RISK FACTORS

Investing in shares of 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 in evaluating an investment in our common stock. If any of the following risks were to occur, our business, financial condition, results of operations, and cash flows could be materially adversely affected. In that case, the trading price of our common stock could decline and you could lose all or part of your investment. Additional risks not presently known to us or that we currently deem immaterial may also impair our business operations.

Risks related to our business

We may not be able to achieve our projected financial results or service our debt.

Although the financial projections recently disclosed in our Disclosure Statement filed with the Bankruptcy Court represent our view based on then current known facts and assumptions about the future operations of the Company there is no guarantee that the financial projections will be realized. We may not be able to meet the projected financial results or achieve projected revenues and cash flows assumed in projecting future business prospects. To the extent we do not meet the projected financial results or achieve projected revenues and cash flows, we may lack sufficient liquidity to continue operating as planned after emergence from bankruptcy and may be unable to service our debt obligations as they come due or may not be able to meet our operational needs. Any one of these failures may preclude us from, among other things: (a) taking advantage of future opportunities; (b) growing our businesses; or (c) responding to future changes in the oil and gas industry. Further, our failure to meet the projected financial results or achieve projected revenues and cash flows could lead to cash flow and working capital constraints, which constraints may require us to seek additional working capital. We may not be able to obtain such working capital when it is required.

Oil and gas price volatility, including the recent significant decline in oil and gas prices, have adversely affected and continue to adversely affect our financial condition, financial results, cash flows, access to capital and ability to grow.

Our future financial condition, revenues, results of operations, rate of growth and the carrying value of our oil and natural gas properties depend primarily upon the prices we receive for our oil and natural gas production. Oil and natural gas prices historically have been volatile and are likely to continue to be volatile in the future, especially given current geopolitical conditions. This price volatility also affects the cash flow we will have available for capital expenditures as well as our ability to borrow money or raise additional capital. The prices for oil and natural gas are subject to a variety of factors that are beyond our control. These factors include, but are not limited to, the following:

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These factors and the volatility of the energy markets generally make it extremely difficult to predict future oil and gas price movements with any certainty. For example, during the five years prior to December 31, 2016, the posted price for West Texas Intermediate light sweet crude oil, commonly referred to as West Texas Intermediate, has ranged from a low of $26.19 per Bbl in February 2016 to a high of $110.62 per Bbl in September 2013. The Henry Hub daily spot market price of natural gas has ranged from a low of $1.49 per MMBtu in March 2016 to a high of $8.15 per MMBtu in February 2014. Since mid-2014, oil and natural gas prices have declined significantly, due in large part to increasing supplies and weakening demand growth. The significant decline in oil and natural gas prices beginning in the second half of 2014 and continuing today has materially adversely impacted our operations, the value of our estimated proved reserves and, in turn, the market value used by the lenders to determine our borrowing base.

Extended periods of continuing lower oil and natural gas prices will not only reduce our revenue but also will reduce the amount of oil and natural gas we can produce economically, and as a result, would have a material adverse effect on our financial condition, results of operations, and reserves. During periods of low commodity prices we shut in or curtail production from additional wells and defer drilling new wells, challenging our ability to produce at commercially paying quantities required to hold our leases. A reduction in production could result in a shortfall in our expected cash flows and require us to reduce our capital spending or borrow funds to cover any such shortfall. Any of these factors could negatively impact our ability to replace our production and our future rate of growth.

A decline in prices from current levels may lead to additional write downs of the carrying values of our oil and natural gas properties in the future which could negatively impact results of operations.

We utilize the full cost method of accounting for costs related to our oil and natural gas properties. Under this method, all costs incurred for both productive and nonproductive properties are capitalized and amortized on an aggregate basis using the units-of-production method. However, these capitalized costs are subject to a ceiling test that limits such pooled costs to the aggregate of the present value of estimated future net revenues attributable to proved oil and natural gas reserves discounted at 10% net of tax considerations, plus the cost of unproved properties not being amortized. The full cost ceiling is evaluated at the end of each quarter using the SEC prices for oil and natural gas in effect at that date. A write-down of oil and natural gas properties does not impact cash flow from operating activities, but does reduce net income. Once incurred, a write-down of oil and natural gas properties is not reversible at a later date. We recorded ceiling test write-downs of $281 million in 2016 and $1.5 billion in 2015. Crude oil prices have staged a moderate recovery in late 2016 and early 2017 from previous historic lows in early 2016. However, oil and natural gas prices are volatile and this and other factors, without mitigating circumstances, could require us to further write down capitalized costs and incur corresponding noncash charges to earnings. Since the prices used in the cost ceiling are based on a trailing twelve-month period, the full impact of a sudden price decline is not recognized immediately.

A significant portion of total proved reserves as of December 31, 2016, are undeveloped, and those reserves may not ultimately be developed.

As of December 31, 2016, approximately 57%, of our estimated proved reserves (by volume) were undeveloped. These reserve estimates reflect our plans to make significant capital expenditures to convert our proved undeveloped reserves into proved developed reserves at a total estimated undiscounted cost of $1.0 billion. You should be aware that actual development costs may exceed estimates, development may not occur as scheduled and results may not be as estimated. If we choose not to develop our proved undeveloped reserves, or if we are not otherwise able to successfully develop them, we will be required to remove the associated volumes from our reported proved reserves.

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In addition, under the SEC’s reserve reporting rules, proved undeveloped reserves generally may be booked only if they relate to wells scheduled to be drilled within five years of the date of booking or unless specific circumstances justify a longer time. A substantial portion of our proved undeveloped reserves are scheduled to be developed over a period extending beyond the typical five year time frame. These reserves are related to our Active EOR Areas and we believe that the specific facts and circumstances of the ongoing projects within these areas justify a longer development time frame. We may be required to write off any reserves that are not developed within this five-year time frame in the event that the SEC does not agree that the specific circumstances related to the longer-term reserves are otherwise exempted from the five-year reporting rules.

The actual quantities and present value of our proved reserves may be lower than we have estimated.

Estimating quantities of proved oil and natural gas reserves is a complex process. The quantities and values of our proved reserves in the projections are only estimates and subject to numerous uncertainties. The accuracy of any reserves estimate is a function of the quality of available data and of engineering and geological interpretation. These estimates depend on assumptions regarding quantities and production rates of recoverable oil and natural gas reserves, future prices for oil and natural gas, timing and amounts of development expenditures and operating expenses, all of which will vary from those assumed in our estimates. If the variances in these assumptions are significant, many of which are based upon extrinsic events we cannot control, they could significantly affect these estimates. Any significant variance from the assumptions used could result in the actual amounts of oil and natural gas ultimately recovered and future net cash flows being materially different from the estimates in our reserves reports. In addition, results of drilling, testing, production, and changes in prices after the date of the estimates of our reserves may result in substantial downward revisions. These estimates may not accurately predict the present value of future net cash flows from our oil and natural gas reserves.

You should not assume that the present values referred to in this prospectus represent the current market value of our estimated oil and natural gas reserves. The timing of production and expenses associated with the development and production of oil and natural gas properties will affect both the timing of actual future net cash flows from our proved reserves and their present value. In accordance with requirements of the SEC, the estimates of present values are based on a twelve-month average price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the twelve-month period prior to the end of the reporting period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. Actual future prices and costs may be materially higher or lower than the prices and costs as of the date of these estimates. Our December 31, 2016 reserve report used SEC pricing of $2.49 per Mcf for natural gas and $42.75 per Bbl for oil.

The development of the proved undeveloped reserves in our Active EOR Areas may take longer and may require higher levels of capital expenditures than we currently anticipate.

As of December 31, 2016, undeveloped reserves in our Active EOR Areas c omprised 55% of our total estimated proved reserves. As of December 31, 2016, we expect to incur future development costs of $0.9 billion, including $323 million for CO ₂ purchase, compression and transportation, over the next 30 years to substantially develop these reserves. The future development costs for our Active EOR Areas are 86% of our total estimated future development and abandonment costs of $1.1 billion as of December 31, 2016. Development of these reserves may take longer and require higher levels of capital expenditures than we currently anticipate. In addition, the development of these reserves will require the use of EOR techniques, including water flood and CO ₂ injection installations, the success of which is still subject to interpretation and predictability by reservoir engineers. Therefore, ultimate recoveries from these fields may not match current expectations.

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

Our New Credit Facility imposes operating and financial restrictions on us. These restrictions limit our ability and that of our restricted subsidiaries to, among other things:

The restrictions contained in the New Credit Facility could:

Our New Credit Facility includes provisions that require mandatory prepayment of outstanding borrowings and/or a borrowing base redetermination when we make asset dispositions over a certain threshold, which could limit our ability to generate liquidity from asset sales. Also, our New Credit Facility requires us to maintain compliance with specified financial ratios and satisfy certain financial condition tests. Our ability to comply with these ratios and financial condition tests may be affected by events beyond our control and, as a result, we may be unable to meet these ratios and financial condition tests. These financial ratio restrictions and financial condition tests could limit our ability to obtain future financings, make needed capital expenditures, withstand a continued downturn in our business or a downturn in the economy in general or otherwise conduct necessary corporate activities. Further declines in oil and natural gas prices could result in our failing to meet one or more of the financial covenants under our New Credit Facility, which could require us to refinance or amend such obligations resulting in the payment of consent fees or higher interest rates, or require us to raise additional capital at an inopportune time or on terms not favorable to us.

A breach of any of these covenants or our inability to comply with the required financial ratios or financial condition tests could result in a default under our New Credit Facility. A default under our New Credit Facility, if not cured or waived, could result in acceleration of all indebtedness outstanding thereunder, which in turn would trigger cross-acceleration and cross-default rights under our other debt.

Provisions in the Stockholders Agreement may restrict, delay or prevent certain transactions that would be beneficial to our stockholders and our business, which could adversely affect our ability to conduct business.

The Stockholders Agreement contains certain provisions requiring the approval of 66 2/3% of our stockholders, thereby restricting the ability of our board of directors to effect certain transactions or other advantageous actions. Such provisions requiring the approval of holders of at least 66 2/3% of our outstanding common stock could make it more difficult or impossible for us to enter into transactions or agreements that are important to our business, even if the transaction or agreement would be beneficial to our stockholders, including:

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Competition in the oil and natural gas industry is intense and many of our competitors have greater financial and other resources than we do.

We operate in the highly competitive areas of oil and natural gas production, acquisition, development, and exploration and face intense competition from both major and other independent oil and natural gas companies:

Many of our competitors have financial and other resources substantially greater than ours, and some of them are fully integrated oil companies. These companies may be able to pay more for development prospects and productive oil and natural gas properties and may be able to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. Our ability to develop our oil and natural gas properties and to acquire additional properties in the future will depend upon our ability to successfully conduct operations, select suitable prospects and consummate transactions in this highly competitive environment.

Drilling wells is speculative and capital intensive.

Developing and exploring properties for oil and natural gas requires significant capital expenditures and involves a high degree of financial risk, including the risk that no commercially productive oil or natural gas reservoirs will be encountered. The budgeted costs of drilling, completing, and operating wells are often exceeded and can increase significantly when drilling costs rise. If our cash flow from operations is not sufficient to fund our capital expenditure budget, we may not be able to access additional bank debt or other methods of financing on commercially reasonable terms to meet these requirements. If revenue were to decrease as a result of lower oil and natural gas prices or decreased production, and our access to capital were limited, we would have a reduced ability to replace our reserves, which may have an adverse effect on our results of operations and financial condition. In addition, drilling may be unsuccessful for many reasons, including title problems, weather, cost overruns, equipment shortages, and mechanical difficulties. Moreover, the successful drilling or completion of an oil or natural gas well does not ensure a profit on investment. Exploratory wells bear a much greater risk of loss than development wells.

If we are not able to replace reserves, we may not be able to sustain production.

Our future success depends largely upon our ability to find, develop, or acquire additional oil and natural gas reserves that are economically recoverable. Unless we replace the reserves we produce through successful development, exploration or acquisition activities, our proved reserves and production will decline over time. Recovery of such reserves will require significant capital expenditures and successful drilling and EOR operations. Our December 31, 2016 reserve estimates reflect that our production rate on current proved developed reserve properties will decline at annual rates of approximately 15%, 13%, and 15% for the next three years. Thus, our future oil and natural gas reserves and production and, therefore, our financial condition, results of operations, and cash flows are highly dependent on our success in efficiently developing our current reserves and economically discovering or acquiring additional recoverable reserves. Due to lower oil prices, we have significantly reduced capital expenditures in 2015 and 2016 compared to 2014 which has therefore reduced our replacement of reserves when compared to previous years.

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Development and exploration drilling may not result in commercially productive reserves.

Drilling activities are subject to many risks, including the risk that commercially productive reservoirs will not be encountered. We cannot assure you that new wells we drill will be productive or that we will recover all or any portion of our investment in such wells. The seismic data and other technologies we use do not allow us to know conclusively prior to drilling a well that oil or natural gas is present or may be economically recovered and/or produced. Drilling for oil and natural gas often involves unprofitable efforts, not only from dry wells but also from wells that are productive but do not produce sufficient net reserves to return a profit at then-realized prices after deducting drilling, operating and other costs. The cost of drilling, completing and operating a well is often uncertain, and cost factors can adversely affect the economics of a project. These risks are magnified when operating in an environment of low crude oil prices. Further, our drilling operations may be curtailed, delayed or canceled as a result of numerous factors, including:

If, for any reason, we are unable to economically recover reserves through our exploration and drilling activities, our results of operations, cash flows, growth, and reserve replenishment may be materially affected.

Oil and natural gas drilling and production operations can be hazardous and may expose us to uninsurable losses or other liabilities.

Oil and natural gas operations are subject to many risks, including well blowouts, cratering, explosions, pipe failure, fires, formations with abnormal pressures, uncontrollable flows of oil, natural gas, brine or well fluids, hydraulic fracturing fluids, toxic gas or other pollutants and other environmental and safety hazards and risks. Our drilling operations involve risks from high pressures and from mechanical difficulties such as stuck pipes, collapsed casings and separated cables. If any of these events occur, we could sustain substantial losses as a result of:

Our liability for environmental hazards sometimes includes those created on properties prior to the date we acquired or leased them. While we maintain insurance against some, but not all, of the risks described above, our insurance may not be adequate to cover any or all resulting losses or liabilities. Moreover, if we experience more insurable events, our annual premiums may increase further or we may not be able to obtain any such insurance on commercially reasonable terms. The occurrence of, or failure by us to obtain or maintain adequate insurance coverage for, any of the events listed above could have a material adverse effect on our financial condition and results of operations, as well as our growth, exploration, and employee recruitment activities.

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We may not have sufficient funds to repay bank borrowings if required as a result of a borrowing base redetermination.

Availability under our New Credit Facility Revolver (the “New Revolver”) is subject to a borrowing base, initially set at $225.0 million as of March 21, 2017, and which is redetermined by the banks semi-annually on May 1 and November 1 of each year, commencing on May 1, 2018. In addition, the banks may request a borrowing base redetermination once between each scheduled redetermination and in the event of early termination of our derivative contracts. Dispositions of our oil and natural gas assets or incurrence of permitted senior unsecured debt may also trigger automatic reductions in our borrowing base. If the outstanding borrowings under our New Revolver were to exceed the borrowing base as a result of a redetermination, we would be required to eliminate this excess. Within 10 days after receiving notice of the new borrowing base, we would be required to make an election: (1) to repay a portion of our bank borrowings in the amount of the excess either in a lump sum within 45 days or in equal monthly installments over a six-month period; (2) to submit within 45 days additional unburdened oil and gas properties to be mortgaged sufficient to eliminate the excess or (3) to eliminate the excess through a combination of repayments and the submission of additional oil and gas properties within 45 days. If we are forced to repay a portion of our bank borrowings, we may not have sufficient funds to make such repayments. If we do not have sufficient funds and are otherwise unable to negotiate renewals of our borrowings or arrange new financing, we may have to sell significant assets. Asset sales may also reduce available collateral and availability under the New Credit Facility and could have a material adverse effect on our business and financial results. In addition, we cannot be certain that our cash flow will be sufficient to allow us to pay the principal and interest on our debt and meet our other obligations.

Resolution of litigation could materially affect our financial position and results of operations.

We have been named as a defendant in certain lawsuits. See “Business—Legal Proceedings.” In some of these suits, our liability for potential loss upon resolution may be mitigated by insurance coverage. To the extent that potential exposure to liability is not covered by insurance or insurance coverage is inadequate, we could incur losses that could be material to our financial position or results of operations in future periods. We may also become involved in litigation over certain issues related to the Reorganization Plan, including the proposed treatment of certain claims thereunder. The outcome of such litigation could have a material impact on our financial position or results of operations in future periods.

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

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

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As a result of any of the above or an operator’s failure to act in ways that are in our best interest, our allocated production revenues and results of operations could be adversely affected.

If the third parties we rely on for gathering and distributing our oil and natural gas are unable to meet our needs for such services and facilities, our future exploration and production activities could be adversely affected.

The marketability of our production depends upon the proximity of our reserves to, and the capacity of, third-party facilities and third-party services, including oil and natural gas gathering systems, pipelines, trucking or terminal facilities, and refineries or processing facilities. Such third parties are subject to federal and state regulation of the production and transportation of oil and natural gas. If such third parties are unable to comply with such regulations and we are unable to replace such service and facilities providers, we may be required to shut-in producing wells or delay or discontinue development plans for our properties. A shut-in, delay or discontinuance could adversely affect our financial condition.

Limitations or restrictions on our ability to obtain water may have an adverse effect on our operating results.

Our operations require significant amounts of water for drilling and hydraulic fracturing. Limitations or restrictions on our ability to obtain water from local sources may require us to find remote sources. In addition, treatment and disposal or such water after use is becoming more highly regulated and restricted. Thus, costs for obtaining and disposing of water could increase significantly, potentially limiting our ability to engage in hydraulic fracturing. This could have a material adverse effect on our operations.

We are subject to complex laws and regulations, including environmental and safety regulations, which can adversely affect the cost, manner, and feasibility of doing business.

Our exploration, production, and marketing operations are subject to complex and stringent federal, state, and local laws and regulations governing, among other things: land use restrictions, drilling bonds and other financial responsibility requirements, reporting and other requirements with respect to emissions of greenhouse gases and air pollutants, utilization and pooling of properties, habitat and endangered species protection, reclamation and remediation, well stimulation processes, produced water disposal, CO ₂ pipeline requirements, safety precautions, operational reporting, and tax requirements. These laws, regulations and related public policy considerations affect the costs, manner, and feasibility of our operations and require us to make significant expenditures in order to comply. Failure to comply with these laws and regulations may result in the assessment of administrative, civil, and criminal penalties, the imposition of investigatory and remedial obligations, and the issuance of injunctions that could limit or prohibit our operations. In addition, some of these laws and regulations may impose joint and several, strict liability for contamination resulting from spills, discharges, and releases of substances, without regard to fault or the legality of the original conduct. Under such laws and regulations, we could be required to remove or remediate previously disposed substances and property contamination, including wastes disposed or released by prior owners or operators. Changes in, or additions to, environmental laws and regulations occur frequently, and any changes or additions that result in more stringent and costly waste handling, storage, transport, disposal, cleanup or other environmental protection requirements could have a material adverse effect on our operations and financial position.

Future legislation may result in the elimination of certain U.S. federal income tax deductions currently available with respect to oil and natural gas exploration and development. Additionally, future federal and state legislation may impose new or increased taxes or fees on oil and natural gas extraction.

In recent years, legislation has been proposed that would, if enacted into law, make significant changes to U.S. federal and state income tax laws, including the elimination of certain U.S. federal income tax benefits and deductions currently available to oil and gas companies. Such changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and gas properties, (ii) the increase of the amortization period of geological and geophysical expenses, (iii) the elimination of current deductions for intangible drilling and development costs; and (iv) the elimination of the deduction for certain U.S. production activities. Moreover, other generally applicable features of proposed tax reform legislation, such as changes to the deductibility of interest expense, the cost recovery rules and the types of income subject to federal income taxes could impact our income taxes and resulting operating cash flow. Although it is currently unclear whether any such proposals will be enacted

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or what form they might possibly take, the President and Congress could include some or all of these proposals as part of anticipated tax reform legislation to accompany lower U.S. federal income tax rates. The passage of such legislation or any other similar change in U.S. federal income tax law could eliminate, reduce or postpone certain tax deductions that are currently available to us or otherwise affect our U.S. federal income tax liability and any such change could negatively affect our financial condition and results of operations. Additionally, legislation could be enacted that imposes new fees or increases the taxes on oil and natural gas extraction, which could result in increased operating costs and/or reduced consumer demand for petroleum products and thereby affect the prices we receive for our commodity products.

Potential legislative and regulatory actions could negatively affect our business.

In addition to the Safe Drinking Water Act and other potential regulations on hydraulic fracturing practices, numerous other legislative and regulatory proposals affecting the oil and gas industry have been introduced, are anticipated to be introduced, or are otherwise under consideration, by Congress, state legislatures and various federal and state agencies. Among these proposals are: (1) climate change/carbon tax legislation introduced in Congress, and EPA regulations to reduce greenhouse gas emissions; and (2) legislation introduced in Congress to impose new taxes on, or repeal various tax deductions available to, oil and gas producers, such as the current tax deductions for intangible drilling and development costs, which deductions, if eliminated, could raise the cost of energy production, reduce energy investment and affect the economics of oil and gas exploration and production activities. Any of the foregoing described proposals could affect our operations, and the costs thereof. The trend toward stricter standards, increased oversight and regulation and more extensive permit requirements, along with any future laws and regulations, could result in increased costs or additional operating restrictions which could have an effect on demand for oil and natural gas or prices at which it can be sold. However, until such legislation or regulations are enacted or adopted into law and thereafter implemented, it is not possible to gauge their impact on our future operations or their results of operations and financial condition.

Federal and state legislation and regulatory initiatives relating to hydraulic fracturing and waste water injector wells could result in increased costs and additional operating restrictions or delays.

Our hydraulic fracturing operations are a significant component of our business, and it is an important and common practice that is used to stimulate production of hydrocarbons, particularly oil and natural gas, from tight formations, including shales. The process, which involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production, is typically regulated by state oil and natural gas commissions. However, federal agencies have asserted regulatory authority over certain aspects of the process. For example, in May 2014, the EPA issued an Advanced Notice of Proposed Rulemaking seeking comment on the development of regulations under the Toxic Substances Control Act to require companies to disclose information regarding the chemicals used in hydraulic fracturing. Beginning in August 2012, the EPA issued a series of rules under the CAA that establish new emission control requirements for emissions of volatile organic compounds and methane from certain oil and natural gas production and natural gas processing operations and equipment. And in March 2015, the Bureau of Land Management (“BLM”) finalized a rule governing hydraulic fracturing on federal lands, implementation of which has been stayed pending the resolution of legal challenges. Further, legislation to amend the Safe Drinking Water Act to repeal the exemption for hydraulic fracturing (except when diesel fuels are used) from the definition of “underground injection” and require federal permitting and regulatory control of hydraulic fracturing, as well as legislative proposals to require disclosure of the chemical constituents of the fluids used in the fracturing process, have been proposed in recent sessions of Congress. Several states and local jurisdictions in which we operate also have adopted or are considering adopting regulations that could restrict or prohibit hydraulic fracturing in certain circumstances, impose more stringent operating standards and/or require the disclosure of the composition of hydraulic fracturing fluids.

More recently, federal and state governments have begun investigating whether the disposal of produced water into underground injection wells (and to a lesser extent, hydraulic fracturing) has caused increased seismic activity in certain areas. In response, some states, including states in which we operate, have imposed additional requirements on the construction and operation of underground disposal wells. For example, the Oklahoma Corporation Commission’s Oil and Gas Conservation Division and the Oklahoma Geologic Survey recently released well completion seismicity guidance, which requires operators to take certain prescriptive actions, including mitigation, following anomalous seismic activity within 1.25 miles of hydraulic fracturing operations.

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These developments, as well as increased scrutiny of hydraulic fracturing and underground injection activities by state and municipal authorities may result in additional levels of regulation or complexity with respect to existing regulations that could lead to operational delays or increased operating costs and could result in additional regulatory burdens that could make it more difficult to perform hydraulic fracturing and increase our cost of compliance and doing business.

Studies by both state or federal agencies demonstrating a correlation between earthquakes and oil and natural gas activities could result in increased regulatory and operational burdens.

In recent years, Oklahoma has experienced a significant increase in earthquakes and other seismic activity. On April 21, 2015, the Oklahoma Geologic Survey (“OGS”) issued a document entitled “Statement of Oklahoma Seismicity,” in which the agency states “[t]he OGS considers it very likely that the majority of recent earthquakes, particularly those in central and north-central Oklahoma, are triggered by the injection of produced water in disposal wells.” The Oklahoma Corporation Commission (“OCC”) has issued directives restricting injection of high volumes of water into the Arbuckle formation and into the crystalline basement below within a specified area of interest (“AOI”) in Central and Western Oklahoma. In the Spring of 2016 the OCC issued Regional Earthquake Response Plans for Western Oklahoma, Combined, the Plans expanded the 2015 AOI to include more than 10,000 square miles and more than 600 Arbuckle disposal wells, resulting in a reduction of more than 800,000 barrels per day from the 2015 average injection volumes. We operate 16 wells in the AOI and are fully compliant with all regulations relating to the disposal of produced water. In addition, in September and November of 2016 the OCC issued additional directives requiring modification of disposal in wells in the vicinity of Pawnee and Cushing, Oklahoma requiring salt water disposal wells to be shut in or to reduce injection volumes into salt water disposal wells in the area. We did not operate any of the disposal wells in the additional area. On February 24, 2017, the OCC issued a new directive aimed at limiting the future growth of disposal rates into the Arbuckle by capping disposal volumes in the AOI, even those not operating under currently permitted volumes, to the thirty day disposal average. Although we continue to operate disposal wells in the area, at this time our operations have not been affected. We cannot predict whether future regulatory actions will result in further expansion of this “area of interest” or new or additional regulations by the OCC or other agencies with jurisdiction over our operations. Any such expansion or new regulation could result in additional levels of regulation, or increased complexity with respect to existing regulations, that could lead to operational delays or increased operating costs and result in additional regulatory burdens that could make it more difficult to inject produced water into disposal wells, and may increase our costs of compliance and doing business. In addition, even though we have conducted our operations in compliance with applicable laws, the increase in media and regulatory attention to the possible connection between seismic activity and produced water injection has led to litigation filed against us and other oil and gas producers requesting compensation for damages, including demands for earthquake insurance premiums on a going forward basis. We cannot predict the outcome of this litigation or provide assurances that other similar claims will not be filed against us in the future.

We are responsible for the decommissioning, abandonment, and reclamation costs for our facilities.

We are responsible for compliance with all applicable laws and regulations regarding the decommissioning, abandonment and reclamation of our facilities at the end of their economic life, the costs of which may be substantial. It is not possible to predict these costs with certainty since they will be a function of regulatory requirements at the time of decommissioning, abandonment and reclamation. We may, in the future, determine it prudent or be required by applicable laws or regulations to establish and fund one or more decommissioning, abandonment and reclamation reserve funds to provide for payment of future decommissioning, abandonment and reclamation costs, which could decrease funds available to service debt obligations. In addition, such reserves, if established, may not be sufficient to satisfy such future decommissioning, abandonment and reclamation costs and we will be responsible for the payment of the balance of such costs.

Costs of environmental liabilities could exceed our estimates and adversely affect our operating results.

Our operations are subject to numerous environmental laws and regulations, which obligate us to install and maintain pollution controls and to clean up various sites at which regulated materials may have been disposed of or released. It is not possible for us to estimate reliably the amount and timing of all future expenditures related to environmental matters because of:

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Although we believe we have established appropriate reserves for known liabilities, including cleanup costs, we could be required to set aside additional reserves in the future due to these uncertainties, incur material cleanup costs, other liabilities, and/or expend significant sums to defend ourselves against litigation related to legacy environmental issues, which could have an adverse effect on our operating results.

Our use of derivative instruments could result in financial losses or reduce our income.

To reduce our exposure to the volatility in the price of oil and gas and provide stability to cash flows, we enter into derivative positions. Our commodity hedges are currently comprised of fixed price swaps and collars with financial institutions. The volumes and average notional prices of these hedges are disclosed in “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Quantitative and Qualitative Disclosures About Market Risk.”

Derivative instruments expose us to risk of financial loss in some circumstances, including when:

Derivatives also expose us to risk of income reduction as derivative instruments may limit the benefit we would receive from increases in the prices for oil and natural gas. Additionally, none of our derivatives are classified as hedges for accounting purposes and therefore must be adjusted to fair value through income each reporting period.

While the primary purpose of our derivative transactions is to protect ourselves against the volatility in oil and natural gas prices, under certain circumstances, or if hedges are discontinued, or terminated for any reason, we may incur substantial losses in closing out our positions, which could have a material adverse effect on our financial condition, results of operations, and cash flows.

We are subject to financing and interest rate exposure risks.

Our future success depends on our ability to access capital markets and obtain financing on reasonable terms. Our ability to access financial markets and obtain financing on commercially reasonable terms in the future is dependent on a number of factors, many of which we cannot control, including changes in:

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Assuming a constant debt level of $375.0 million, equal to our borrowing base as of March 21, 2017 under the senior secured revolving loan of our New Credit Facility and our term loan under the same facility, the cash flow impact for a 12-month period resulting from a 100 basis point movement in interest rates, regardless of whether the spread widens or tightens, would be $3.8 million. As a result, any increases in our interest rates, or our inability to access the equity markets on reasonable terms, could have an adverse impact on our financial condition, results of operations, and growth prospects.

Unusual weather patterns or natural disasters, whether due to climate change or otherwise, could negatively impact our financial condition.

Our business depends, in part, on normal weather patterns across the United States. Natural gas demand and prices are particularly susceptible to seasonal weather trends. Warmer than usual winters can result in reduced demand and high season-end storage volumes, which can depress prices to unacceptably low levels. In addition, because a majority of our properties are located in Oklahoma and Texas, our operations are constantly at risk of extreme adverse weather conditions such as freezing rain, tornadoes and hurricanes. Any unusual or prolonged adverse weather patterns in our areas of operations or markets, whether due to climate change or otherwise, could have a material and adverse impact on our business, financial condition and cash flow. In addition, our business, financial condition and cash flow could be adversely affected if the businesses of our key vendors, purchasers, contractors, suppliers or transportation service providers were disrupted due to severe weather, such as freezing rain, hurricanes or floods, whether due to climate change or otherwise.

Changes in, or challenges to, our rates and other terms and conditions of service could have a material adverse effect on our financial condition and results of operations.

The rates charged by certain of our pipeline systems are regulated by the Federal Energy Regulatory Commission, or FERC, state regulatory agencies, or both. These regulatory agencies also regulate other terms and conditions of the services these pipeline systems provide, including the types of services we may offer. If one of these regulatory agencies, on its own initiative or due to challenges by third parties, were to lower our tariff rates or deny any rate increase or other material changes to the types, or terms and conditions, of service we might propose, the profitability of our pipeline businesses would suffer. If we were permitted to raise our tariff rates for a particular pipeline, there might be significant delay between the time the tariff rate increase is approved and the time that the rate increase actually goes into effect, which if delayed could further reduce our cash flow. Furthermore, competition from other pipeline systems may prevent us from raising our tariff rates even if regulatory agencies permit us to do so. The regulatory agencies that regulate our systems periodically implement new rules, regulations and terms and conditions of services subject to their jurisdiction. New initiatives or orders may adversely affect the rates charged for our services or otherwise adversely affect our financial condition, results of operations and cash flows.

A change in the jurisdictional characterization of our assets, or a change in policy, could result in increased regulation of our assets which could materially affect our financial condition, results of operations and cash flows and our ability to make cash distributions to our unitholders .

Certain of our pipeline assets are natural gas gathering facilities. Unlike interstate natural gas transportation facilities, natural gas gathering facilities are exempt from the jurisdiction of the FERC under the Natural Gas Act of 1938, or NGA. Although the FERC has not made a formal determination with respect to all of our facilities we believe to be gathering facilities, we believe that these pipelines meet the traditional tests that the FERC has used to determine that a pipeline is a gathering pipeline and is therefore not subject to FERC jurisdiction. The distinction between FERC-regulated transmission services and federally unregulated gathering services, however, has been the subject of substantial litigation, and the FERC determines whether facilities are gathering

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facilities on a case-by-case basis, so the classification and regulation of our gathering facilities is subject to change based on future determinations by the FERC, the courts or Congress. If the FERC were to consider the status of an individual facility and determine that the facility and/or services provided by it are not exempt from FERC regulation under the NGA and that the facility provides interstate service, the rates for, and terms and conditions of, services provided by such facility would be subject to regulation by the FERC under the NGA or the Natural Gas Policy Act of 1978, or NGPA. Such regulation could decrease revenue, increase operating costs, and, depending upon the facility in question, could adversely affect our financial condition, results of operations and cash flows. In addition, if any of our facilities were found to have provided services or otherwise operated in violation of the NGA or NGPA, this could result in the imposition of civil penalties, as well as a requirement to disgorge charges collected for such services in excess of the rate established by the FERC.

The absence of a quorum at FERC, if it persists, could limit our ability to construct new facilities and/or expand certain existing facilities, which could have a material and adverse impact on our business and result of operations.

FERC, or the Commission, oversees, among other matters, the interstate sale at wholesale and transportation of natural gas. FERC’s authority includes reviewing proposals to site, construct, expand and/or retire interstate natural gas pipeline facilities. As set forth in the Department of Energy Authorization Act (“DOE Act”), the Commission is composed of up to five Commissioners, who are to be appointed by the President and confirmed by the Senate. The DOE Act requires that at least three Commissioners be present “for the transaction of business.” Without such a quorum of three or more Commissioners, FERC is unable to act on matters that require a vote of its Commissioners. Norman Bay, a FERC Commissioner and former Chairman of the Commission, resigned effective February 3, 2017. With Commissioner Bay’s departure, only two FERC Commissioners remained in office, as there were already two vacancies prior to Commissioner Bay’s resignation. FERC has therefore lacked the quorum required for its Commissioners to issues orders and take other actions since February 3. While FERC staff may still issue certain routine or uncontested orders under authority delegated by the Commission while it had a quorum, and such delegated authority was broadened immediately prior to Commissioner Bay’s departure, FERC is currently unable to resolve contested cases or issue major new orders, such as certificates of public convenience and necessity for new interstate natural gas pipelines or the expansion of existing FERC-certificated pipelines. The current limitations on FERC’s ability to act have not had a material effect on our operations, but if the absence of a quorum continues for a long enough period of time, our ability to construct new facilities and/or expand the capacity of our pipelines could be materially affected. The absence of a quorum will continue until a new FERC Commissioner is nominated by the President and confirmed by the Senate, provided the two remaining FERC Commissioners remain in office. The President has not yet nominated any new FERC Commissioners to fill the vacancies.

Increased regulatory requirements regarding pipeline safety and integrity management may require us to incur significant capital and operating expenses to comply.

The ultimate costs of compliance with pipeline safety and integrity management regulations are difficult to predict. The majority of the compliance costs are for pipeline safety and integrity testing and the repairs found to be necessary. We plan to continue our efforts to assess and maintain the safety and integrity of our existing and future pipelines as required by the DOT and PHMSA rules. The results of these tests could cause us to incur significant and unanticipated capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operation of our pipelines. In addition, new laws and regulations that may be enacted in the future, or a revised interpretation of existing laws and regulations, could significantly increase the amount of these costs. We cannot be assured about the amount or timing of future expenditures for pipeline integrity regulation, and actual future expenditures may be different from the amounts we currently anticipate. Revised or additional regulations that result in increased compliance costs, or additional operating restrictions, could have a material adverse effect on our business, financial position, results of operations and prospects.

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The recent adoption of derivatives legislation by the U.S. Congress could have an adverse effect on us and our ability to hedge risks associated with our business.

The Dodd-Frank Act requires the Commodities Futures Trading Commission (the “CFTC”) and the SEC to promulgate rules and regulations establishing federal oversight and regulation of the over-the-counter derivatives market and entities that participate in that market including swap clearing and trade execution requirements. New or modified rules, regulations or requirements may increase the cost and availability to the counterparties of our hedging and swap positions which they can make available to us, as applicable, and may further require the counterparties to our derivative instruments to spin off some of their derivative activities to separate entities which may not be as creditworthy as the current counterparties. Any changes in the regulations of swaps may result in certain market participants deciding to curtail or cease their derivative activities.

While many rules and regulations have been promulgated and are already in effect, other rules and regulations remain to be finalized or effectuated, and therefore, the impact of those rules and regulations on us is uncertain at this time. The Dodd-Frank Act, and the rules promulgated thereunder, could (i) significantly increase the cost, or decrease the liquidity, of energy-related derivatives that we use to hedge against commodity price fluctuations (including through requirements to post collateral), (ii) materially alter the terms of derivative contracts, (iii) reduce the availability of derivatives to protect against risks we encounter, and (iv) increase our exposure to less creditworthy counterparties.

Shortages of oil field equipment, services and qualified personnel could reduce our cash flow and adversely affect results of operations .

The demand for qualified and experienced field personnel to drill wells and conduct field operations, geologists, geophysicists, engineers and other professionals in the oil and natural gas industry can fluctuate significantly, often in correlation with oil and natural gas prices, causing periodic shortages in such personnel. The severe industry decline over the past couple of years has resulted in a large displacement of experienced personnel through layoffs and many of the affected personnel have moved on to careers in other industries. This structural shift in available workforce may be impactful in future periods. Recently the industry has experienced a modest price recovery that began in late 2016. This has resulted in an increase in the number of active drilling rigs and stimulated demand for crews and associated supplies, oilfield equipment and services, and personnel. As such we may encounter shortages of these resources as well as increased prices. These types of shortages or price increases could significantly decrease our profit margin, cash flow and operating results and/or restrict or delay our ability to drill those wells and conduct those operations that we currently have planned and budgeted, causing us to miss our forecasts and projections.

A significant portion of our operations are located in Oklahoma and the Texas Panhandle, making us vulnerable to risks associated with operating in a limited number of major geographic areas.

As of March 31, 2017, almost 100% of our proved reserves and production was located in the Mid-Continent geographic area. This concentration could disproportionately expose us to operational and regulatory risk in this area. This lack of diversification in location of our key operations could expose us to adverse developments in our operating areas or the oil and natural gas markets, including, for example, transportation or treatment capacity constraints, curtailment of production or treatment plant closures for scheduled maintenance. These factors could have a significantly greater impact on our financial condition, results of operations and cash flows than if our properties were more geographically diversified.

A cyber incident could result in information theft, data corruption, operational disruption, and/or financial loss.

Our business has become increasingly dependent on digital technologies to conduct day-to-day operations, including certain of their exploration, development and production activities. We depend on digital technology to estimate quantities of oil and gas reserves, process and record financial and operating data, analyze seismic and drilling information and in many other activities related to their business. Our technologies, systems and networks may become the target of cyber-attacks or information security breaches that could result in the disruption of our business operations. For example, unauthorized access to our seismic data, reserves information or other proprietary information could lead to data corruption, communication interruption, or other operational disruptions in our drilling or production operations. To date we have not experienced any material losses relating to cyber-attacks, however there can be no assurance that we will not suffer such losses in the future. As cyber threats continue to evolve, we may be required to expend significant additional resources to continue to modify or enhance their protective measures or to investigate and remediate any cyber vulnerabilities.

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

The EPA has determined that greenhouse gases present an endangerment to public health and the environment because such gases contribute to warming of the earth’s atmosphere and other climatic changes. Based on these findings, the EPA has adopted and implemented, and continues to adopt and implement, regulations that restrict emissions of greenhouse gases (“GHGs”) under existing provisions of the Clean Air Act (“CAA”). The EPA also requires the annual reporting of GHG emissions from certain large sources of GHG emissions in the United States, including certain oil and gas production facilities. The EPA has also taken steps to limit methane emissions from oil and gas production facilities. In addition, the U.S. Congress has from time to time considered adopting legislation to reduce emissions of GHGs and almost one-half of the states have already taken legal measures to reduce emissions of GHGs primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. The Kyoto Protocol to the United Nations Framework Convention on Climate Change became effective in February 2005. Under the Protocol, participating nations are required to implement programs to reduce emissions of greenhouse gases that are suspected of contributing to global warming. The United States was not currently a participant in the Protocol. In December 2015, the United States joined the international community at the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change in Paris, France. The resulting Paris Agreement calls for the parties to undertake “ambitious efforts” to limit the average global temperature, and to conserve and enhance sinks and reservoirs of greenhouse gases. The Paris Agreement entered into force in November 2016. The United States was one of over 70 nations that ratified or otherwise indicated an intention to comply with the agreement. On June 1, 2017 President Trump announced that the United States will withdraw and attempt to negotiate a different agreement. Restrictions on emissions of GHGs could adversely affect the natural gas industry by reducing demand for hydrocarbons and by making it more expensive to develop and produce hydrocarbons, either of which could have a material adverse effect on future demand for our services. Moreover, climate change may cause more extreme weather conditions and increased volatility in seasonal temperatures. Extreme weather conditions can interfere with our operations and increase our costs, and damage resulting from extreme weather may not be fully insured. For further discussion of climate change and the regulatory implications, please see “Business – Environmental Matters and Regulation – Greenhouse Gas Emissions.”

Risks related to our emergence from Chapter 11 bankruptcy

We recently emerged from bankruptcy, which could adversely affect our business and relationships.

It is possible that our having filed for bankruptcy and our recent emergence from the Chapter 11 bankruptcy proceedings could adversely affect our business and relationships with customers, vendors, royalty or working interest owners, contractors, employees or suppliers. Due to uncertainties, many risks exist, including the following:

The occurrence of one or more of these events could have a material and adverse effect on our operations, financial condition and reputation. We cannot assure you that having been subject to bankruptcy protection will not adversely affect our operations in the future.

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Our actual financial results after emergence from bankruptcy may not be comparable to our historical financial information as a result of the implementation of the Reorganization Plan and the transactions contemplated thereby and our adoption of fresh start accounting.

In connection with the Disclosure Statement we filed with the Bankruptcy Court, and the hearing to consider confirmation of the Reorganization Plan, we prepared projected financial information to demonstrate to the Bankruptcy Court the feasibility of the Reorganization Plan and our ability to continue operations upon our emergence from bankruptcy. Those projections were prepared solely for the purpose of the bankruptcy proceedings and have not been, and will not be, updated on an ongoing basis and should not be relied upon by investors. Although the financial projections disclosed in our Disclosure Statement filed with the Bankruptcy Court represent our view based on then current known facts and assumptions about the future operations of the Company there is no guarantee that the financial projections will be realized. We may not be able to meet the projected financial results or achieve projected revenues and cash flows assumed in projecting future business prospects. To the extent we do not meet the projected financial results or achieve projected revenues and cash flows, we may lack sufficient liquidity to continue operating as planned and may be unable to service our debt obligations as they come due or may not be able to meet our operational needs. Any one of these failures may preclude us from, among other things: (a) taking advantage of future opportunities; (b) growing our businesses; or (c) responding to future changes in the oil and gas industry. Further, our failure to meet the projected financial results or achieve projected revenues and cash flows could lead to cash flow and working capital constraints, which constraints may require us to seek additional working capital. We may not be able to obtain such working capital when it is required.

In addition, upon our emergence from bankruptcy, we adopted fresh start accounting, as a consequence of which our assets and liabilities were adjusted to fair values and our accumulated deficit was restated to zero. Accordingly, our future financial conditions and results of operations may not be comparable to the financial condition or results of operations reflected in the Company’s historical financial statements.

Upon our emergence from bankruptcy, the composition of our Board of Directors changed significantly.

Pursuant to the Reorganization Plan, the composition of the Board changed significantly. Upon emergence, the Board is now made up of seven directors, with a new non-executive Chairman of the Board, and of which six will not have previously served on the Board. The new directors have different backgrounds, experiences and perspectives from those individuals who previously served on the Board and, thus, may have different views on the issues that will determine the future of the Company. There is no guarantee that the new Board will pursue, or will pursue in the same manner, our current strategic plans. As a result, the future strategy and plans of the Company may differ materially from those of the past.

The ability to attract and retain key personnel is critical to the success of our business and may be affected by our emergence from bankruptcy.

The success of our business depends on key personnel. The ability to attract and retain these key personnel may be difficult in light of our emergence from bankruptcy, the uncertainties currently facing the business and changes we may make to the organizational structure to adjust to changing circumstances. We may need to enter into retention or other arrangements that could be costly to maintain. If executives, managers or other key personnel resign, retire or are terminated, or their service is otherwise interrupted, we may not be able to replace them in a timely manner and we could experience significant declines in productivity.

Our ability to utilize our net operating loss carryforwards (“NOLs”) may be limited as a result of our emergence from bankruptcy.

In general, Section 382 of the Internal Revenue Code (“IRC”) of 1986, as amended, provides an annual limitation with respect to the ability of a corporation to utilize its tax attributes, as well as certain built-in-losses, against future taxable income in the event of a change in ownership. Emergence from Chapter 11 bankruptcy proceedings resulted in a change in ownership for purposes of the IRC Section 382. The Company analyzed alternatives available within the IRC to taxpayers in Chapter 11 bankruptcy proceedings in order to minimize the impact of the ownership change and cancellation of indebtedness income on its tax attributes. Upon filing its 2017 U.S. Federal income tax return, the Company plans to elect an available alternative which would likely result in the

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Company experiencing a limitation that subjects existing tax attributes at emergence to an IRC Section 382 limitation that could result in some or all of the remaining net operating loss carryforwards expiring unused. However, the Company will continue to evaluate the remaining available alternative which would not subject existing tax attributes to an IRC Section 382 limitation.

Limitations imposed on our ability to use NOLs to offset future taxable income may cause U.S. federal income taxes to be paid earlier than otherwise would be paid if such limitations were not in effect and could cause such NOLs to expire unused, in each case reducing or eliminating the benefit of such NOLs. Similar rules and limitations may apply for state income tax purposes.

Risks relating to this offering

The market price of our common stock is volatile.

The trading price of our common stock and the price at which we may sell common stock in the future are subject to large fluctuations in response to any of the following:

We do not anticipate paying dividends on our common stock in the near future .

We have not paid any dividends on our common stock in either of the last two years and we do not currently anticipate paying any cash dividends on our common stock in the foreseeable future. We currently intend to retain all future earnings to fund the development and growth of our business. Any future determination relating to our dividend policy will be at the discretion of our board of directors and will depend on our results of operations, financial condition, capital requirements and other factors deemed relevant by our board. We are also restricted in our ability to pay dividends under our New Credit Facility.

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Certain anti-takeover provisions may affect your rights as a stockholder .

Our Third Amended and Restated Certificate of Incorporation (“Certificate of Incorporation”), which became effective upon our emergence from bankruptcy, authorizes our board of directors to set the terms of and issue preferred stock, subject to certain restrictions in our Stockholders Agreement as discussed under “Description of Capital Stock—Stockholders Agreement.” Our board of directors could use the preferred stock as a means to delay, defer or prevent a takeover attempt that a stockholder might consider to be in our best interest. In addition, our New Credit Facility contains terms that may restrict our ability to enter into change of control transactions, including requirements to repay borrowings under our New Credit Facility on a change in control. These provisions, along with specified provisions of the DGCL and our Certificate of Incorporation and our Amended and Restated Bylaws, may discourage or impede transactions involving actual or potential changes in our control, including transactions that otherwise could involve payment of a premium over prevailing market prices to holders of our common stock.

Sales of substantial amounts of shares of our common stock could cause the price of our common stock to decrease .

This prospectus covers the sale by selling stockholders of a substantial number of shares of our common stock. Our stock price may decrease due to the additional amount of shares available in the market as a result of sales under this prospectus.

There is a limited trading market for our securities and the market price of our securities is subject to volatility .

Upon our emergence from bankruptcy, our old common stock was cancelled and we issued new common stock. Our common stock is not listed on any national or regional securities exchange. The market price of our common stock could be subject to wide fluctuations in response to, and the level of trading that develops with our common stock may be affected by, numerous factors, many of which are beyond our control. These factors include, among other things, our new capital structure as a result of the transactions contemplated by the Reorganization Plan, our limited trading history subsequent to our emergence from bankruptcy, our limited trading volume, the concentration of holdings of our common stock, the lack of comparable historical financial information due to our adoption of fresh start accounting, actual or anticipated variations in our operating results and cash flow, the nature and content of our earnings releases, announcements or events that impact our products, customers, competitors or markets, business conditions in our markets and the general state of the securities markets and the market for energy-related stocks, as well as general economic and market conditions and other factors that may affect our future results, including those described under this “Risk Factors” and elsewhere in this prospectus. No assurance can be given that an active market will develop for the common stock or as to the liquidity of the trading market for the common stock. The common stock may be traded only infrequently in transactions arranged through brokers or otherwise, and reliable market quotations may not be available. Holders of our common stock may experience difficulty in reselling, or an inability to sell, their shares. In addition, if an active trading market does not develop or is not maintained, significant sales of our common stock, or the expectation of these sales, could materially and adversely affect the market price of our common stock.

There is currently no active public trading market for our Class A common stock or our Class B common stock. Therefore, you may be unable to liquidate your investment in our common stock.

Our Class A common stock is quoted on the OTCQB tier of the OTC Markets Group Inc. under the symbol “CHPE”. Although our Class A common stock is quoted on the OTCQB, there is currently no active public trading market of our Class A common stock and the market price of our Class A common stock may be difficult to ascertain. Our Class B common stock is not listed or quoted on the OTCQB or any other stock exchange or quotation system, and we have not applied for such listing. Further, in the event we were to seek such listing, there is no guarantee that any established securities exchange or quotation system would accept any of our Class B common stock for listing. As a result, investors in our securities may not be able to resell their shares at or above the purchase price paid by them or may not be able to resell them at all.

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