our and their business. Environmental incidents resulting from our operations could defer revenue, increase operating costs and/or increase maintenance and repair capital expenditures.

Many of our operations are currently conducted in locations that may be at risk of damage from fire, mudslides, earthquakes or other natural disasters.

Carbon California currently conducts operations in California near known wildfire and mudslide areas and earthquake fault zones. Certain of Carbon California’s operations were temporarily halted in December 2017 due to the wildfires in South California. A future natural disaster, such as a fire, mudslide or an earthquake, could cause substantial delays in our operations, damage or destroy equipment, prevent or delay transport of production and cause us to incur additional expenses, which would adversely affect our business, financial condition and results of operations. In addition, our facilities would be difficult to replace and would require substantial lead time to repair or replace. The insurance we maintain against earthquakes, mudslides, fires and other natural disasters would not be adequate to cover a total loss of our facilities, may not be adequate to cover our losses in any particular case and may not continue to be available to us on acceptable terms, or at all.

We may suffer losses or incur environmental liability in hydraulic fracturing operations.

Oil and natural gas deposits exist in shale and other formations. It is customary in our industry to recover oil and natural gas from these shale formations through the use of hydraulic fracturing, combined with horizontal drilling. Hydraulic fracturing is the process of creating or expanding cracks, or fractures, underground where water, sand and other additives are pumped under high pressure into a shale formation. We contract with established service companies to conduct our hydraulic fracturing. The personnel of these service companies are trained to handle potentially hazardous materials and possess emergency protocols and equipment to deal with potential spills and carry material safety data sheets for all chemicals.

In the fracturing process, an accidental release could result in possible environmental damage. All wells have manifolds with escape lines to containment areas. High pressure valves for flow control are on the wellheads. Valves and piping are designed for higher pressures than are typically encountered. Piping is tested prior to any procedure and regular safety inspections and incident drill records are kept on those tests. Despite all of these safety procedures, there are many risks involved in hydraulic fracturing that could result in liability to us. In addition, our liability for environmental hazards may include conditions created by the previous owner of properties that we purchase or lease.

We have entered into natural gas and oil derivative contracts and may in the future enter into additional commodity derivative contracts for a portion of our production, which may result in future cash payments or prevent us from receiving the full benefit of increases in commodity prices.

We use commodity derivative contracts to reduce price volatility associated with certain of our natural gas and oil sales. Under these contracts, we receive a fixed price per MMbtu of natural gas/Bbl of oil and pay a floating market price per MMbtu/Bbl of natural gas/oil to the counterparty based on Henry Hub/NYMEX WTI pricing. The fixed-price payment and the floating-price payment are offset, resulting in a net amount due to or from the counterparty. The extent of our commodity price exposure is related largely to the effectiveness and scope of our commodity derivative contracts. For example, our commodity derivative contracts are based on quoted market prices, which may differ significantly from the actual prices we realize in our operations for oil. In addition, our credit agreement limits the aggregate notional volume of commodities that can be covered under commodity derivative contracts we enter into and, as a result, we will continue to have direct commodity price exposure on the unhedged portion of our production volumes. Our policy has been to hedge a significant portion of our estimated oil and natural gas production. However, our price hedging strategy and future hedging transactions will be determined at our discretion. We are not under an obligation to hedge a specific portion of our production. The prices at which we hedge our production in the future will be dependent upon commodity prices at the time we enter into these transactions, which may be substantially higher or lower than current commodity prices. Accordingly, our price hedging strategy may not protect us from significant declines in commodity prices received for our future production, whether due to declines in prices in general or to widening differentials we experience with respect to our products. Conversely, our hedging strategy may limit our ability to realize cash flows from commodity price increases. It is also possible that a substantially larger percentage of our future production will not be hedged as compared with the next few years, which would result in our revenues becoming more sensitive to commodity price changes.

In addition, our actual future production may be significantly higher or lower than we estimate at the time we enter into commodity derivative contracts for such period. If the actual amount is higher than we estimate, we will have greater commodity price exposure than we intended. If the actual amount is lower than the notional amount of our commodity derivative contracts, we might be forced to satisfy all or a portion of our commodity derivative contracts without the benefit of the cash flow from our sale or purchase of the underlying physical commodity, substantially diminishing our liquidity. There may be a change in the expected differential between the underlying commodity price in the commodity derivative contract and the actual price received, which may result in payments to our derivative counterparty that are not offset by our receipt of payments for our production in the field. Accordingly, our earnings may fluctuate significantly as a result of changes in the fair value of our commodity derivative contracts.

Our commodity derivative contracts expose us to counterparty credit risk.

Our commodity derivative contracts expose us to risk of financial loss if a counterparty fails to perform under a contract. Disruptions in the financial markets could lead to sudden decreases in a counterparty’s liquidity, which could make them unable to perform under the terms of the contract and we may not be able to realize the benefit of the contract. We are unable to predict sudden changes in a counterparty’s creditworthiness or ability to perform. Even if we do accurately predict sudden changes, our ability to negate the risk may be limited depending upon market conditions.

During periods of declining commodity prices, our derivative contract receivable positions generally increase, which increases our counterparty credit exposure. If the creditworthiness of our counterparties deteriorates and results in their nonperformance, we could incur a significant loss with respect to our commodity derivative contracts.

The inability of our derivative contract counterparty to meet its obligations may adversely affect our financial results.

We currently have one derivative contract counterparty (BP Energy Company), and this concentration may impact our overall credit risk in that the counterparty may be similarly affected by changes in economic or other conditions. The inability or failure of our derivative contract counterparty to meet its obligations to us or their insolvency or liquidation may materially adversely affect our financial condition and results of operations.

Our business depends in part on gathering and transportation facilities owned by others. Any limitation in the availability of those facilities would interfere with our ability to market natural gas we produce.

The marketability of our natural gas production depends in part on the availability, proximity and capacity of gathering and pipeline systems owned by third parties. Since we do not own or operate these pipelines or other facilities, their continuing operation in their current manner is not within our control. The amount of natural gas that can be produced and sold is subject to curtailment in certain circumstances, such as pipeline interruptions due to scheduled and unscheduled maintenance, excessive pressure, physical damage to gathering or transportation systems, or lack of contracted transportation capacity on such systems. The curtailments arising from these and similar circumstances may last from a few days to several months. We may be provided with only minimal, if any, notice as to when these circumstances will arise, or their duration. If any of these third party pipelines and other facilities become partially or fully unavailable to transport natural gas or oil, or if the gas quality specifications for the natural gas gathering or transportation pipelines or facilities change so as to restrict our ability to transport natural gas on those pipelines or facilities, our revenues and cash available for distribution could be adversely affected.

In addition, properties may be acquired which are not currently serviced by gathering and transportation pipelines, or the gathering and transportation pipelines in the area may not have sufficient capacity to transport additional production. As a result, we may not be able to sell production from these properties until the necessary facilities are built.

We may incur losses as a result of title deficiencies.

We typically do not retain attorneys to examine title before acquiring leases or mineral interests. Rather, we rely upon the judgment of oil and natural 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. Prior to drilling a well, however, we (or the company that is the operator) obtain a preliminary title review to initially determine that no obvious title deficiencies are apparent. As a result of some such examinations, certain curative work may be required to correct deficiencies in title, and such curative work may be expensive. In some instances, curative work may not be feasible or possible. Our failure to cure any title defects may delay or prevent us from utilizing the associated mineral interest, which may adversely impact our ability in the future to increase production and reserves. Additionally, undeveloped acreage has greater risk of title defects than developed acreage. If there are any title defects or defects in assignment of leasehold rights in properties in which we hold an interest, we may suffer a financial loss. In addition, it is possible that certain interests could have been bought in error from someone who is not the owner. In that event, our interest would be worthless.

In addition, our reserve estimates assume that we have proper title for the properties we have acquired. In the event we are unable to perform curative work to correct deficiencies and our interest is deemed to be worthless, our reserve estimates and the financial information related thereto may be found to be inaccurate, which could have a material adverse effect on us.

Conservation measures and technological advances could reduce demand for oil and natural gas.

Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to oil and natural gas, technological advances in fuel economy and energy-generation devices could reduce demand for oil and natural gas. The impact of the changing demand for oil and natural gas services and products may materially adversely affect our business, financial condition, results of operations and ability to pay dividends on our common stock.

Competition in the oil and natural gas industry is intense, making it more difficult for us to acquire properties, market oil and natural gas and secure trained personnel.

The oil and natural gas industry is intensely competitive, and we compete with other companies that have greater resources than us. Many of these companies not only explore for and produce oil and natural gas, but also carry on midstream and refining operations and market petroleum and other products on a regional, national, or international basis. These companies may be able to pay more for productive oil and natural gas properties and exploratory prospects or define, evaluate, bid for, and purchase a greater number of properties and prospects than our financial or human resources permit. In addition, these companies may have a greater ability to continue exploration activities during periods of low oil and natural gas market prices. Our larger competitors may be able to absorb the burden of present and future federal, state, local, and other laws and regulations more easily than we can, which would adversely affect our competitive position. Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. In addition, because we have fewer financial and human resources than many companies in our industry, we may be at a disadvantage in bidding for exploratory prospects and producing reserves.

The oil and natural gas industry is characterized by rapid and significant technological advancements and introductions of new products and services using new technologies. As others use or develop new technologies, we may be placed at a competitive disadvantage or competitive pressures may force us to implement those new technologies at substantial costs. In addition, other oil and natural gas companies may have greater financial, technical, and personnel resources that allow them to enjoy technological advantages and may in the future allow them to implement new technologies before we can. We may not be able to respond to these competitive pressures and implement new technologies on a timely basis or at an acceptable cost. If one or more of the technologies we use now or in the future were to become obsolete or if we are unable to use the most advanced commercially available technology, our business, financial condition, and results of operations could be materially adversely affected.

The unavailability or high cost of drilling rigs, equipment, supplies, personnel and field services could adversely affect our ability to execute our exploration and development plans within our budget and on a timely basis.

The demand for qualified and experienced field personnel, geologists, geophysicists, engineers and other professionals in the industry can fluctuate significantly, often in correlation with oil and natural gas prices, causing periodic shortages. Historically, there have been shortages of qualified personnel, drilling and workover rigs, pipe and other equipment and materials as demand for rigs and equipment increased along with the number of wells being drilled. We cannot predict whether these conditions will exist in the future and, if so, what their timing and duration will be. Such shortages could delay or cause us to incur significant expenditures that are not provided for in our capital budget, which could have a material adverse effect on our business, financial condition and results of operations.

The loss of senior management or technical personnel could adversely affect operations.

We depend on the services of our senior management and technical personnel. The loss of the services of our senior management, including Patrick McDonald, our Chief Executive Officer, Mark Pierce, our President, and Kevin Struzeski, our Chief Financial Officer, Treasurer and Secretary, could have a material adverse effect on our operations. We do not maintain, nor do we plan to obtain, any insurance against the loss of any of these individuals.

In addition, there is competition within our industry for experienced technical personnel and certain other professionals, which could increase the costs associated with identifying, attracting and retaining such personnel. If we cannot identify, attract, develop and retain our technical and professional personnel or attract additional experienced technical and professional personnel, our ability to compete could be harmed.

Due to our lack of asset and geographic diversification, adverse developments in our operating areas would reduce our ability to pay dividends on shares of our common stock.

We derive substantially all of our revenues from sales of natural gas. Furthermore, a substantial majority of our assets are located in the Ventura Basin in California and Appalachian Basin. Due to our lack of diversification in asset type and location, an adverse development in the oil and gas business of these geographic areas, including those resulting from the impact of regional supply and demand factors, delays or interruptions of production from wells in these areas caused by and costs associated with governmental regulation, processing or transportation capacity constraints, market limitations, water shortages or other weather related conditions, interruption of the processing or transportation of oil, NGLs or natural gas and changes in regional and local political regimes and regulations, would have a significantly greater impact on our results of operations and cash available for dividend payments on shares of our common stock than if we maintained more diverse assets and locations.

There can be no assurance that the Old Ironsides Buyout will be consummated in the anticipated timeframe, on the terms described herein, or at all.

We signed a purchase agreement to acquire all of Old Ironsides’ interest in Carbon Appalachia for $58 million. The consummation of the Old Ironsides Buyout is subject to certain closing conditions, including a financing condition that we anticipate being satisfied by the application of the proceeds from this offering. In addition, the purchase agreement contains certain closing conditions and termination rights for each of Carbon and Old Ironsides if the closing of the Old Ironsides Buyout has not occurred on or before September 1, 2018. There can be no assurances that the Old Ironsides Buyout will be consummated in the anticipated timeframe, on the terms described herein, or at all. Our stock price could be negatively impacted if we fail to complete the Old Ironsides Buyout.

We may be subject to risks in connection with acquisitions of properties and may be unable to successfully integrate acquisitions.

There is intense competition for acquisition opportunities in our industry and we may not be able to identify attractive acquisition opportunities. Even if we do identify attractive acquisition opportunities, we may not be able to complete the acquisitions or do so on commercially acceptable terms. Competition for acquisitions may increase the cost of, or cause us to refrain from, completing acquisitions. Our ability to complete acquisitions is dependent upon, among other things, our ability to obtain debt and equity financing and, in some cases, regulatory approvals. Further, these acquisitions may be in geographic regions in which we do not currently operate, which could result in unforeseen operating difficulties and difficulties in coordinating geographically dispersed operations, personnel, and facilities. In addition, if we enter into new geographic markets, we may be subject to additional and unfamiliar legal and regulatory requirements. Compliance with these regulatory requirements may impose substantial additional obligations on us and our management, cause us to expend additional time and resources in compliance activities, and increase our exposure to penalties or fines for non-compliance with such additional legal requirements. Completed acquisitions could require us to invest further in operational, financial, and management information systems and to attract, retain, motivate, and effectively manage additional employees. The inability to effectively manage the integration of acquisitions could reduce our focus on subsequent acquisitions and current operations, which, in turn, could negatively impact our results of operations and growth. Our financial condition and results of operations may fluctuate significantly from period to period, based on whether or not significant acquisitions are completed in particular periods.

Any acquisition involves potential risks, including, among other things:

Our ability to complete dispositions of assets, or interests in assets, may be subject to factors beyond our control, and in certain cases we may be required to retain liabilities for certain matters.

From time to time, we may sell an interest in a strategic asset for the purpose of assisting or accelerating the asset’s development. In addition, we regularly review our property base for the purpose of identifying nonstrategic assets, the disposition of which would increase capital resources available for other activities and create organizational and operational efficiencies. Various factors could materially affect our ability to dispose of such interests or nonstrategic assets or complete announced dispositions, including the receipt of approvals of governmental agencies or third parties and the availability of purchasers willing to acquire the interests or purchase the nonstrategic assets on terms and at prices acceptable us.

Sellers typically retain certain liabilities or indemnify buyers for certain pre-closing matters, such as matters of litigation, environmental contingencies, royalty obligations and income taxes. The magnitude of any such retained liability or indemnification obligation may be difficult to quantify at the time of the transaction and ultimately may be material. Also, as is typical in divestiture transactions, third parties may be unwilling to release us from guarantees or other credit support provided prior to the sale of the divested assets. As a result, after a divestiture, we may remain secondarily liable for the obligations guaranteed or supported to the extent that the buyer of the assets fails to perform these obligations.

Properties we acquire may not produce as projected, and we may be unable to determine reserve potential, identify liabilities associated with the properties that we acquire, or obtain protection from sellers against such liabilities.

Acquiring oil and natural gas properties requires us to assess reservoir and infrastructure characteristics, including recoverable reserves, development and operating costs, and potential environmental and other liabilities. Such assessments are inexact and inherently uncertain. In connection with the assessments, we perform a review of the subject properties, but such a review will not reveal all existing or potential problems. In the course of our due diligence, we may not inspect every well or pipeline. We cannot necessarily observe structural and environmental problems, such as pipe corrosion, when an inspection is made. We may not be able to obtain contractual indemnities from the seller for liabilities created prior to our purchase of the property. We may be required to assume the risk of the physical condition of the properties in addition to the risk that the properties may not perform in accordance with our expectations.

Our ability to use net operating loss carryforwards to offset future taxable income for U.S. federal income tax purposes is subject to limitation.

As of December 31, 2017, we had approximately $21.2 million of U.S. federal net operating loss carryforwards (“ NOLs ”), which begin to expire in 2032. Utilization of these NOLs depends on many factors, including our future income, which cannot be assured. In addition, Section 382 of the Internal Revenue Code of 1986, as amended (“ Section 382 ”), generally imposes an annual limitation on the amount of NOLs that may be used to offset taxable income by a corporation that has undergone an “ownership change” (as determined under Section 382). An ownership change generally occurs if one or more stockholders (or groups of stockholders) that are each deemed to own at least 5% of our stock increase their ownership percentage by more than 50 percentage points over their lowest ownership percentage during a rolling three-year period.

We believe we will experience an ownership change as a result of this offering. Thus, our ability to utilize NOLs existing at the time of such ownership change will be subject to limitation under Section 382. The application of such NOL limitation may cause U.S. federal income taxes to be paid earlier than they otherwise would be paid if such limitation were not in effect and could cause such NOLs to expire unused, in each case reducing or eliminating the benefit of such NOLs. To the extent we are not able to offset our future income with our NOLs, this would adversely affect our operating results and cash flows if we have taxable income in the future. Similar rules and limitations may apply for state income tax purposes.

Recently enacted tax legislation may impact our ability to fully utilize our interest expense deductions and net operating loss carryovers to fully offset our taxable income in future periods.

On December 22, 2017, tax legislation commonly known as the Tax Cuts and Jobs Act (the “ TCJA ”) was enacted. Beginning in 2018, the TCJA generally will (i) limit our annual deductions for interest expense to no more than 30% of our “adjusted taxable income” (plus 100% of our business interest income) for the year and (ii) permit us to offset only 80% (rather than 100%) of our taxable income with net operating losses we generate after 2017. Interest expense and net operating losses subject to these limitations may be carried forward by us for use in later years, subject to these limitations. Additionally, the TCJA repealed the domestic manufacturing tax deduction for oil and gas companies. These tax law changes could have the effect of causing us to incur income tax liability sooner than we otherwise would have incurred such liability or, in certain cases, could cause us to incur income tax liability that we might otherwise not have incurred, in the absence of these tax law changes. The TCJA also includes provisions that, beginning in 2018, reduce the maximum federal corporate income tax rate from 35% to 21% and eliminate the alternative minimum tax, which would lessen any adverse impact of the limitations described in the preceding sentences.

We may incur more taxes and certain of our projects may become uneconomic if certain federal income tax deductions currently available with respect to oil and natural gas exploration and development are eliminated as a result of future legislation.

Various proposals have been made recommending the elimination of certain key U.S. federal tax incentives that are currently available with respect to oil and natural gas exploration and development. Any such change could negatively impact our financial condition and results of operations by increasing the costs we incur which would in turn make it uneconomic to drill some prospects if commodity prices are not sufficiently high, resulting in lower revenues and decreases in production and reserves.

A terrorist attack or armed conflict could harm our business.

Terrorist activities, anti-terrorist activities and other armed conflicts involving the United States or other countries may adversely affect the United States and global economies. If any of these events occur, the resulting political instability and societal disruption could reduce overall demand for oil and natural gas, potentially putting downward pressure on demand for our operators’ services and causing a reduction in our revenues. Oil and natural gas facilities, including those of our operators, could be direct targets of terrorist attacks, and if infrastructure integral to our operators is destroyed or damaged, they may experience a significant disruption in their operations. Any such disruption could materially adversely affect our financial condition, results of operations and cash available to pay dividends on our common stock.

Our business could be materially and adversely affected by security threats, including cybersecurity threats, and other disruptions.

As an oil and gas producer, we face various security threats, including cybersecurity threats to gain unauthorized access to sensitive information or to render data or systems unusable; threats to the security of our facilities and infrastructure or third party facilities and infrastructure, such as processing plants and pipelines; and threats from terrorist acts. The potential for such security threats has subjected our operations to increased risks that could have a material adverse effect on our business. In particular, our implementation of various procedures and controls to monitor and mitigate security threats and to increase security for our information, facilities and infrastructure may result in increased capital and operating costs. Costs for insurance may also increase as a result of security threats, and some insurance coverage may become more difficult to obtain, if available at all. Moreover, there can be no assurance that such procedures and controls will be sufficient to prevent security breaches from occurring. If any of these security breaches were to occur, they could lead to losses of sensitive information, critical infrastructure or capabilities essential to our operations and could have a material adverse effect on our reputation, financial position, results of operations and cash flows.

Cybersecurity attacks in particular are becoming more sophisticated. We rely extensively on information technology systems, including Internet sites, computer software, data hosting facilities and other hardware and platforms, some of which are hosted by third parties, to assist in conducting our business. Our technologies systems and networks, and those of our business associates may become the target of cybersecurity attacks, including without limitation malicious software, attempts to gain unauthorized access to data and systems, and other electronic security breaches that could lead to disruptions in critical systems and materially and adversely affect us in a variety of ways, including the following:

These events could damage our reputation and lead to financial losses from remedial actions, loss of business or potential liability. Additionally, certain cyber incidents, such as surveillance, may remain undetected for an extended period.

Increased costs of capital could materially adversely affect our business.

Our business, ability to make acquisitions and operating results could be harmed by factors such as the availability, terms and cost of capital or increases in interest rates. Changes in any one or more of these factors could cause our cost of doing business to increase, limit our access to capital, limit our ability to pursue acquisition opportunities, and place us at a competitive disadvantage. A significant reduction in the availability of credit could materially and adversely affect our ability to achieve our planned growth and operating results.

Increases in interest rates could adversely affect the demand for our common stock.

An increase in interest rates may cause a corresponding decline in demand for equity investments, in particular for yield-based equity investments such as our common stock. Any such reduction in demand for our common stock resulting from other more attractive investment opportunities may cause the trading price of our common stock to decline.

Risks Related to Regulatory Requirements

We are subject to complex federal, state, local and other laws and regulations that could adversely affect the cost, manner or feasibility of conducting our operations or expose us to significant liabilities.

Our exploration, production and transportation operations are subject to complex and stringent laws and regulations. In order to conduct our operations in compliance with these laws and regulations, we must obtain and maintain numerous permits, approvals and certificates from various federal, state and local governmental authorities. We may incur substantial costs in order to maintain compliance with these existing laws and regulations. In addition, our costs of compliance may increase if existing laws and regulations are revised or reinterpreted, or if new laws and regulations become applicable to our operations. Such costs could have a material adverse effect on our business, financial condition and results of operations. For example, in California, there have been proposals at the legislative and executive levels in the past for tax increases which have included a severance tax as high as 12.5% on all oil production in California. Although the proposals have not passed the California legislature, the State of California could impose a severance tax on oil in the future. Carbon California has significant oil production in California and while we cannot predict the impact of such a tax without having more specifics, the imposition of such a tax could have severe negative impacts on its willingness and ability to incur capital expenditures in California to increase production, could severely reduce or completely eliminate its profit margins from operations in California and would result in lower oil production in its California properties due to the need to shut-in wells and facilities made uneconomic either immediately or at an earlier time than would have previously been the case.

Our business is subject to federal, state and local laws and regulations as interpreted and enforced by governmental authorities possessing jurisdiction over various aspects of the exploration for, and the production and transportation of, oil and natural gas. Failure to comply with such laws and regulations, including any evolving interpretation and enforcement by governmental authorities, could have a material adverse effect on our business, financial condition and results of operations.

Changes to existing or new regulations may unfavorably impact us, could result in increased operating costs, and could have a material adverse effect on our financial condition and results of operations. For example, over the last few years, several bills have been introduced in Congress that, if adopted, would subject companies involved in oil and natural gas exploration and production activities to, among other items, additional regulation of and restrictions on hydraulic fracturing of wells, the elimination of certain U.S. federal tax incentives and deductions available for such activities, and the prohibition or additional regulation of private energy commodity derivative and hedging activities. Additionally, the Bureau of Land Management (“ BLM ”), acting under its authority pursuant to the Mineral Leasing Act of 1920, finalized new regulations in November 2016 that aimed to reduce waste of natural gas from federal and tribal leasehold by imposing new venting, flaring, and leak detection and repair requirements. In December 2017, BLM issued a final rule suspending implementation of the November 2016 rule until January 2019. In February 2018, the suspension was overturned by the U.S. District Court for Northern California. Implementation of these regulations remains uncertain due to ongoing litigation. If these regulations, or other potential regulations, particularly at the local level, are implemented, they could increase our operating costs, reduce our liquidity, delay or halt our operations or otherwise alter the way we conduct our business, which could in turn have a material adverse effect on our financial condition, results of operations and cash flows.

Operations may be exposed to significant delays, costs and liabilities as a result of environmental, health and safety requirements applicable to our business activities.

We may incur significant delays, costs and liabilities as a result of environmental, health and safety requirements applicable to our exploration, development and production activities. These delays, costs and liabilities could arise under a wide range of federal, state and local laws and regulations and enforcement policies relating to protection of the environment, health and safety, which have tended to become increasingly stringent over time. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, imposition of cleanup and site restoration costs and liens, and, in some instances, issuance of orders or injunctions limiting or requiring discontinuation of certain operations. We are often required to prepare and present to federal, state or local authorities data pertaining to the effect or impact that a proposed project may have on the environment, threatened and endangered species, and cultural and archaeological artifacts. The public may comment on and otherwise engage in the permitting process, including through judicial intervention. As a result, the permits we need may not be issued, or if issued, may not be issued in a timely manner or may impose requirements that restrict our ability to conduct operations.

In addition, claims for damages to persons or property, including natural resources, may result from the environmental, health and safety impacts of our operations. Strict liability and joint and several liability may be imposed under certain environmental laws, which could cause us to become liable for the conduct of others or for consequences of our own actions that were in compliance with all applicable laws at the time those actions were taken.

New laws, regulations or enforcement policies could be more stringent and impose unforeseen liabilities or significantly increase compliance costs. If we are not able to recover the resulting costs through increased revenues, our business, financial condition or results of operations could be adversely affected.

The adoption of climate change legislation or regulations restricting emissions of “greenhouse gases” could result in increased operating costs and reduced demand for the oil and natural gas we produce.

In response to findings that emissions of carbon dioxide, methane and other “greenhouse gases” present an endangerment to public health and the environment, the EPA has issued regulations to restrict emissions of greenhouse gases under existing provisions of the federal Clean Air Act. These regulations include limits on tailpipe emissions from motor vehicles and preconstruction and operating permit requirements for certain large stationary sources. The EPA has also adopted rules requiring the reporting of greenhouse gas emissions from specified large greenhouse gas emission sources in the United States, as well as certain onshore oil and natural gas production facilities, on an annual basis. In December 2015, the EPA finalized rules that added new sources to the scope of the greenhouse gases monitoring and reporting rule. These new sources include gathering and boosting facilities as well as completions and workovers from hydraulically fractured oil wells. The revisions also include the addition of well identification reporting requirements for certain facilities. More recently, in June 2016, the EPA finalized rules that establish new air emission controls for methane emissions from certain new, modified or reconstructed equipment and processes in the oil and natural gas source category, including production, processing, transmission and storage activities. However, over the past year the EPA has taken several steps to delay implementation of the agency’s methane standards, and proposed rulemaking in June 2017 to stay the requirements for a period of two years and revisit implementation of the agency’s methane standards in its entirety. The EPA has not yet published a final rule but, as a result of these developments, future implementation of the 2016 rules is uncertain at this time. In addition, various industry and environmental groups have separately challenged both the original methane requirements and the EPA’s attempts to delay implementation of the rules. As a result, substantial uncertainty exists with respect to future implementation of the EPA’s methane rules. Compliance with rules to control methane emissions would likely require enhanced record-keeping practices, the purchase of new equipment such as optical gas imaging instruments to detect leaks and the increased frequency of maintenance and repair activities to address emissions leaks. The rules would also likely require hiring additional personnel to support these activities or the engagement of third party contractors to assist with and verify compliance with these new and proposed rules and could increase the cost of our operations. The future implementation of these rules, or similar proposed rules, could result in increased compliance costs for us.

In addition, Congress has from time to time considered adopting legislation to reduce emissions of greenhouse gases and many states have already established greenhouse gas cap and trade programs. Most of these cap and trade programs work by requiring major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and gas processing plants, to acquire and surrender emission allowances. The number of allowances available for purchase is reduced each year in an effort to achieve the overall greenhouse gas emission reduction goal. Internationally, the United Nations Framework Convention on Climate Change finalized an agreement among 195 nations at the 21st Conference of the Parties in Paris with an overarching goal of preventing global temperatures from rising more than 2 degrees Celsius. The agreement includes provisions that every country take some action to lower emissions, but there is no legal requirement for how or by what amount emissions should be lowered.

California has been one of the leading states in adopting greenhouse gas emission reduction requirements, and has implemented a cap and trade program as well as mandates for renewable fuels sources. California’s cap and trade program requires Carbon California to report its greenhouse gas emissions and essentially sets maximum limits or caps on total emissions of greenhouse gases from all industrial sectors that are or become subject to the program. This includes the oil and natural gas extraction sector of which Carbon California is a part. Carbon California’s main sources of greenhouse gas emissions for its Southern California oil and gas operations are primarily attributable to emissions from internal combustion engines powering generators to produce electricity, flares for the disposal of excess field gas, and fugitive emission from equipment such as tanks and components. Under the California program, the cap declines annually from 2013 through 2020. In July 2017, California extended the cap and trade program to 2030. Under the cap and trade program, Carbon California is required to obtain authorizations for each metric ton of greenhouse gases that it emits, either in the form of allowances (each the equivalent of one ton of carbon dioxide) or qualifying offset credits. A portion of the allowance will be granted by the state, but any shortfall between the state-granted allowance and the facility’s emissions will have to be addressed through the purchase of additional allowances either from the state or a third party. The availability of allowances will decline over time in accordance with the declining cap, and the cost to acquire such allowances may increase over time. However, we do not expect the cost to be material to Carbon California’s operations.

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

Environmental legislation and regulatory initiatives, including those relating to hydraulic fracturing and underground injection, could result in increased costs and additional operating restrictions or delays.

We are subject to extensive federal, state and local laws and regulations concerning environmental protection. Government authorities frequently add to those regulations. Both oil and gas development generally and hydraulic fracturing in particular, are receiving increased regulatory attention.

Essentially all of our reserves in the Appalachian Basin are subject to or have been subjected to hydraulic fracturing. The reservoir rock in these areas, in general, has insufficient permeability to flow enough oil or natural gas to be economically viable without stimulation. The controlling regulatory agencies for well construction have standards that are designed specifically in anticipation of hydraulic fracturing. The stimulation process cost varies according to well location and reservoir. The regulatory environment may change with respect to the use of hydraulic fracturing. Any increase in compliance costs could negatively impact our ability to conduct our business.

While hydraulic fracturing historically has been regulated by state and natural gas commissions, the practice has become increasingly controversial in certain parts of the country, resulting in increased scrutiny and regulation from federal and state agencies. The EPA has asserted federal regulatory authority pursuant to the federal SDWA over hydraulic fracturing involving fluids that contain diesel fuel and published permitting guidance in February 2014 for hydraulic fracturing operations that use diesel fuel in fracturing fluids in those states in which EPA is the permitting authority. In recent years, the EPA has issued final regulations under the federal CAA establishing performance standards for completions of hydraulically fractured oil and natural gas wells, compressors, controllers, dehydrators, storage tanks, natural gas processing plants and certain other equipment. EPA also finalized rules in June 2016 that prohibit the discharge of wastewater from hydraulic fracturing operations to publicly owned wastewater treatment plants. Federal agencies have also proposed limits on hydraulic fracturing activities on federal lands and many producing states, cities and counties have adopted, or are considering adopting, regulations that impose more stringent permitting, public disclosure and well construction requirements on hydraulic fracturing operations or bans or moratoria on drilling that effectively prohibit further production of oil and natural gas through the use of hydraulic fracturing or similar operations. For example, several jurisdictions in California have proposed various forms of moratoria or bans on hydraulic fracturing and other hydrocarbon recovery techniques, including traditional waterflooding, acid treatments and cyclic steam injection.

Moreover, while the scientific community and regulatory agencies at all levels are continuing to study a possible linkage between oil and gas activity and induced seismicity, some state regulatory agencies have modified their regulations or guidance to regulate potential causes of induced seismicity including fluid injection or oil and natural gas extraction. In addition, the California Division of Oil, Gas & Geothermal Resources (“ DOGGR ”) adopted regulations intended to bring California’s Class II Underground Injection Control (“ UIC ”) program into compliance with the federal Safe Drinking Water Act, under which some wells may require an aquifer exemption. DOGGR began reviewing all active UIC projects, regardless of whether an exemption is required. In addition, DOGGR has undertaken a comprehensive examination of existing regulations and plans to issue additional regulations with respect to certain oil and gas activities in 2018, such as management of idle wells, pipelines and underground fluid injection. If new regulatory initiatives are implemented that restrict or prohibit the use of underground injection wells in areas where we rely upon the use of such wells in our operations, our costs to operate may significantly increase and our ability to continue production may be delayed or limited, which could have an adverse effect on our results of operation and financial position.

Any of the above factors could have a material adverse effect on our financial position, results of operations or cash flows and could make it more difficult or costly for us to perform hydraulic fracturing or underground injection.

Should we fail to comply with all applicable FERC administered statutes, rules, regulations and orders, we could be subject to substantial penalties and fines.

FERC has civil penalty authority under the Natural Gas Act (“ NGA ”), the Natural Gas Policy Act, and the rules, regulations, restrictions, conditions and orders promulgated under those statutes, including regulations prohibiting market manipulation in connection with the purchase or sale of natural gas, to impose penalties for current violations of up to approximately $1.2 million per day for each violation and disgorgement of profits associated with any violation. This maximum penalty authority established by statute will continue to be adjusted periodically for inflation.

Section 1(b) of the NGA exempts certain natural gas gathering facilities from regulation by FERC. We believe that our natural gas gathering pipelines meet the traditional tests FERC has used to establish a pipeline’s status as an exempt gatherer not subject to regulation as a natural gas company. While our systems have not been regulated by FERC as a natural gas company under the NGA, we are required to report aggregate volumes of natural gas purchased or sold at wholesale to the extent such transactions utilize, contribute to, or may contribute to the formation of price indices. In addition, Congress may enact legislation, FERC may adopt regulations, or a court may make a determination that may subject certain of our otherwise non-FERC jurisdictional facilities to further regulation. Failure to comply with those regulations in the future could subject us to civil penalty liability.

The adoption of derivatives legislation could have an adverse impact on our ability to use derivatives as hedges against fluctuating commodity prices.

In July 2010, the Dodd-Frank Act was enacted, representing an extensive overhaul of the framework for regulation of U.S. financial markets. The Dodd-Frank Act called for various regulatory agencies, including the SEC and the Commodities Futures Trading Commission (“ CFTC ”), to establish regulations for implementation of many of its provisions. The Dodd-Frank Act contains significant derivatives regulations, including requirements that certain transactions be cleared on exchanges and that cash collateral (margin) be posted for such transactions. The Dodd-Frank Act provides for an exemption from the clearing and cash collateral requirements for commercial end-users, such as Carbon, and includes a number of defined terms used in determining how this exemption applies to particular derivative transactions and the parties to those transactions. We have satisfied the requirements for the commercial end-user exception to the clearing requirement and intend to continue to engage in derivative transactions.

In December 2016, the CFTC proposed rules on capital requirements that may have an impact on our hedging counterparties, as the proposed rules would require certain swap dealers and major swap participants to calculate capital requirements inclusive of swaps with commercial end-users. The CFTC has not yet acted on this proposed rulemaking. Also in December 2016, the CFTC re-proposed regulations regarding position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents, subject to exceptions for certain bona fide hedging transactions. The CFTC has not acted on the re-proposed position limit regulations. As these new position limit rules are not yet final, the impact of those provisions on us is uncertain at this time. However, as proposed, Carbon anticipates that its swaps would qualify as exempt bona fide hedging transactions. The ultimate effect of these new rules and any additional regulations is uncertain. New rules and regulations in this area may result in significant increased costs and disclosure obligations as well as decreased liquidity as entities that previously served as hedge counterparties exit the market.

Risks Related to This Offering and Our Common Stock

We may not have sufficient available cash to pay any dividends on our common stock.

We may not have sufficient available cash each quarter to enable us to pay any dividends to our stockholders. The actual amount of our available cash we will have to pay dividends each quarter will be reduced by the cost to fund acquisitions without issuing additional equity or debt, payments in respect of our debt instruments, other contractual obligations, operating expenses, general and administrative expenses, maintenance capital expenditures and reserves for future capital needs that the board of directors may determine are appropriate.

Our ability to pay regular dividends on our common stock is subject to the discretion of our board of directors.

Our stockholders will have no contractual or other legal right to dividends. The payment of future dividends on our common stock will be at the discretion of our board of directors and will depend on, among other things, our earnings, financial condition, capital requirements, level of indebtedness, statutory and contractual restrictions applying to the payment of dividends and other considerations that our board of directors deems relevant. Our board of directors will have the authority to establish cash reserves for the prudent conduct of our business, and the establishment of or increase in those reserves could result in a reduction in cash available for distribution to pay dividends on our common stock at anticipated levels. Accordingly, we may not be able to make, or may have to reduce or eliminate, the payment of dividends on our common stock, which could adversely affect the market price of our common stock.

Delaware law imposes restrictions on our ability to pay cash dividends on our common stock.

Holders of our common stock do not have a right to dividends on such shares unless declared or set aside for payment by our board of directors. Under Delaware law, cash dividends on capital stock may only be paid from “surplus” or, if there is no “surplus,” from the corporation’s net profits for the then-current or the preceding fiscal year. Unless we operate profitably, our ability to pay dividends on our common stock would require the availability of adequate “surplus,” which is defined as the excess, if any, of net assets (total assets less total liabilities) over capital. Our business may not generate sufficient cash flow from operations to enable us to pay dividends on our common stock.

Our credit facilities impose restrictions on dividend payments.

Our credit facility contains covenants that restrict our ability to pay dividends unless Adjusted EBITDA (as defined therein) for the prior quarter is at least 2.75x our interest expense for such quarter and our utilization is less than 85% of the borrowing base. Additionally, our credit facility requires us to maintain a balance of unencumbered cash and cash equivalents of $750,000 as of the relevant determination dates. There can be no assurance that we will generate sufficient Adjusted EBITDA to permit us to pay dividends under our credit facilities or that future credit facilities, including the New Revolving Credit Facility, might not have more stringent restrictions on the payment of dividends.

Restrictions on distributions to us by our subsidiaries and affiliates under their credit agreements could limit our ability to pay anticipated dividends to holders of our common stock. These agreements contain financial tests and covenants that our subsidiaries and affiliates must satisfy prior to making distributions. If any of our subsidiaries or affiliates is unable to satisfy these restrictions or is otherwise in default under such agreements, it would be prohibited from making distributions to us that could, in turn, limit our ability to pay dividends to holders of our common stock.

We do not have a legal or contractual obligation to pay dividends quarterly or on any other basis. The amount of our quarterly cash dividends, if any, may vary significantly both quarterly and annually and will be directly dependent on the performance of our business.

Investors who are looking for an investment that will pay regular and predictable quarterly dividends should not invest in our common stock. Our future business performance may be volatile and our cash flows may be unstable and we do not intend to maintain excess dividend coverage for the purpose of maintaining stability or growth in our dividends nor do we intend to reserve cash for dividends in future periods or incur debt to pay dividends. Because our quarterly dividends will be dependent upon the amount of cash we generate each quarter after payment of our fixed and variable expenses and after reserves for (i) debt service and other contractual obligations and fixed charges and (ii) future operating and capital needs, future quarterly dividends paid to our stockholders will vary significantly from quarter to quarter and may be zero. Please read “ Dividend Policy and Restrictions on Dividends .”

Our board of directors will initially adopt a policy to pay dividends to our stockholders, which could limit our ability to grow and make acquisitions.

As a result of our dividend policy, we will have limited cash available to fund acquisitions, and we will rely primarily upon external financing sources, including commercial bank borrowings and the issuance of debt and equity securities, to fund our acquisitions. As such, to the extent we are unable to finance growth externally, our dividend policy may significantly impair our ability to grow.

To the extent we issue additional shares of common stock in connection with any acquisitions or as in-kind dividends, the payment of dividends on those additional shares of common stock may increase the risk that we will be unable to maintain or increase our per share dividend level. The incurrence of commercial borrowings or other debt to finance our growth strategy would result in increased interest expense, which, in turn, would reduce the available cash that we have to distribute to our stockholders.

The market price of our common stock could be materially adversely affected by sales of substantial amounts of our common stock in the public markets, including sales by Yorktown.

Giving effect to the Pro Forma Adjustments, Yorktown and its affiliates will beneficially own approximately           % of our outstanding common stock. After the expiration of the 180-day lockup with the underwriters, Yorktown and its affiliates will be able to sell their shares in the public markets. Any such sales, or the perception that such sales might occur, could have a material adverse effect on the price of our common stock or could impair our ability to obtain capital through an offering of equity securities.

We have incurred and will continue to incur increased costs and demands upon management and accounting and finance resources as a result of complying with the laws and regulations affecting public companies; any failure to establish and maintain adequate internal control over financial reporting or to recruit, train and retain necessary accounting and finance personnel could have an adverse effect on our ability to accurately and timely prepare our financial statements.

As a public company, we incur significant administrative, legal, accounting and other burdens and expenses beyond those of a private company, including those associated with corporate governance requirements and public company reporting obligations. We have had to and will continue to expend resources to supplement our internal accounting and financial resources, to obtain technical and public company training and expertise, and to develop and expand our quarterly and annual financial statement closing process in order to satisfy such reporting obligations.

Our management team must comply with various requirements of being a public company. We have devoted, and will continue to devote, significant resources to address these public company-associated requirements, including compliance programs and investor relations, as well as our financial reporting obligations. Complying with these rules and regulations results in higher legal and financial compliance costs as compared to a public company. As we continue to acquire other properties and expand our business we expect these costs to increase.

If we fail to maintain an effective system of internal controls, we may not be able to accurately report our financial results or prevent fraud. As a result, current and potential stockholders could lose confidence in our financial reporting, which would harm our business and the trading price of our common stock.

We are required to disclose material changes made in our internal control over financial reporting on a quarterly basis and we are required to assess the effectiveness of our controls annually. Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud and operate successfully as a public company. We cannot be certain that our efforts to maintain our internal controls will be successful or that we will be able to comply with our obligations under Section 404 of the Sarbanes Oxley Act of 2002. We may incur significant costs in our efforts to comply with Section 404. As a smaller reporting company, we currently are exempt from the requirement to obtain an external audit on the effectiveness of internal controls over financial reporting provided in Section 404(b) of the Sarbanes-Oxley Act. Any failure to maintain effective internal controls, or difficulties encountered in implementing or improving our internal controls, could harm our operating results or cause us to fail to meet our reporting obligations. Ineffective internal controls could also cause investors to lose confidence in our reported financial information, which would likely have a negative effect on the trading price of our common stock. For a description of a significant deficiency in our internal controls as of December 31, 2017, please see Note 13 to our consolidated financial statements included in this prospectus.

An active, liquid and orderly trading market for our common stock does not exist and may not develop, and the price of our stock may be volatile and may decline in value.

There currently is not an active public market for our common stock. An active trading market may not develop or, if developed, may not be sustained. The lack of an active market may impair your ability to sell your shares of common stock at the time you wish to sell them or at a price that you consider reasonable. An inactive market may also impair our ability to raise capital by selling shares of common stock and may impair our ability to acquire other companies or assets by using shares of our common stock as consideration.

The market price of our common stock may also be influenced by many factors, some of which are beyond our control, including:

We are a “smaller reporting company” and the reduced disclosure requirements applicable to smaller reporting companies may make our common stock less attractive to investors.

We are considered a “smaller reporting company” (a company that has a public float of less than $75 million). We are therefore entitled to rely on certain reduced disclosure requirements, such as an exemption from providing selected financial data and executive compensation information. We have utilized this exemption for each year since the year ended March 31, 2009. These exemptions and reduced disclosures in our SEC filings due to our status as a smaller reporting company mean our auditors do not review our internal control over financial reporting and may make it harder for investors to analyze our results of operations and financial prospects. We cannot predict if investors will find our common stock less attractive because we may rely on these exemptions. If some investors find our common stock less attractive as a result, there may be a less active trading market for our common stock and our common stock prices may be more volatile.

We will be a “controlled company” within the meaning of the NASDAQ rules. As a result, we qualify for, and intend to continue to rely on, exemptions from corporate governance requirements that provide protection to stockholders of other companies.

Yorktown controls a majority of the voting power of our outstanding common stock. As a result, we are a “controlled company” within the meaning of NASDAQ Listing Rule 5615(c). Under these rules, a company of which more than 50% of the voting power is held by an individual, group or another company is a “controlled company” and may elect not to comply with some corporate governance requirements, including:

Accordingly, you do not have the same protections afforded to stockholders of companies that are subject to all of the corporate governance requirements of the NASDAQ rules.

Control of our stock by current stockholders is expected to remain significant.

Currently, our key stockholders directly and indirectly beneficially own a majority of our outstanding common stock. As a result, these affiliates have the ability to exercise significant influence over matters submitted to our stockholders for approval, including the election and removal of directors, amendments to our certificate of incorporation and bylaws and the approval of any business combination. This concentration of ownership may also have the effect of delaying or preventing a change of control of our company or discouraging others from making tender offers for our shares, which could prevent our stockholders from receiving an offer premium for their shares.

Provisions of our charter documents and Delaware law may inhibit a takeover, which could limit the price investors might be willing to pay in the future for our common stock.

Provisions in our certificate of incorporation and bylaws may have the effect of delaying or preventing an acquisition of us or a merger in which we are not the surviving company and may otherwise prevent or slow changes in our board of directors and management. In addition, because we are incorporated in Delaware, we are governed by the provisions of Section 203 of the Delaware General Corporation Law (the “ DGCL ”), which will apply to us from the closing of this offering. These provisions could discourage an acquisition of us or other change in control transactions and thereby negatively affect the price that investors might be willing to pay in the future for our common stock.

Our amended and restated bylaws designate the state and federal courts located within the State of Delaware as the sole and exclusive forum for certain types of actions and proceedings that may be initiated by our stockholders, which could limit our stockholders’ ability to obtain a favorable judicial forum for disputes with us or our directors, officers, employees or agents.

Our amended and restated bylaws provide that, unless we consent in writing to the selection of an alternative forum, the state and federal courts located within the State of Delaware will, to the fullest extent permitted by applicable law, be the sole and exclusive forum for (i) any derivative action or proceeding brought on our behalf, (ii) any action asserting a claim of breach of a fiduciary duty owed by any of our directors, officers, or other employees to us or our stockholders, (iii) any action asserting a claim arising pursuant to any provision of the DGCL, or (iv) any action asserting a claim governed by the internal affairs doctrine, in each such case subject to such court’s having personal jurisdiction over the indispensable parties named as defendants therein. Any person or entity purchasing or otherwise acquiring any interest in shares of our capital stock will be deemed to have notice of the provisions of our amended and restated bylaws described in the preceding sentence. This choice of forum provision may limit a stockholder’s ability to bring a claim in a judicial forum that it finds favorable for disputes with us or our directors, officers, employees or agents, which may discourage such lawsuits against us and such persons. Alternatively, if a court were to find these provisions of our amended and restated bylaws inapplicable to, or unenforceable in respect of, one or more of the specified types of actions or proceedings, we may incur additional costs associated with resolving such matters in other jurisdictions, which could adversely affect our business, financial condition or results of operations.

Terms of subsequent financings may adversely impact stockholder equity.

We may raise additional capital through the issuance of equity or debt in the future. In that event, the ownership of our existing stockholders would be diluted, and the value of the stockholders’ equity in common stock could be reduced. If we raise more equity capital from the sale of common stock, institutional or other investors may negotiate terms more favorable than the current prices of our common stock. If we issue debt securities, the holders of the debt would have a claim to our assets that would be prior to the rights of stockholders until the debt is paid. Interest on these debt securities would increase costs and could negatively impact operating results.

In accordance with Delaware law and the provisions of our certificate of incorporation, we may issue preferred stock that ranks senior in right of dividends, liquidation or voting to our common stock. The issuance by us of such preferred stock may (a) reduce or eliminate the amount of cash available for payment of dividends to our holders of common stock, (b) diminish the relative voting strength of the total shares of common stock outstanding as a class, or (c) subordinate the claims of our holders of common stock to our assets in the event of our liquidation.

The borrowing base under our secured lending facility presently is $25.0 million and all borrowings under the facility are secured by a majority of our oil and natural gas assets. The proposed terms of our New Revolving Credit Facility also provide that borrowings will be secured by a majority of our oil and natural gas assets. Borrowings outside the facility, or, once adopted, the New Revolving Credit Facility, may have to be unsecured, and such borrowings, if obtainable, may have a higher interest rate, which would increase debt service costs could negatively impact our operating results. 

Our Certificate of Incorporation does not provide stockholders the pre-emptive right to buy shares from us. As a result, stockholders will not have the automatic ability to avoid dilution in their percentage ownership of us.

The underwriters of this offering may waive or release parties to the lock-up agreements entered into in connection with this offering, which could adversely affect the price of our common stock.

We, Yorktown and its affiliates and each of our directors and executive officers have entered into lock-up agreements with respect to their common stock, pursuant to which they are subject to certain resale restrictions for a period of 180 days following the date of this prospectus. The underwriter, at any time and without notice, may release all or any portion of the common stock subject to the foregoing lock-up agreements. If the restrictions under the lock-up agreements are waived, then common stock will be available for sale into the public markets, which could cause the market price of our common stock to decline and impair our ability to raise capital.